As Filed With the Securities and Exchange Commission on October 17, 2002.

Registration No. 333-            

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

SOUTHWEST ROYALTIES, INC.

AND THE ADDITIONAL REGISTRANT LISTED HEREIN

DELAWARE	1311	75-1917432
(State or Other Jurisdiction of Incorporation or Organization)	(Primary standard industrial classification code number)	(I.R.S. Employer Identification No.)

407 North Big Spring

Suite 300

Midland, Texas 79701

(915) 686-9927

(Address, including zip code, and telephone number, including area code,

of registrant’s principal executive offices)

H.H. Wommack, III

Southwest Royalties, Inc.

407 North Big Spring

Suite 300

Midland, Texas 79701

(915) 686-9927

(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies To:

Bill E. Coggin	J. Porter Durham, Jr., Esquire
Southwest Royalties, Inc.	Baker, Donelson,
407 North Big Spring	Bearman & Caldwell
Suite 300	1800 Republic Centre
Midland, Texas 79701	633 Chestnut Street
(915) 686-9927	Chattanooga, Tennessee 37450 (423) 756-2010

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this registration statement which relates to (i) the merger of limited partnerships with and into Southwest Consolidated Partnerships, Inc., a wholly-owned subsidiary of Southwest Royalties, Inc., and (ii) the subsequent merger of Southwest Consolidated Partnerships, Inc. into Southwest Managed Assets, Inc., a wholly-owned subsidiary of Southwest Royalties, Inc., pursuant to the merger agreements described in the enclosed proxy statement/prospectus.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.    ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered	Amount to be Registered (1)	Proposed Maximum Offering Price Per Share	Proposed Maximum Aggregate Offering Price (2)	Amount of Registration Fee (2)
Common Stock, $0.01 par value (3)	826,016	N/A	$10,000,000	$920
Series B Special Stock, $.01 par value	137,669	N/A	$2,500,000	$230

(1) Based upon the registrant’s estimate of the maximum number of shares that might be issued in connection with the proposed merger.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(f), based on the book value of the limited partner interests to be cancelled in the merger, computed as of the latest practicable date.

(3) Includes 137,669 shares of common stock that may be issued upon conversion of the Series B Special Stock registered herein.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

ADDITIONAL REGISTRANT

SOUTHWEST CONSOLIDATED PARTNERSHIPS, INC.

(Exact Name of Registrant as Specified in its Charter)

DELAWARE	1311	33-1026299
(State or Other Jurisdiction of	(Primary standard industrial	(I.R.S. Employer
Incorporation or Organization)	classification code number)	Identification No.)

407 North Big Spring

Suite 300

Midland, Texas 79701

(915) 686-9927

(Address, including zip code, and telephone number, including area code,

of registrant’s principal executive offices)

H.H. Wommack, III

Southwest Consolidated Partnerships, Inc.

407 North Big Spring

Suite 300

Midland, Texas 79701

(915) 686-9927

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies To:

Bill E. Coggin	J. Porter Durham, Jr., Esquire
Southwest Royalties, Inc.	Baker, Donelson,
407 North Big Spring	Bearman & Caldwell
Suite 300	1800 Republic Centre
Midland, Texas 79701	633 Chestnut Street
(915) 686-9927	Chattanooga, TN 37450 (423) 756-2010

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this registration statement which relates to (i) the merger of limited partnerships with and into Southwest Consolidated Partnerships, Inc., a wholly-owned subsidiary of Southwest Royalties, Inc., and (ii) the subsequent merger of Southwest Consolidated Partnerships, Inc. into Southwest Managed Assets, Inc., a wholly-owned subsidiary of Southwest Royalties, Inc., pursuant to the merger agreements described in the enclosed proxy statement/prospectus.

If the securities being registered on this form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

CALCULATION OF REGISTRATION FEE

Title Of Each Class Of Securities To Be Registered	Amount To Be Registered (1)	Proposed Maximum Offering Price Per Share	Proposed Maximum Aggregate Offering Price (2)		Amount Of Registration Fee (2)
Common Stock, $0.01 par value	10,000	N/A	$	1,000,000	$	92

⁽¹⁾ Based upon the registrant’s estimate of the maximum number of shares that might be issued in connection with the proposed merger.

⁽²⁾ Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(f), based on the book value of the limited partner interests to be cancelled in the merger, computed as of the latest practicable date.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

SUBJECT TO COMPLETION                     , 2002

PROSPECTUS/PROXY STATEMENT

SOUTHWEST ROYALTIES, INC.

Southwest Royalties, Inc. (“Southwest”) proposes the adoption of a plan of merger of 21 limited partnerships in which Southwest serves as general partner and which consist of:

Southwest Royalties, Inc. Income Fund V, L.P. Southwest Royalties, Inc. Income Fund VI, L.P. Southwest Oil & Gas Income Fund VII-A, L.P. Southwest Royalties Institutional Income Fund VII-B, L.P. Southwest Oil & Gas Income Fund VIII-A, L.P. Southwest Royalties Institutional Income Fund VIII-B, L.P. Southwest Oil & Gas Income Fund IX-A, L.P. Southwest Royalties Institutional Income Fund IX-B, L.P. Southwest Oil & Gas Income Fund X-A, L.P. Southwest Royalties Institutional Income Fund X-A, L.P. Southwest Oil & Gas Income Fund X-B, L.P. Southwest Royalties Institutional Income Fund X-B, L.P. Southwest Oil & Gas Income Fund X-C, L.P. Southwest Royalties Institutional Income Fund X-C, L.P. Southwest Combination Income/Drilling Program 1988, L.P. Southwest Development Drilling Fund 1990, L.P. Southwest Developmental Drilling Fund 91-A, L.P. Southwest Developmental Drilling Fund 92-A, L.P. Southwest Developmental Drilling Fund 1993, L.P. Southwest Developmental Drilling Fund 1994, L.P. Southwest Partners, L.P.

Pursuant to the plan of merger, the limited partnerships will merge with and into Southwest Consolidated Partnerships, Inc., a wholly-owned subsidiary of Southwest. Immediately thereafter, Southwest Consolidated Partnerships, Inc. will merge with and into Southwest Managed Assets, Inc., another wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as “the merger.”

We are asking the limited partners of each partnership to approve the merger. The merger must be approved by at least 75% of the outstanding limited partner interests of each partnership before that partnership will be able to participate in the merger. Limited partners who vote in favor of the merger of the partnerships into Southwest Consolidated Partnerships will provide a written consent, as prospective stockholders of Southwest Consolidated Partnerships, approving the subsequent merger of Southwest Consolidated Partnerships into Southwest Managed Assets.

The special meeting of the limited partners for each partnership will be jointly held             ,             , 2002, 10:00 a.m., Central Time at The Midland Hilton, 117 West Wall Street, Midland, Texas 79701.

The merger will not be consummated unless the limited partners of either Southwest Partners, L.P. or Southwest Royalties, Inc. Income Fund VI, L.P. approve the merger, Southwest receives the approval of its stockholders and certain other conditions are met.

If the merger is completed, the limited partners of each participating partnership will initially receive shares of Southwest Consolidated Partnerships common stock. Immediately thereafter, upon the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, former limited partners will receive shares of Southwest common stock in exchange for their Southwest Consolidated Partnerships common stock in proportion to the Merger Value of their former partnership relative to the total Merger Value of all participating partnerships and Southwest. The Merger Value is based primarily on the present value of estimated future net revenues from proved reserves of each partnership and Southwest, plus net working capital, minus long-term debt, plus the book value of any Additional Net Assets. The present value of estimated future net revenues from proved reserves was determined by Ryder Scott Company, L.P., an independent petroleum engineering and consulting firm, as of January 1, 2002 and updated to July 1, 2002 by our internal staff of engineers. The Merger Value, as calculated and presented herein, uses financial information for the period ended June 30, 2002 and reserve value for the period ended July 1, 2002. The Merger Value will be further adjusted at the time of the consummation of the merger, using the reserve values and financial statements updated to the month ending immediately preceding the month in which the merger becomes effective. In connection with the merger, we will issue shares of our special stock into an escrow account, which shares are intended to prevent the limited partners from being diluted under certain circumstances. See “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock To Be Issued in the Merger.”

The merger is expected to be tax-neutral to Southwest and to the limited partners. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES.”

Prior to the proposed merger, there has been no public market for our common stock. There is no assurance that the market value of the shares of our common stock to be distributed to the limited partners will bear any relationship to the Merger Value. The Merger Value is being used solely to determine the relative value of Southwest and each of the partnerships and may not represent the fair value of Southwest, the partnerships or their net assets.

We have applied to have our common stock listed on Nasdaq (National Market) under the symbol “SWRI” upon completion of the merger. The special stock to be issued into escrow in the merger will not be listed on any exchange or authorized for quotation on any inter-dealer quotation system. However, in the event the special stock converts into common stock and the common stock is thereafter distributed to the limited partners, those shares of common stock would be authorized for quotation on Nasdaq (National Market).

This prospectus/proxy statement is first being mailed to the limited partners of the partnerships on or about             , 2002.

This prospectus/proxy statement provides you with detailed information about the merger. Please read it carefully. In addition, you should carefully consider the risks relating to the merger described in “ RISK FACTORS” before voting in favor of the merger.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of our common stock or determined if this prospectus/proxy statement is truthful or complete. Any representation to the contrary is a criminal offense.

            , 2002

The information in this prospectus/proxy statement is not complete and may be changed. We may not sell these securities until the registration statement filed with the SEC is effective. This prospectus/proxy statement is not an offer to sell securities and is not soliciting an offer to buy securities in any state where such offer or sale is not permitted.

You should only rely on the information contained in this prospectus/proxy statement and the accompanying prospectus supplements. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus/proxy statement or the accompanying prospectus supplements is accurate as of any date other than the date on the front of those documents.

The offering involves risks, including the following:

• Limited partners will own common stock in a corporation rather than an interest in a limited partnership, resulting in material changes in the nature of their investment.

• Limited partners have received cash distributions from the partnerships but will receive no cash distributions or dividends in the foreseeable future from Southwest.

• You may be exchanging limited partner interests in a partnership that cannot incur indebtedness for shares of common stock in Southwest, which has a significant level of indebtedness.

• There has been no prior market for our common stock, and there is no assurance that a market will develop. The Merger Value assigned to your limited partner interests may be greater than the fair value of Southwest or its net assets, which means the shares of common stock you receive in Southwest may be worth less than your limited partner interests. The shares of common stock you receive in the merger may trade at prices substantially below the value ascribed to them by the Merger Value calculation. The Merger Value, which we believe to be a fair measure for allocating shares of our common stock to each partnership, should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

• Southwest determined the terms of the merger. The consideration to be received by the limited partners and Southwest, as the managing general partner, was calculated using an evaluation method which was also determined by Southwest. Accordingly, Southwest has an inherent conflict of interest as the managing general partner of the partnerships. Our Board of Directors has received an opinion from an investment bank that the Merger Value is fair to the limited partners and to Southwest, as the managing general partner of each partnership. However, the consideration may not reflect the value of the net assets of each partnership if sold to an unaffiliated third party in an arms length transaction.

• The Merger Values are based primarily on estimates of reserves and future net cash flows, which have inherent uncertainties. The assumptions and estimates we used to value the assets may turn out to have operated to the disadvantage of certain partnerships or to have been incorrect. Moreover, although we have discounted reserves according to the degree of risk associated with the production of such reserves, our formula for valuing the degree of risk of the reserves may prove to be an inaccurate measure. Merger Values may not represent fair market value.

• The alternatives of continuing partnership operations or liquidating partnership assets potentially could be more beneficial to limited partners than the merger.

• No independent representative was engaged to represent the limited partners in negotiating the terms of the merger, which may be inferior to those terms that could have been negotiated by an independent representative.

• The Internal Revenue Service may disagree with our characterization of the merger as being tax-neutral, and, accordingly, the merger may create a taxable event to the limited partners.

INFORMATION INCORPORATED BY REFERENCE

This prospectus/proxy statement incorporates important business and financial information about Southwest that is not included in or delivered with this document. This information is available without charge to you, as a limited partner of a partnership, upon written or oral request to Southwest Royalties, Inc., 407 North Big Spring, Midland, Texas 79701, Attention: B.J. Parrish. You may also request this information by calling 1-800-             or visiting our website for the merger at www.swrpartners.com. In order to ensure timely delivery of this information, you must request the information no later than              [date five business days before limited partners must vote on the merger.]

TABLE OF CONTENTS

WHERE YOU CAN FIND MORE INFORMATION	1
GLOSSARY OF OIL AND GAS TERMS	1
QUESTIONS AND ANSWERS	3
SUMMARY	8
Risk Factors	8
Southwest Royalties, Inc.	9
Strategy	11
The Partnerships	12
Southwest Consolidated Partnerships	12
Southwest Managed Assets	13
Merger Value	13
Example Calculation of Merger Value	21
Background and Reasons for the Merger	22
Merger of each Partnership	27
Meeting, Voting and Proxy Information	29
Federal Income Tax Considerations	30
RISK FACTORS	32
BUSINESS OF SOUTHWEST ROYALTIES, INC.	42
Our Company	42
Our Strategy	46
Our Principal Oil and Gas Properties	47
Our Oil and Gas Reserves	48
Net Production, Unit Prices and Costs	50
Producing Wells	50
Acreage	51
Drilling Activities	51
Our Principal Executive Offices	51
Customers	51
Legal Proceedings	51
Employees	52
Competition	52
Financial Information about Geographic Areas	52
Operating Hazards and Risks	52
Regulation	53
Market Price of and Dividends on our Common Stock and Related Stockholder Matters	55
Bondholder Consent	56
SUMMARY HISTORICAL FINANCIAL DATA OF SOUTHWEST	57
Selected Operating Data	58
SUMMARY UNAUDITED PRO FORMA FINANCIAL INFORMATION OF SOUTHWEST	59
SUMMARY OIL AND GAS RESERVE INFORMATION	61
COMPARATIVE PER SHARE DATA	62
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF SOUTHWEST	65
General	65
Critical Accounting Policies	65
Results of Operations	66
Liquidity and Capital Resources	70
Other Issues	73
Recent Accounting Pronouncements	74

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	74
Quantitative Disclosures	74
Qualitative Disclosures	77
THE PARTNERSHIPS	77
General	77
Business	80
Market for the Partnerships’ Limited Partner Interests and Related Partnership Matters	83
SOUTHWEST CONSOLIDATED PARTNERSHIPS	84
General	84
Business	84
SOUTHWEST MANAGED ASSETS	84
General	84
Business	84
BACKGROUND AND REASONS FOR THE MERGER	85
Overview	85
Background of the Merger	89
Benefits of the Merger to the Limited Partners	91
Disadvantages of the Merger to the Limited Partners	93
Reasons for the Structure of the Merger	93
Reasons for the Timing of the Merger	93
Alternatives to the Merger	94
Fairness of the Merger	95
FORWARD LOOKING STATEMENTS	106
METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED	107
Summary Reserve Report and Qualifications and Method of Selection	107
Components and Method of Merger Value for each Partnership	107
Other Methods of Determining Merger Value	110
MERGER OF EACH PARTNERSHIP	111
General	111
No Continuing Interest in the Partnerships	111
Fractional Shares	112
Future of a Partnership that does not Participate in the Merger	112
Termination of Registration and Reporting Requirements of Certain Partnerships	112
Conditions to Consummation of the Merger	113
Accounting Treatment	113
Expenses and Fees and Source of Funds	114
Regulatory Requirements	114
Nasdaq Listing	114
Appraisal Rights	114
Access to Books and Records and Separate Counsel	114
Limited Partner Lists for each Partnership	114
MERGER AGREEMENT	115
Structure; Effective Time	115
Effect of the Merger of each Partnership	115
Conduct of Business Prior to the Merger of each Partnership	115
Other Provisions	116
Conditions to the Merger of each Partnership into Southwest Consolidated Partnerships	117
Conditions to the Merger of Southwest Consolidated Partnerships into Southwest Managed Assets	117
Termination of the First-Step Merger Agreement and the Merger of Any Partnership into Southwest Consolidated Partnerships	118
Amendments and Waivers of First-Step Merger Agreement	119

Termination of the Second-Step Merger Agreement and the Merger of Southwest Consolidated Partnerships into Southwest Managed Assets	119
Amendments and Waivers of Second-Step Merger Agreement	120
MEETING, VOTING AND PROXY INFORMATION	121
General	121
Meeting	121
Amendments to the Partnership Agreements	121
Record Date	121
Vote Required for Approval	121
Voting	123
Solicitation of Proxies	124
Approval of the Merger by Stockholders of Southwest	125
MANAGEMENT OF SOUTHWEST	125
Executive Compensation	128
Agreements with Executive Officers	128
Board Compensation	130
Compensation Decisions	130
Compensation Committee Interlocks and Insider Participation	130
MANAGEMENT OF SOUTHWEST CONSOLIDATED PARTNERSHIPS AND SOUTHWEST MANAGED ASSETS	130
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	131
PRINCIPAL STOCKHOLDERS OF SOUTHWEST	131
STOCK OWNERSHIP OF SOUTHWEST MANAGEMENT	135
DESCRIPTION OF OUR CAPITAL STOCK	139
General	139
Common Stock	139
Class A Common Stock	139
Series A Special Stock Held by SRH	140
Series B Special Stock To Be Issued in the Merger	141
Preferred Stock	141
Board Representation	141
Stockholders Agreement	142
Limitation on Director’s Liability and Indemnification of Directors	142
Transfer Agent and Registrar	143
Anti-Takeover Effect of Delaware Law and our Amended and Restated Certificate of Incorporation and By-Law Provisions	143
DESCRIPTION OF CAPITAL STOCK OF SOUTHWEST CONSOLIDATED PARTNERSHIPS	144
General	144
Limitation on Director’s Liability	144
COMPARISON OF RIGHTS OF SOUTHWEST STOCKHOLDERS AND THE PARTNERSHIPS’ LIMITED PARTNERS	145
General	145
Distribution and Dividends	145
Terms of Conversion and Redemption	147
Voting Rights	147
Liquidation Rights	147
Assessments and Limited Liability	150
Right of Presentment; Right of First Refusal	150
Transferability	151
Statutory Anti-Takeover Provisions	151
Management	151

Continuity of Existence	152
Taxation	153
Financial Reporting	153
Meetings and Proposals	153
Indemnification	154
Fiduciary Duty	154
Mergers	155
Appraisal Rights	155
Books and Records	155
Compensation	156
Investment Policy	156
Compensation and Distribution History	157
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES	157
ERISA CONSIDERATIONS	160
LEGAL OPINIONS	161

EXPERTS	161
FUTURE SHAREHOLDER PROPOSALS	162
INDEX TO FINANCIAL STATEMENTS	F-1
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS	P-1

LIST OF APPENDICES

Appendix A: General Information Relating to each Partnership

Table 1—Jurisdiction of Organization, Initial Subscription Price for each Unit, Initial Investment by Limited Partners and Number of Limited Partners as of June 30, 2002

Table 2—Aggregate Merger Value Attributable to Southwest’s General Partner Interest, to Southwest’s Limited Partner Interest and to the Interests of the Other Limited Partners of each Partnership

Table 3—Merger Value Attributable to Partnership Interests of Limited Partners Per $500 Investment

Table 4—Voting Percentage of Southwest in Its Capacity as a Limited Partner and General Partner Interest of Southwest as of June 30, 2002

Table 5—Historical Quarterly Partnership Distributions to the Limited Partners per $500 Investment from Inception Through June 30, 2002

Appendix B: Reserve Reports of Ryder Scott Company, L.P. dated March 5, 2001

B1	Southwest Royalties, Inc.
B2	Southwest Royalties, Inc. Income Fund V, L.P.
B3	Southwest Royalties, Inc. Income Fund VI, L.P.
B4	Southwest Oil & Gas Income Fund VII-A, L.P.
B5	Southwest Royalties Institutional Income Fund VII-B, L.P.
B6	Southwest Oil & Gas Income Fund VIII-A, L.P.
B7	Southwest Royalties Institutional Income Fund VIII-B, L.P.
B8	Southwest Oil & Gas Income Fund IX-A, L.P.
B9	Southwest Royalties Institutional Income Fund IX-B, L.P.
B10	Southwest Oil & Gas Income Fund X-A, L.P.
B11	Southwest Royalties Institutional Income Fund X-A, L.P.
B12	Southwest Oil & Gas Income Fund X-B, L.P.
B13	Southwest Royalties Institutional Income Fund X-B, L.P.
B14	Southwest Oil & Gas Income Fund X-C, L.P.
B15	Southwest Royalties Institutional Income Fund X-C, L.P.
B16	Southwest Combination Income/Drilling Program 1988, L.P.
B17	Southwest Developmental Drilling Fund 1990, L.P.
B18	Southwest Developmental Drilling Fund 91-A, L.P.
B19	Southwest Developmental Drilling Fund 92-A, L.P.
B20	Southwest Developmental Drilling Fund 1993, L.P.
B21	Southwest Developmental Drilling Fund 1994, L.P.
B22	Southwest Partners, L.P.
B22(a)	Tex-Hal Partners, a wholly-owned subsidiary of Southwest Partners, L.P.

Appendix C: Form of Agreement and Plan of Merger Between the Limited Partnerships and Southwest Consolidated Partnerships

Appendix D: Form of Agreement and Plan of Merger Between Southwest Consolidated Partnerships and Southwest Managed Assets

Appendix E: Form of Fairness of Opinion of Friedman, Billings, Ramsey & Co., Inc.

WE HAVE PREPARED A SEPARATE SUPPLEMENT TO THIS PROSPECTUS/PROXY STATEMENT FOR EACH PARTNERSHIP. EACH SUPPLEMENT INCLUDES:

• MATERIAL RISKS ASSOCIATED WITH THE MERGER

• FAIRNESS OF THE MERGER

• MERGER VALUE FOR EACH PARTNERSHIP

• COMPENSATION AND DISTRIBUTIONS FROM EACH PARTNERSHIP

• A SUPPLEMENTAL INFORMATION TABLE CONTAINING:

-— THE AGGREGATE INITIAL INVESTMENT BY THE LIMITED PARTNERS

-— THE AGGREGATE HISTORICAL LIMITED PARTNER DISTRIBUTIONS THROUGH  JUNE 30, 2002

-— THE AGGREGATE MERGER VALUE ATTRIBUTABLE TO PARTNERSHIP INTERESTS OF LIMITED PARTNERS, INCLUDING SOUTHWEST

-— THE MERGER VALUE PER $500 LIMITED PARTNER INVESTMENT AS OF JUNE 30, 2002

-— THE MERGER VALUE PER $500 LIMITED PARTNER INVESTMENT AS A MULTIPLE OF DISTRIBUTIONS FOR THE TWELVE MONTHS ENDED JUNE 30, 2002

-— THE BOOK VALUE PER $500 LIMITED PARTNER INVESTMENT AS OF JUNE 30, 2002 AND AS OF DECEMBER 31, 2001

-— THE GOING CONCERN VALUE PER $500 LIMITED PARTNER INVESTMENT AS OF JUNE 30, 2002

-— THE LIQUIDATION VALUE PER $500 LIMITED PARTNER INVESTMENT AS OF  JUNE 30, 2002

-— THE FINAL PRESENTMENT VALUE PER $500 LIMITED PARTNER INVESTMENT AS OF JUNE 30, 2002

• SELECTED HISTORICAL FINANCIAL DATA FOR EACH PARTNERSHIP FOR THE FIVE YEARS ENDED DECEMBER 31, 2001 AND FOR THE SIX MONTHS ENDED JUNE 30, 2002 AND 2001

• MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR EACH PARTNERSHIP, FOR THE QUARTERS ENDED JUNE 30, 2002 AND 2001, FOR THE SIX MONTHS ENDED JUNE 30, 2002 AND 2001 AND FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999.

THE SUPPLEMENTS CONSTITUTE AN INTEGRAL PART OF THIS DOCUMENT FOR EACH PARTNERSHIP. PLEASE CAREFULLY READ ALL OF THE SUPPLEMENTS FOR THE PARTNERSHIPS IN WHICH YOU ARE A LIMITED PARTNER.

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

Notice of Joint Special Meeting of Limited Partners

to be Held             , 2002

To the Limited Partners of 21 Limited Partnerships:

This is a notice that a joint special meeting of the limited partners of each of the following 21 partnerships will be held at The Midland Hilton, 117 West Wall Street, Midland, Texas 79701 on             , 2002 at              a.m. Central Time (the “Special Meeting”):

Southwest Royalties, Inc. Income Fund V, L.P. Southwest Royalties, Inc. Income Fund VI, L.P. Southwest Oil & Gas Income Fund VII-A, L.P. Southwest Royalties Institutional Income Fund VII-B, L.P. Southwest Oil & Gas Income Fund VIII-A, L.P. Southwest Royalties Institutional Income Fund VIII-B, L.P. Southwest Oil & Gas Income Fund IX-A, L.P. Southwest Royalties Institutional Income Fund IX-B, L.P. Southwest Oil & Gas Income Fund X-A, L.P. Southwest Royalties Institutional Income Fund X-A, L.P. Southwest Oil & Gas Income Fund X-B, L.P. Southwest Royalties Institutional Income Fund X-B, L.P. Southwest Oil & Gas Income Fund X-C, L.P. Southwest Royalties Institutional Income Fund X-C, L.P. Southwest Combination Income/Drilling Program 1988, L.P. Southwest Developmental Drilling Fund 1990, L.P. Southwest Developmental Drilling Fund 91-A, L.P. Southwest Developmental Drilling Fund 92-A, L.P. Southwest Developmental Drilling Fund 1993, L.P. Southwest Developmental Drilling Fund 1994, L.P. Southwest Partners, L.P.

(collectively, the “Partnerships”).

Southwest Royalties, Inc., a Delaware corporation (“Southwest”), sponsored each of the partnerships. Southwest is the managing general partner of each of the partnerships.

At the Special Meeting, the limited partners of each of the Partnerships will:

• consider and vote upon the adoption of (a) plans of merger pursuant to which (1) each of the Partnerships will merge with Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest and, immediately thereafter, (2) Southwest Consolidated Partnerships will merge with Southwest Managed Assets, another wholly-owned subsidiary of Southwest, pursuant to which limited partners will ultimately receive shares of Southwest common stock in exchange for their limited partner interests in the Partnerships; and (b) an amendment to the partnership agreement of each Partnership to permit the Partnership’s merger into Southwest’s subsidiary; and

• transact such other business that may properly come before the Special Meeting or any adjournments thereof.

Your attention is directed to the accompanying prospectus/proxy statement and prospectus supplement(s) which contain further information with respect to the proposals to be considered at the Special Meeting.

Only limited partners of record of one or more of the Partnerships at the close of business on             , 2002 are entitled to notice of and to vote at the Special Meeting or any postponements or adjournments thereof. Each Partnership’s approval of its plan of merger requires an affirmative vote by 75% of the outstanding limited partner interests of such Partnership. Please be aware that failing to cast a vote constitutes a vote against the merger. Information regarding voting and revocation of proxies is set forth under “MEETING, VOTING AND PROXY INFORMATION.”

WHETHER OR NOT YOU EXPECT TO BE PERSONALLY PRESENT AT THE SPECIAL MEETING, PLEASE BE SURE THAT YOU EITHER (1) PROPERLY COMPLETE, DATE, SIGN AND RETURN THE ENCLOSED PROXY AND LETTER OF TRANSMITTAL WITHOUT DELAY IN THE ENCLOSED ENVELOPE, (2) CAST YOUR VOTE BY TELEPHONE PROXY BY CALLING TOLL-FREE AT 1-800-             OR (3) VOTE YOUR PROXY VIA THE INTERNET AT WWW.            . PLEASE SEE THE BACK COVER OF THIS PROSPECTUS/PROXY STATEMENT FOR MORE INFORMATION ABOUT VOTING.

SOUTHWEST ROYALTIES, INC. Managing General Partner
By:
	H.H. Wommack, III, President and Chief Executive Officer

Midland, Texas

                        , 2002

WHERE YOU CAN FIND MORE INFORMATION

Each of the following partnerships, which we call reporting partnerships, file annual, quarterly and special reports, and other information, with the Securities and Exchange Commission (the “SEC”): Southwest Royalties, Inc. Income Fund V, L.P., Southwest Royalties, Inc. Income Fund VI, L.P., Southwest Oil & Gas Income Fund VII-A, L.P., Southwest Royalties Institutional Income Fund VII-B, L.P., Southwest Oil & Gas Income Fund VIII-A, L.P., Southwest Royalties Institutional Income Fund VIII-B, L.P., Southwest Oil & Gas Income Fund IX-A, L.P., Southwest Royalties Institutional Income Fund IX-B, L.P., Southwest Oil & Gas Income Fund X-A, L.P., Southwest Royalties Institutional Income Fund X-A, L.P., Southwest Oil & Gas Income Fund X-B, L.P., Southwest Royalties Institutional Income Fund X-B, L.P., Southwest Oil & Gas Income Fund X-C, L.P., Southwest Royalties Institutional Income Fund X-C, L.P., Southwest Developmental Drilling Fund 91-A, L.P. and Southwest Developmental Drilling Fund 92-A, L.P.

Until March 18, 2002, we filed annual, quarterly and special reports with the SEC. In addition, this prospectus/proxy statement is part of a registration statement we filed with the SEC. Not all of the information contained in that registration statement has been included in or delivered with this prospectus/proxy statement. You may read and copy any document we have filed with the SEC at the SEC’s public reference facilities at 450 Fifth Street, N.W., Washington, DC 20549. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 450 Fifth Street, N.W. Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. The full registration statement, the reporting partnerships’ filings and our other SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may visit our website at  http://www.swrinc.com. You may also visit the partnerships’ website at http://www.swrpartners.com, which website contains information about the merger. These websites are not part of this prospectus/proxy statement.

GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this prospectus/proxy statement. All volumes of natural gas referred to herein are stated at the legal pressure base to the state or area where the reserves exit and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl.    One stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf.    Billion cubic feet.

Boe.    Barrel of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

Boepd.    Barrels of oil equivalent per day.

Bopd.    Barrels of oil per day.

Completion.    The installation of permanent equipment for the production of oil and natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developmental well.    A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well.    A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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Exploratory well.    A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells.    The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling.    A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and can result in both increased production rates and greater ultimate recoveries of hydrocarbons.

MBbls.    One thousand barrels.

MBoe.    One thousand barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

Mcf.    One thousand cubic feet.

Mcfd.    One thousand cubic feet per day.

MMBbls.    One million barrels of crude oil or other liquid hydrocarbons.

MMBoe.    One million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

MMcf.    One million cubic feet.

Net acres or net wells.    The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGL.    Natural Gas Liquids. The liquid hydrocarbons that can be extracted from natural gas containing condensate and/or other hydrocarbons such as propane and butane.

Oil.    Crude oil, condensate and natural gas liquids.

Present value and PV-10 Value.    When used with respect to oil and natural gas reserves, the estimated future net revenue to be generated from the production of proved reserves, determined in all material respects in accordance with the rules and regulations of the SEC (generally using prices and costs in effect as of the date indicated) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Productive well.    A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed producing reserves.    Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.

Proved developed reserves.    Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.

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Proved reserves.    The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped location.    A site on which a developmental well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves.    Proved reserves that are expected to be recovered from new wells on undrilled acreage.

Recompletion.    The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.

Reserve life.    A ratio determined by dividing the existing reserves by production from such reserves for the prior 12-month period.

Reservoir.    A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Royalty interest.    An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

Undeveloped acreage.    Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore.    The hole drilled by the bit.

Working interest.    The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover.    Operations on a producing well to restore or increase production.

QUESTIONS AND ANSWERS

About the Merger

Q:    What is being proposed?

A:    We are proposing to merge 16 public and 5 private partnerships of which we are the managing general partner into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest. Immediately thereafter, Southwest Consolidated Partnerships will merge with and into Southwest Managed Assets, another wholly-owned subsidiary of Southwest.

Q:    What will I receive as a result of the merger?

A:    Limited partners will ultimately receive shares of our common stock based on the relative value of their ownership interest in their partnership compared to the combined value of Southwest and all partnerships that participate in the merger. We will also issue shares of our special stock into an escrow account, which shares are intended to prevent the limited partners from being diluted under certain circumstances. See “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger.” The method of determining the

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merger value of each partnership is described in “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED.” Although we will not receive shares of common stock for any partnership interests that we own in the partnerships, Merger Value will be attributable to our general partner interests and any limited partner interests that we hold in the partnerships. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED” for an explanation of how Merger Value will be attributed to our general partner interests.

Q:    Why is the merger being proposed?

A:    We believe that the merger is fair to and in the best interest of the limited partners. After the completion of the merger, limited partners should benefit from:

• a larger and more diversified asset base;

• the opportunity for future growth;

• liquidity for their investment;

• a reduction in administrative expenses; and

• simplification of tax reporting for the limited partners.

Q:    How is the relative value of each partnership determined?

A:    The relative value of each partnership is being determined primarily based on the present value of estimated future net revenues to be derived from its proved reserves. The value of each partnership also takes into consideration net working capital, long-term debt and the book value of any Additional Net Assets. The result of this determination is the Net Asset Value of each partnership. (For a definition of Additional Net Assets see “SUMMARY—Merger Value—Summary Table—Merger Value”).

Q:    What happens to my partnership cash distributions?

A:    The partnerships pay limited partners regular cash distributions if so available. You will continue to receive cash distributions until the SEC has declared our Registration Statement on S-4, of which this prospectus/proxy statement is a part, effective. Thereafter, any cash will accumulate to each partnership account and will be part of the working capital account used to determine the Adjusted Net Asset Value of each partnership in the month ending immediately preceding the month in which the merger becomes effective. In the event your partnership does not participate in the merger, any cash that has accumulated in the working capital account of such partnership will thereafter be distributed to you as per the terms of the partnership agreement of your partnership. (For a definition of “Adjusted Net Asset Value,” see “SUMMARY—Merger Value—Summary Table—Merger Value”). 

Upon the consummation of the merger, in the event your partnership merges into Southwest, you will receive no further cash distributions or dividends because we do not anticipate payment of dividends on our common stock in the near future.

Q:    What are the federal tax consequences of the merger?

A:    We believe that the merger of each partnership into Southwest’s subsidiary, Southwest Consolidated Partnerships, should be treated as a non-taxable transfer of assets from the partnerships to Southwest Consolidated Partnerships. Likewise, we believe that the merger of Southwest Consolidated Partnerships into Southwest Managed Assets should be treated as a non-taxable transfer of assets in return for the Southwest common stock held by Southwest Managed Assets, followed by an immediate distribution of the Southwest common stock to the former limited partners. If it is treated as such, the merger should be tax-neutral to the

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limited partners. There is a possibility, however, that the IRS may disagree with our characterization of the merger as a tax-neutral transaction. Accordingly, the merger may create a taxable event to the limited partners.

As a result of the merger, limited partners will become stockholders of Southwest; thus, you will no longer receive pass-through tax treatment currently available to limited partners. Additionally, you will no longer receive a Schedule K-1. You are strongly urged to consult your tax advisor concerning the federal, state and other tax consequences of the proposed merger.

Q:    Will I have dissenter’s rights in the merger?

A:    You are not entitled to appraisal or dissenters’ rights under the laws of the State of Delaware or the State of Tennessee, which are the states of formation of the partnerships. If the merger of a partnership in which you hold a limited partner interest is approved by 75% of the outstanding limited partner interests of your partnership, you will have no dissenter’s rights and will be bound by the merger, even if you vote against the merger.

Q:    There are several companies involved in the merger; which are important and why?

A:    Southwest Royalties, Inc. is the parent company of Southwest Consolidated Partnerships, Inc. and Southwest Managed Assets, Inc. and is the managing general partner of the 21 partnerships that we propose to include in the merger. Southwest will issue the common stock that the limited partners whose partnerships participate in the merger will ultimately receive.

Southwest Consolidated Partnerships, Inc. is a newly-formed, wholly-owned subsidiary of Southwest. Southwest Consolidated Partnerships is principally a conduit company; the partnerships will merge into Southwest Consolidated Partnerships and, immediately thereafter, Southwest Consolidated Partnerships will merge with and into Southwest Managed Assets. Limited partners will momentarily receive shares of common stock of Southwest Consolidated Partnerships, but upon the subsequent merger of Southwest Consolidated Partnerships into Southwest Managed Assets, former limited partners will receive shares of common stock of Southwest Royalties, Inc.

Southwest Managed Assets, Inc. is a newly-formed, wholly-owned subsidiary of Southwest. Southwest will issue shares of common stock to Southwest Managed Assets, which will thereafter distribute those shares of common stock to the former limited partners upon the merger of Southwest Consolidated Partnerships into Southwest Managed Assets. Upon the completion of the merger, former limited partners will own shares of Southwest common stock and Southwest Managed Assets will continue to be a wholly-owned subsidiary of Southwest.

See the diagrams in “BACKGROUND AND REASONS FOR THE MERGER.”

About the Meeting

Q:    What do I need to do now?

A:    After carefully considering the enclosed information, please indicate how you want to vote and sign and return your proxy in the enclosed envelope as soon as possible. You may instead vote via telephone by calling 1-800-             or on the Internet at www.             prior to the meeting. You may also attend the special meeting and vote in person. You should also complete the enclosed letter of transmittal so that your shares of common stock will be issued promptly after the closing of the merger.

Q:    What vote is required to approve the merger?

A:    The approval of limited partners holding 75% of the outstanding limited partner interests of each partnership is required to approve the merger. The merger will not be consummated unless the limited partners of

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either Southwest Royalties, Inc. Income Fund VI, L.P. or Southwest Partners, L.P. approve the merger. We are requiring a 75% approval for each partnership in order to comply with the Rules of the NASD, which compliance is necessary in order for our shares of common stock to be authorized for quotation on Nasdaq (National Market).

Abstentions and failures to vote will have the effect of a vote against the merger. Brokers, if any, who hold limited partner interests of a partnership in street name for customers have the authority to vote on “routine” proposals when they have not received instructions from beneficial owners. These brokers, however, are precluded from exercising their voting discretion with respect to the approval and adoption of non-routine matters such as the merger and thus, absent specific instructions from the beneficial owner of the limited partner interests, brokers are not empowered to vote the limited partner interests with respect to the merger. These “broker non-votes” will have the effect of a vote against the merger.

Q:    How do I vote my limited partner interest?

A:    Each limited partner interest in a partnership that is outstanding on             , 2002 is entitled to notice of and to vote at the special meeting. You may vote your limited partner interest in any of four ways:

(1) Voting by Mail.    If you choose to vote by mail, simply mark your proxy, date and sign it, and return it in the postage-paid envelope provided.

(2) Voting by Telephone.    You can vote your limited partner interests by telephone proxy by calling  1-800-            . Telephone voting is available 24 hours a day.

(3) Voting by Internet.    You can vote your proxy via the Internet at www.            . The website for Internet voting is available 24 hours a day.

(4) Voting in Person.    You can vote by appearing and voting in person at the special meeting.

If you vote your proxy by telephone or via the Internet you should not return your proxy card. Instructions on how to vote by telephone or via the Internet are located in “MEETING, VOTING AND PROXY INFORMATION” and on the proxy card attached to this prospectus/proxy statement. The accompanying proxy card is for your use if you are unable to attend the special meeting in person and if you do not wish to vote your proxy via telephone or the Internet. You may also vote by telephone, via the Internet or by proxy card if you are able to attend the special meeting but do not wish to vote in person. If you choose to vote by proxy card, you should specify your choices with regard to the proposal on the enclosed proxy card. The proxy cards that the holders of limited partner interests properly complete, date, sign and return, as well as the votes they cast by telephone or via the Internet, will serve as voting instructions to their trustee to vote those limited partner interests at the special meeting as directed. Please vote by telephone, via the Internet or properly complete, sign and date the proxy card and return it in the enclosed postage-paid envelope.

Q:    What happens if I do not return a proxy card, vote via telephone or the Internet or attend the special meeting and vote in person?

A:    Failing to return your proxy card or to vote via telephone or the Internet or to attend the special meeting and vote in person will have the same effect as voting against the merger for each partnership in which you own a limited partner interest.

Q:    May I change my vote or revoke my proxy?

A:    Yes. Just send in a later-dated, signed proxy card to the proxy tabulator, as set forth in “MEETING, VOTING AND PROXY INFORMATION” and on the back cover of this prospectus/proxy statement, or vote again by telephone at 1-800-             or on the Internet at www.             before the special meeting. You can also

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attend the meeting in person and vote, although attendance at the meeting by itself will not by itself revoke a previously granted proxy. You may also revoke your proxy by sending a notice of revocation to the proxy tabulator, or by telephone at 1-800-             or over the Internet at www.            . You can find further details on how to revoke your proxy in “MEETING, VOTING AND PROXY INFORMATION” and on the back cover of this prospectus/proxy statement.

Q:    Should I send in any documentation with respect to my limited partner interests now?

A:    No.    If the merger of a partnership in which you own a limited partner interest is completed, your limited partner interests in that partnership will automatically be canceled. We will mail certificates representing Southwest common stock issued to you on completion of the merger of that partnership.

Q:    Who can help answer my questions?

A:    If you have any questions about the merger of any of the partnerships in which you own an interest, please call B.J. Parrish from Southwest at 1-800-               , or our information agent, D.F. King & Co., Inc. at 1-800-            . You may also access information regarding the merger by visiting our website at www.swrpartners.com.

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SUMMARY

This summary contains basic information about the merger, our business and operations, and the partnerships. It probably does not contain all of the information that is important to you. For a more complete understanding, we encourage you to read this entire document, including the financial data and related notes, the appendices, the supplements for the partnerships in which you hold limited partner interests and the documents we have referenced. The terms “we,” “our,” and “us,” as used in this prospectus/proxy statement, refer to Southwest Royalties, Inc. Certain terms used in this prospectus/proxy statement are defined under the section “GLOSSARY OF OIL AND GAS TERMS.”

Risk Factors

Before voting in favor of the merger, you should carefully consider the risks associated with the merger, in addition to the other information included in this prospectus/proxy statement. Some of the risk factors associated with the merger are summarized below and described in more detail under the caption “RISK FACTORS.”

• Limited partners will own common stock in a corporation rather than an interest in a limited partnership, resulting in material changes in the nature of their investment.

• Limited partners have received cash distributions from the partnerships but will receive no cash distributions or dividends in the foreseeable future from Southwest.

• You may be exchanging limited partner interests in a partnership that cannot incur indebtedness for shares of common stock in Southwest, which has a significant level of indebtedness.

• There has been no prior market for our common stock and there is no assurance that a market will develop. The Merger Value assigned to your limited partner interests may be greater than the fair value of Southwest or its net assets, which means the shares of common stock you receive in Southwest may be worth less than your limited partner interests. The shares of common stock you receive in the merger may trade at prices substantially below the value ascribed to them by the merger value calculation. The Merger Value, which we believe to be a fair measure for allocating shares of our common stock to each partnership, should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

• Southwest determined the terms of the merger. The consideration to be received by the limited partners and Southwest, as the managing general partner, was calculated using an evaluation method which was also determined by Southwest. Accordingly, Southwest has an inherent conflict of interest as the managing general partner of the partnerships. Our Board of Directors has received an opinion from an investment bank that the Merger Value is fair to the limited partners and to Southwest, as the managing general partner of each partnership. However, consideration may not reflect the value of the net assets of each partnership if sold to an unaffiliated third party in an arms length transaction.

• The Merger Values are based primarily on estimates of reserves and future net cash flows, which have inherent uncertainties. The assumptions and estimates we used to value the assets may turn out to have operated to the disadvantage of certain partnerships or to have been incorrect. Moreover, although we have discounted reserves according to the degree of risk associated with the production of such reserves, our formula for valuing the degree of risk of the reserves may prove to be an inaccurate measure. Merger Values may not represent fair market value.

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• The alternatives of continuing partnership operations or liquidating partnership assets potentially could be more beneficial to limited partners than the merger.

• No independent representative was engaged to represent the limited partners in negotiating the terms of the merger, which may be inferior to those terms that could have been negotiated by an independent representative.

• The IRS may disagree with our characterization of the merger as being tax-neutral, and, accordingly, the merger may create a taxable event to the limited partners.

Southwest Royalties, Inc.

Background

Formed in 1983 as a Delaware corporation, we are an independent oil and gas company engaged in the acquisition, drilling, development and production of oil and gas properties. Our primary operations are in the Permian Basin, where approximately 95% of our properties and wells are located. We have grown primarily through selective acquisitions of producing oil and gas properties, drilling and development, both directly and through the partnerships we manage. Our oil and gas properties exhibit long-lived production and multiple pay intervals. Our history of operations in the Permian Basin provides us with operational and strategic competitive advantages, as well as growth opportunities.

We initially financed the acquisition of oil and gas reserves and our exploration and development efforts through public and private limited partnership offerings. We are a general partner of these limited partnerships, own interests in these partnerships and receive management fees and operating cost reimbursements from these partnerships. Since 1983, we have completed over $250.0 million of oil and gas property acquisitions, both directly and through the limited partnerships we manage. As of July 1, 2002, we had total estimated net proved reserves of 20.5 MMBbls of oil and 78.0 Bcf of natural gas, aggregating 33.5 MMBoe, with a PV-10 Value of $220.0 million. The reserve estimates at July 1, 2002 assume a New York Mercantile Exchange (“NYMEX”) oil price of $26.86 per Bbl with an average adjusted price, reflecting adjustments for oil quality and gathering and transportation costs, of $25.04 per Bbl and a NYMEX gas price of $3.25 per Mcf with an average adjusted price, reflecting adjustments for BTU content, gathering and transportation costs and gas processing and shrinkage, of $2.97 per Mcf.

Our proved reserves have the following characteristics:

• the half-life of our reserves is approximately 8 years;

• our R/P (reserve total divided by production rate) is 16 to 18 years; and

• classification of reserves as of July 1, 2002 based upon PV-10 Value:

60.3% is proved developed producing;

10.5% is proved developed non-producing; and

29.2% is proved undeveloped.

As shown above, our development projects are located primarily in shallow to intermediate depth (normally pressured reservoirs), resulting in moderate drilling and completion costs. Many of these development projects contain multiple producing oil and gas horizons that are potentially productive, further reducing developmental drilling risk. As a result of our history of acquiring oil and gas properties, we have a significant inventory of potential drilling opportunities. Our inventory of non-producing reserves, which is primarily located in the Permian Basin, gives us development growth potential in a geographic area where we currently operate most of our properties and, therefore, have expertise.

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As of September 30, 2002, we had only one subsidiary, Blue Heel Company. Blue Heel Company holds a nominal interest in certain oil and gas properties owned by Southwest. In connection with the merger, we have formed two wholly-owned subsidiaries, Southwest Consolidated Partnerships and Southwest Managed Assets.

Our Principal Executive Offices

Our principal executive offices are located at 407 North Big Spring, Suite 300, Midland, Texas, 79701 and our telephone number is (915) 686-9927. Our website is located at www.swrinc.com. Information contained on our website is not part of this prospectus.

Potential Acquisitions

Major and large independent oil and gas companies have generally decided to focus their operations in geographic areas other than the Permian Basin in order to explore more significant reserve opportunities found off-shore or in foreign countries or they have consolidated with companies outside the Permian Basin. Continued consolidation in the oil and gas industry provides potential acquisition opportunities for Southwest in the Permian Basin. As a result of our past history of acquiring properties, we have established a network to take advantage of acquisition opportunities. We also have significant experience in the assimilation of both large and small oil and gas properties and companies.

Repurchase of our 10½% Senior Notes

On October 15, 1997, we completed a $200.0 million private placement of 10½% Senior Notes due 2004, Series A, which were offered and sold by underwriters only to qualified institutional buyers. On March 11, 1998, we concluded a registered offering to exchange the Series A Notes for 10½% Senior Notes due 2004, Series B, which had been registered under the Securities Act of 1933, as amended (the “Securities Act”). The form and terms of the Series B Notes were identical in all material respects to the form and terms of the Series A Notes.

On March 5, 2002, we commenced an offer for $123.685 million aggregate principal amount of those 10½% Senior Notes, which represented all of the 10½% Senior Notes then outstanding, plus any interest accrued but not paid thereon, in exchange for approximately $60.0 million in principal amount of Senior Secured Notes due 2004 and 900,000 shares of our Class A common stock. On April 19, 2002, our offer to exchange the 10½% Senior Notes expired, with holders of $114.815 million in principal amount of the 10½% Senior Notes tendering in exchange for the Senior Secured Notes and Class A common stock. As of September 30, 2002, $8.87 million in aggregate principal amount of the 10½% Senior Notes remained outstanding.

The Merger

The merger adds significant existing production and cash flow to our operations, as well as a substantial inventory of development projects. The partnerships’ projects are generally in the same or adjacent oil and gas fields as our oil and gas properties.

As a result of restrictions imposed by most of the partnership agreements, we have been unable to exploit developmental opportunities on the partnerships’ properties for the last 15 years, resulting in a build-up of potential projects. We have identified numerous opportunities for development of the partnerships’ properties.

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At July 1, 2002, our oil and gas properties had the following characteristics, with and without the merger:

	Southwest	Southwest upon completion in the merger (assuming participation by all 21 partnerships)
Interests Owned	133,725 net leasehold acres	154,400 net leasehold acres
Estimated Proved Reserves
Crude Oil	20.5 MMBbls	23.8 MMBbls
Natural Gas	78.0 Bcf	93.5 Bcf
Total Equivalent	33.5 MMBoe	39.4 MMBoe
PV-10 Value	$220.0 million	$256.7 million
Proved Developed Reserves
% of PV-10 Value	70.8%	72.3%

Strategy

Our objective is to increase our revenues, cash flow, earnings and reserves through the efficient development and exploitation of our inventory of projects and continued oil and gas property acquisitions in the Permian Basin.

Develop and exploit existing oil and gas properties

• We have a diversified portfolio of oil and gas properties that contain numerous identified development opportunities.

• We believe that current oil and gas prices have improved the attractiveness of accelerated development of these properties. We plan to increase our capital spending during the remainder of 2002 and in 2003 to pursue these opportunities, which consist principally of infill drilling, recompletions, enhanced recovery operations and workover opportunities.

• The partnership agreements of the partnerships do not allow for meaningful exploratory or developmental drilling. The merger and the resulting termination of the partnership agreements will allow for the full exploitation of the partnerships’ undeveloped assets.

Acquire producing oil and gas properties

• We will focus on acquisitions that provide opportunities for the addition of reserves, production and cash flow through operational improvements, production enhancement and additional development. We believe properties meeting these criteria are available in the Permian Basin due to the region’s long history of production and multiple producing oil and gas horizons.

• Major and large independent oil and gas companies have decided to focus their operations in geographic areas other than the Permian Basin in order to explore more significant reserve opportunities found off-shore or in foreign countries or they have consolidated with companies outside the Permian Basin. Additionally, limited access to liquidity through the capital markets and reduced availability on commercial bank lines have resulted in an increase in attractive acquisition opportunities offered by independent oil and gas companies seeking additional liquidity. We intend to pursue these acquisition opportunities.

Maintain Operations and Cost Controls

• Our oil and gas activities are located in the Permian Basin, with properties in this region representing 93% of our PV-10 Value at July 1, 2002. Our focus on the Permian Basin allows us to build upon our region-specific geological, engineering and production experience.

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• We operated 71% of our PV-10 Value as of July 1, 2002. Our significant control of operations and geographic focus have resulted in substantial operating economies of scale that have enabled us to maintain a low cost structure.

The Partnerships

The partnerships that we propose to include in the merger consist of institutional income funds, oil and gas income funds, developmental drilling funds, a combination income/drilling fund and an investment fund. The principal executive office for all of the partnerships is located at 407 North Big Spring, Suite 300, Midland, Texas 79701 and the telephone number is (915) 686-9927. The businesses of the partnerships are summarized below.

Income Funds.    The partnerships which are designated as oil and gas income funds own producing oil and gas properties located primarily in the Permian Basin. The partnerships which are designated as institutional income funds own and hold non-operating interests, such as royalties, overriding royalties, and net profits interests in producing oil and gas properties. In general, the activities of the income funds are limited to purchasing, holding and disposing of, by sale or exchange, producing properties, or interests in producing properties, and producing and marketing crude oil and natural gas. The income funds are specifically prohibited under their partnership agreements from engaging in exploratory or developmental drilling and incurring indebtedness of any kind (other than trade payables in the normal course of business).

Developmental Drilling Funds and Combination Income/Drilling Fund.    The partnerships which are designated as developmental drilling funds were formed to engage primarily in drilling, development and exploration of oil and natural gas properties in the Permian Basin. The partnership which is designated as a combination income/drilling fund combines the objectives of an income program and drilling program. Both types of partnerships own producing oil and gas properties located in the Permian Basin and engaged in drilling developmental and exploratory wells. All drilling activity by the drilling funds ceased upon use of designated partnership funds. The partnerships are now limited to producing and marketing the oil and gas derived from their drilling activities. The drilling funds are specifically prohibited from engaging in off-shore drilling and incurring indebtedness of any kind (other than trade payables in the normal course of business).

Investment Fund.    The partnership designated as an investment fund was formed to acquire or invest in mid-market oil and gas companies. Acquisition purchase prices and amounts to be invested were to range from $1.0 million to $50.0 million. In addition, the investment fund could purchase direct interests in oil and gas properties and drill developmental and exploratory wells. Unlike the other partnerships, the investment fund can incur indebtedness and currently has outstanding bank debt.

Southwest Consolidated Partnerships

Southwest Consolidated Partnerships is a Delaware corporation and a wholly-owned subsidiary of Southwest. Southwest Consolidated Partnerships holds no assets and has no liabilities. The partnerships will merge with and into Southwest Consolidated Partnerships, and limited partners will receive shares of Southwest Consolidated Partnerships common stock in exchange for their limited partner interests. Upon consummation of the merger of the partnerships with and into Southwest Consolidated Partnerships, limited partners will own 100% of Southwest Consolidated Partnerships. Immediately thereafter, Southwest Consolidated Partnerships will merge with and into Southwest Managed Assets, another wholly-owned subsidiary of Southwest, and Southwest Consolidated Partnerships will cease to exist. Shares of Southwest Consolidated Partnerships common stock beneficially owned by the former limited partners will automatically be exchanged for shares of our common

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stock. Limited partners who vote in favor of the merger of their partnership with and into Southwest Consolidated Partnerships will also execute a written consent (effective immediately upon the merger of the partnerships into Southwest Consolidated Partnerships) to approve the subsequent merger of Southwest Consolidated Partnerships into Southwest Managed Assets. See “SUMMARY—Southwest Managed Assets” below for a description of Southwest Managed Assets and the merger of Southwest Consolidated Partnerships into Southwest Managed Assets.

Southwest Managed Assets

Southwest Managed Assets is a Delaware corporation and a wholly-owned subsidiary of Southwest. Prior to the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, Southwest will transfer to Southwest Managed Assets 688,347 shares of our common stock (assuming all 21 partnerships participate in the merger). Southwest Managed Assets has no liabilities, and its only asset will be the shares of our common stock that it will hold prior to the merger. Upon the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, stockholders of Southwest Consolidated Partnerships, which are the former limited partners of the partnerships participating in the merger, will receive shares of our common stock in exchange for their Southwest Consolidated Partnerships common stock. Upon the consummation of the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, Southwest Consolidated Partnerships will cease to exist. The former limited partners will hold shares of our common stock and Southwest Managed Assets will remain a wholly-owned subsidiary of Southwest. Southwest Managed Assets’ assets will consist of the assets of the partnerships that participate in the merger.

Merger Value

Summary Table—Merger Value

Set forth below is the estimated dollar value for the general and limited partner interests of the partnerships that we propose to include in the merger (the “Merger Value”) and the aggregate number of shares of Southwest common stock to be issued in connection with the merger. Please note, however, that the Merger Value will be recalculated on the effective date of the merger using an adjusted net asset value (“Adjusted Net Asset Value”) consisting of (1) revised proved reserves and future net revenues determined by adjusting the report prepared by an independent petroleum engineering firm, Ryder Scott Company, L.P., forward to the month ending immediately preceding the month in which the merger becomes effective and (2) revised net working capital, long-term debt and any assets other than current assets (excluding tangible and deferred assets) (“Additional Net Assets”) derived from financial statements (prepared by Southwest in accordance with generally accepted accounting principles (“GAAP”)) as of the month ending immediately preceding the month in which the merger becomes effective. The Merger Value is based upon a formula used to allocate shares of common stock and does not constitute a market value of our stock or our reserves. While we believe the Merger Value is a fair measure of allocating shares of our common stock to each partnership, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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Partnership Name	Aggregate Merger Value Attributable to Southwest’s General Partner Interests(1) (in thousands) ($)	Aggregate Merger Value Attributable to Southwest’s Limited Partner Interests (in thousands) ($)	Aggregate Merger Value Attributable to Limited Partners (Other than Southwest) (in thousands) ($)	Aggregate Number of Shares of Southwest Common Stock Offered to Limited Partners (#)(2)(3)
Southwest Royalties, Inc. Income Fund V, L.P.	96	329	538	11,563
Southwest Royalties, Inc. Income Fund VI, L.P.	588	1,872	3,422	73,594
Southwest Oil & Gas Income Fund VII-A, L.P.	237	668	1,468	31,576
Southwest Royalties Institutional Income Fund VII-B, L.P.	398	1,043	2,539	54,614
Southwest Oil & Gas Income Fund VIII-A, L.P.	221	481	1,505	32,366
Southwest Royalties Institutional Income Fund VIII-B, L.P.	236	445	1,682	36,181
Southwest Oil & Gas Income Fund IX-A, L.P.	250	97	2,152	46,273
Southwest Royalties Institutional Income Fund IX-B, L.P.	234	69	2,039	43,861

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Partnership Name	Aggregate Merger Value Attributable to Southwest’s General Partner Interests(1) (in thousands) ($)	Aggregate Merger Value Attributable to Southwest’s Limited Partner Interests (in thousands) ($)	Aggregate Merger Value Attributable to Limited Partners (Other than Southwest) (in thousands) ($)	Aggregate Number of Shares of Southwest Common Stock Offered to Limited Partners (#)(2)(3)
Southwest Oil & Gas Income Fund X-A, L.P.	71	10	626	13,468
Southwest Royalties Institutional Income Fund X-A, L.P.	139	31	1,219	26,232
Southwest Oil & Gas Income Fund X-B, L.P.	114	19	1,006	21,642
Southwest Royalties Institutional Income Fund X-B, L.P.	160	64	1,375	29,574
Southwest Oil & Gas Income Fund X-C, L.P.	83	25	721	15,512
Southwest Royalties Institutional Income Fund X-C, L.P.	68	11	598	12,870
Southwest Developmental Drilling Fund 91-A, L.P.	23	4	184	3,950
Southwest Developmental Drilling Fund 92-A, L.P.	89	3	718	15,444
Southwest Partners, L.P.	1,499	440	8,057	173,285
Southwest Combination Income/Drilling Program 1988, L.P.	12	3	64	1,372

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Partnership Name	Aggregate Merger Value Attributable to Southwest’s General Partner Interests(1) (in thousands) ($)	Aggregate Merger Value Attributable to Southwest’s Limited Partner Interests (in thousands) ($)	Aggregate Merger Value Attributable to Limited Partners (Other than Southwest) (in thousands) ($)	Aggregate Number of Shares of Southwest Common Stock Offered to Limited Partners (#)(2)(3)
Southwest Developmental Drilling Fund 1990, L.P.	80	—	454	9,759
Southwest Developmental Drilling Fund 1993, L.P.	139	2	1,122	24,139
Southwest Developmental Drilling Fund 1994, L.P.	64	—	515	11,071

⁽¹⁾ Our Chairman, President and Chief Executive Officer, H.H. Wommack, III, is an additional general partner in nine of the partnerships that we propose to include in the merger. Prior to the consummation of the merger, however, Mr. Wommack will transfer these general partner interests to Southwest for no consideration. The aggregate Merger Value attributable to Southwest’s general partner interests includes the general partner interests to be transferred to Southwest by Mr. Wommack.

⁽²⁾ Although Merger Value is attributable to our general partner and limited partner interests, we will not receive shares of our common stock in connection with the merger. Instead, the ownership percentage of Merger Value attributable to our interests will be netted out of the total Merger Value.

⁽³⁾ The aggregate number of shares of our common stock to be distributed to the limited partners will increase in the event our shares of special stock to be held in escrow convert into common stock. The total number of special stock to be held in escrow and allocable to the limited partners is 137,669 shares (assuming all 21 partnerships participate in the merger).

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Summary Table—Merger Value and Distributions

Set forth below is the estimated Merger Value and limited partner distributions from inception through June 30, 2002, per $500 investment for each partnership. Not all limited partners originally invested in the partnerships at $500 per unit of limited partner interest. This figure is used to show an equivalent interest basis only. See “THE PARTNERSHIPS” for the original investment per interest of each partnership. Additionally, as noted above, the Merger Value for each partnership will be recalculated on the effective date of the merger.

	Per $500 Initial Limited Partner Investment
Partnership Name	Merger Value	Limited Partner Distributions from Inception Through June 30, 2002
Southwest Royalties, Inc. Income Fund V, L.P.	$  57.79	$471
Southwest Royalties, Inc. Income Fund VI, L.P.	$264.71	$786
Southwest Oil & Gas Income Fund VII-A, L.P.	$142.38	$658
Southwest Royalties Institutional Income Fund VII-B, L.P.	$238.84	$667
Southwest Oil & Gas Income Fund VIII-A, L.P.	$146.09	$563
Southwest Royalties Institutional Income Fund VIII-B, L.P.	$209.65	$635
Southwest Oil & Gas Income Fund IX-A, L.P.	$215.15	$656
Southwest Royalties Institutional Income Fund IX-B, L.P.	$215.49	$658
Southwest Oil & Gas Income Fund X-A, L.P.	$  60.72	$248
Southwest Royalties Institutional Income Fund X-A, L.P.	$110.48	$275
Southwest Oil & Gas Income Fund X-B, L.P.	$  94.18	$451
Southwest Royalties Institutional Income Fund X-B, L.P.	$128.69	$452
Southwest Oil & Gas Income Fund X-C, L.P.	$119.52	$533
Southwest Royalties Institutional Income Fund X-C, L.P.	$101.79	$493
Southwest Developmental Drilling Fund 91-A, L.P.	$  81.81	$548
Southwest Developmental Drilling Fund 92-A, L.P.	$256.10	$521

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	Per $500 Initial Limited Partner Investment
Partnership Name	Merger Value	Limited Partner Distributions from Inception Through June 30, 2002
Southwest Partners, L.P.	$976.64	$  38

Southwest Combination Income/ Drilling Program 1988, L.P.	$  19.01	$254
Southwest Developmental Drilling Fund 1990, L.P.	$130.77	$286
Southwest Developmental Drilling Fund 1993, L.P.	$270.45	$524
Southwest Developmental Drilling Fund 1994, L.P.	$115.16	$128

Method of Determining Merger Value of each Limited Partnership

The following method was used to determine the Merger Value and the number of shares of our common stock to be exchanged for each unit of limited partner interest in each partnership.

The Merger Value for each unit of partnership interest in each participating partnership has been determined by (1) calculating the net asset value (“Net Asset Value”) of each partnership and Southwest and (2) dividing each entity’s Net Asset Value by the total combined Net Asset Value of all the partnerships and Southwest to determine a percentage of ownership for each partnership and Southwest.

Our financial statements have been prepared in accordance with GAAP. As a consequence, the proportionate share of our ownership in the partnerships is included in our balance sheet. These amounts have been adjusted for use in the Merger Value calculation and, as a result, the amounts shown will not coincide with our audited and unaudited financial statements presented elsewhere in this prospectus/proxy statement. Our short-term and long-term debt excludes the additional carrying value representing future interest expense as imposed by SFAS No. 15 “Accounting for Debtors and Creditors for Troubled Debt Restructurings.”

We determined the Net Asset Value per limited partner interest for each partnership as follows:

1. We engaged Ryder Scott Company, L.P., an independent petroleum engineering and consulting firm, to audit the volumes of proved reserves of Southwest and of each partnership as of December 31, 2001, and our internal engineers updated the reports to July 1, 2002. The reserve value component is set forth in Appendix B to this prospectus/proxy statement. Please refer to the reports audited by Ryder Scott Company, L.P. located in Appendix B (the “Ryder Scott Reports”) for more information, including all of the parameters used in the estimation process, including any adjustments made for risk, location, type of ownership interest, operational characteristics and other factors. If we have not consummated the merger by year-end, Ryder Scott Company, L.P. will prepare the volumes of proved reserves for Southwest and each partnership at year-end. We will then recalculate the Net Asset Value based upon the revised reports and as updated by our internal staff of engineers.

2. Using the Ryder Scott Reports, our engineers calculated the present value of estimated future net revenues for Southwest and each partnership as of July 1, 2002 using $26.46, $24.74, $23.30, $22.44 and $21.84, the five-year NYMEX future prices for oil, and $3.42, $3.86, $3.96, $3.99 and $4.02, the five-year NYMEX

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futures prices for gas, with prices held constant after year five at the year five price, less standard industry price adjustments listed below. Historical operating costs were adjusted only for those items affected by commodity prices, such as production taxes and ad valorem taxes. An industry-standard discount rate of 10% was used in the calculation of the value of proved developed producing reserves (“PDP”). Ten percent is the discount rate commonly used in the industry for producing reserve acquisition evaluations and the rate required to be used by the SEC for calculating discounted future net cash flows of all reserve categories for comparative reporting in the year-end reports of publicly owned oil and gas companies. We used a discount rate of 15% to calculate the value of the proved non-producing reserves (“PNP”) and a discount rate of 20% to calculate the value of the proved undeveloped reserves (“PUD”). By using a higher discount rate to calculate the future net cash flows of the currently non-producing reserve categories, we have adjusted the value of these reserves for the inherent risks associated with their future development. We believe that the higher discount rate used in the valuation of the non-producing reserves results in a more fair “risk-adjusted” value and is a commonly accepted practice in the industry. We believe the discount rates used in the calculation of the non-producing reserves represent a fair discount percentage based on our knowledge of the properties, as well as the fact that we did not adjust the value of the non-producing properties of the partnerships even though these partnerships are unable to develop their reserves. Currently, the partnerships (except Southwest Partners, L.P.) are unable to invest the capital necessary to develop their nonproducing and nondeveloped reserves because of cash flow and partnership agreement restrictions. The partnerships must rely on third parties for the development of these reserves. The farm-out negotiations usually require the owners to relinquish a large portion of the ownership in the developed properties. Each partnership’s reserve estimates and present value of future net revenues were prepared assuming the partnerships had the ability to invest the necessary capital expenditures to directly develop their nondeveloped reserves and that development restrictions did not apply.

The standard industry adjustments include:

a. the effects of oil quality;

b. British thermal unit, or BTU, content of gas;

c. any bonus paid (by the purchaser);

d. oil and gas gathering and transportation costs; and

e. gas processing costs and shrinkage.

No adjustments were made for gas imbalances, which were deemed immaterial.

For purposes of the Merger Value calculation Southwest’s reserve estimates and present value of future net revenues were prepared assuming no ownership in the partnerships by Southwest.

3. We then determined the Net Asset Value for Southwest and each partnership using the following formula:

a. the present value (as described above) of the future net revenues as of July 1, 2002 using the appropriate discount factor for each reserve category, plus

b. the net working capital (current assets minus current liabilities) as of June 30, 2002, less

c. long-term debt, as of June 30, 2002, plus

d. the book value of any Additional Net Assets, as of June 30, 2002, less

e. estimated merger expenses and fees, which apply only to Southwest’s Net Asset Value.

The assets and liabilities of Southwest and each partnership are accounted for in accordance with GAAP, which uses accrual-based accounting methodology. Our short-term and long-term debt, however, excludes the additional carrying value representing future interest expense.

4. The percentage of general partner interests owned by Southwest in each partnership was then subtracted from each partnership’s respective Net Asset Value to determine the limited partners’ Net Asset Value and Southwest’s Net Asset Value for its general partner interests.

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5. The percentage of limited partner interests owned by Southwest in each partnership was then calculated and deducted from the limited partners’ Net Asset Value in each partnership to determine (a) the Net Asset Value of the partnership interests owned by Southwest, and (b) the Net Asset Value of the partnership interests owned by all other limited partners in each partnership.

6. The Net Asset Value of each partnership attributable to the general partner interests and limited partner interests owned by Southwest was added to the Net Asset Value of Southwest to determine the final and Adjusted Net Asset Value for Southwest.

7. The Net Asset Value of the limited partners in each partnership (excluding Southwest’s general partner and limited partner interests) and the Adjusted Net Asset Value of Southwest was divided by the total of the Net Asset Value of the limited partners in each partnership (excluding Southwest’s general and limited partner interests) plus the final and Adjusted Net Asset Value of Southwest to determine a percentage of ownership to the total Net Asset Value for each partnership and Southwest.

8. The total number of shares of Southwest common stock and Class A common stock currently issued and outstanding was divided by Southwest’s percentage of ownership to the total Net Asset Value to determine the total number of shares of common stock of the combined business (on a post-merger basis and assuming the conversion of Class A common stock into common stock).

9. Each partnership’s percentage of ownership to the total Net Asset Value was then multiplied by the total number of shares of common stock of the combined business (on a post-merger basis and assuming the conversion of Class A common stock into common stock) to determine the number of shares of common stock to be allocated to each partnership.

10. The number of shares of common stock to be allocated to each partnership was then divided by the number of limited partner interests in each partnership (less the general and limited partner interests owned by Southwest) to determine the number of shares of common stock per partnership interest to be distributed to the limited partners.

Shares of our special stock will be issued into escrow by Southwest, to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock To Be Issued in the Merger.” The issuance of 137,669 shares of our special stock into escrow is intended to prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will have a right to a number of shares of special stock, calculated by (a) multiplying the total number of shares of special stock to be allocated to the partnerships by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock allocable per each limited partner interest in each partnership.

The Merger Value will be recalculated using the Adjusted Net Asset Value on the effective date of the merger. The Adjusted Net Asset Value will use the same formula as outlined above, except for the following adjustments:

1. The proved reserves and future net revenues for Southwest and each partnership will be recalculated by Southwest by adjusting the most current Ryder Scott Reports forward to the month ending immediately preceding the month in which the merger becomes effective and recognizing any material reserve changes such as additions and deletions.

2. The net working capital, long-term debt, and Additional Net Assets used to calculate the Net Asset Value for each partnership and Southwest will be determined from the financial statements as of the month ending immediately preceding the month in which the merger becomes effective, subject to and adjusted for any material changes in any of the aforementioned components.

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Example Calculation of Merger Value

Set forth below is a table showing the calculation of the Merger Value for Southwest Royalties, Inc. Income Fund V, L.P. Our financial statements have been prepared in accordance with GAAP. As a consequence, the proportionate share of our ownership in the partnerships is included in our balance sheet. These amounts have been adjusted for use in the Merger Value calculation and, as a result, the amounts shown will not coincide with our audited and unaudited financial statements presented elsewhere in this prospectus/proxy statement. Our short-term and long-term debt excludes the additional carrying value representing future interest expense as imposed by SFAS No. 15 “Accounting for Debtors and Creditors for Troubled Debt Restructurings.”

(1)	Determine the Net Asset Value of Income Fund V				Document(s) from which information was obtained or calculated
		Net Present Value of Reserves	$	917,495.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	45,608.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional net assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Income Fund V	$	963,103.00	calculated
(2)		Net Asset Value of Income Fund V	$	963,103.00	calculated
	less	GP% owned by Southwest in Income Fund V (10%)	$	96,310.30	Partnership records
	less	LP% owned by Southwest in Income Fund V (34.18%)	$	329,188.61	Partnership records
	equals	Net Asset Value of Income Fund V owned by limited partners (excluding Southwest’s ownership%)	$	537,604.09	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP% of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Income Fund V (excluding Southwest’s ownership%)	$	537,604.09	calculated
	equals	The percentage of ownership of Income Fund V (other than Southwest) to the total Net Asset Value		0.68%	calculated

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				Document(s) from which information was obtained or calculated
(5)		Total shares of Southwest Class A common stock and common stock currently issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Income Fund V (other than Southwest)	0.68%	calculated
	equals	The number of shares of common stock attributable to Income Fund V (other than to Southwest)	11,562.53	calculated
(7)		The number of shares of common stock attributable to Income Fund V (other than to Southwest)	11,563
	divided by	The number of limited partner interests (less the GP and Southwest LP interests) in Income Fund V	4,651	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Income Fund V	2	calculated
(8)		The number of shares of special stock attributable to Income Fund V (other than to Southwest)	2,313	Calculated
	divided by	The number of limited partner interests (less the GP & Southwest LP interests) in Income Fund V	4,651	Partnership records
	equals	The number of shares of special stock issuable per each limited partner interest in Income Fund V	.5	calculated

Background and Reasons for the Merger

Overview

We are proposing the merger of 21 public and private partnerships into Southwest’s subsidiary, Southwest Consolidated Partnerships, and the subsequent merger of Southwest Consolidated Partnerships into Southwest’s subsidiary, Southwest Managed Assets. Upon consummation of the merger, all assets and liabilities of the partnerships that participate in the merger will become the assets and liabilities of our subsidiary, Southwest Managed Assets, and the participating partnerships and Southwest Consolidated Partnerships will cease to exist. Limited partners will ultimately receive shares of our common stock in connection with the merger. Additionally, we will issue shares of our special stock into an escrow account, which shares are intended to prevent the limited partners’ stock ownership from being diluted under certain circumstances.

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The merger must be approved and adopted by at least 75% of the outstanding limited partner interests of a partnership before that partnership will be able to participate in the merger.

We are furnishing this prospectus/proxy statement to the limited partners of the partnerships in connection with our solicitation of proxies, for use at the joint special meeting of limited partners and at any adjournments or postponements of the joint special meeting.

Background of the Merger

The limited partnerships were formed by Southwest between 1986 and 1994. We have routinely had general, internal discussions about how to maximize the value of the partnerships’ assets, particularly while considering the partnerships’ inability to develop their nonproducing reserves. Over the last five to seven years, we have discussed various transaction possibilities for maximizing partnership value, including the sale of partnership properties to unaffiliated third parties, the continuation of partnership operations and the combining of certain of the partnerships into a separate oil and gas company. We have also examined alternatives brought to us by investment banking firms. Although many possibilities were reviewed, we believe that the best opportunity for the limited partners to maximize the value of their interests is a merger of the partnerships into Southwest’s subsidiary.

Benefits of the Merger to the Limited Partners

The following are the principal anticipated benefits of the merger to the limited partners. We cannot assure you, however, that the merger will achieve any of the benefits and objectives described below. You should analyze the anticipated benefits and objectives of the merger in light of all of the terms of the merger as described in this prospectus/proxy statement and the prospectus supplement(s) of your partnership(s).

Greater Access to Capital Markets and Increased Growth and Investment Appreciation.    We believe that a larger, combined business will have greater access to public and private capital markets as a result of the increase in and diversification of our asset base resulting from the merger. This increased access to capital may provide us with greater flexibility to fund acquisitions and development strategies.

Increased Liquidity.    We believe that the participation in the merger will provide you with shares of common stock for which there may be a public market in the future. We cannot assure you, however, that an active market for our common stock will, in fact, develop.

Increased Exploratory and Developmental Drilling.    We believe that following the merger, we will be able to take advantage of development opportunities in properties currently owned by the partnerships in which the partnerships cannot currently directly engage in exploratory or developmental drilling under the partnership agreements. The removal of these restrictions may enable us to realize a larger return on investment.

Reduction of Tax Reporting Requirements and Costs.    As a stockholder in Southwest, you will not be required to include information regarding our operations on your personal tax returns as you now do for the partnership operations and will no longer receive a Schedule K-1. Thus, we believe that the exchange of your limited partner interests for our common stock will eliminate some partnership tax reporting requirements and certain associated costs.

Increased Reinvestment of Cash Flow and Growth Potential.    Following the merger, we intend to retain and reinvest the net cash flow from partnership properties. We believe that the increase in overall asset size, along with the retention and reinvestment of the cash flow that would otherwise be distributed, will increase our financial strength and flexibility and will facilitate the acquisition and development of oil and gas properties.

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Administrative Efficiencies.    We believe that participation in the merger will result in general and administrative efficiencies and cost reductions in the management and operation of the properties and the partnerships. For example, we will no longer have to file individual tax returns for each limited partnership and will no longer be required to file periodic reports with the SEC for the reporting partnerships.

Geographic and Operational Efficiencies.    Our primary operations are located in the Permian Basin. The partnerships also either hold interests in, or produce and market oil and gas drilled from, properties in the Permian Basin. We own interests in many of the same properties as the partnerships and operate many of the properties in which the partnerships own an interest. The merger of the partnerships should create geographic and operational efficiencies for the management of our properties and the properties of the partnerships.

Maturity of Partnerships and Properties.    Although each partnership held many long-lived properties at inception, because of the restrictions on property development imposed by the partnership agreements we anticipate that at some point each partnership will need to be liquidated. We are recommending the merger for each partnership at this time because maintenance of the properties and administrative expenses for each partnership are increasing relative to production and, as each partnership’s properties have matured, the net cash flows from operations for each partnership have generally declined, except in periods of substantially increased commodity pricing.

Disadvantages of the Merger to the Limited Partners

The following are what we believe to be the principal disadvantages of the merger to the limited partners:

Different Investment Objective.    Limited partners of each partnership will own stock in a corporation, which is a different investment from an investment in a partnership that is designed to generate recurring cash distributions. It is unlikely that we will make cash distributions to our stockholders in the foreseeable future.

Significant Indebtedness of Southwest.    Limited partners who become Southwest stockholders will be exchanging limited partner interest in a partnership that generally cannot incur indebtedness for shares of common stock in Southwest, which has a significant level of indebtedness.

Increased Risks from Operations.    We plan to engage in the acquisition, exploration and development of oil and gas properties that will expose limited partners of each partnership to all of the attendant risks associated with such activities. Each partnership owns producing properties and does not conduct drilling activities. Our activities may, therefore, involve greater risks than the activities of each partnership. Additionally, each partnership’s properties will become part of a larger group of properties, which may have increased liabilities attendant to those properties which are currently not borne by another partnership.

Volatility of Market Price of Common Stock.    Limited partnership investments are not currently subject to any market risk or volatility, other than oil and gas price fluctuations. Upon becoming a Southwest stockholder, a limited partner’s investment in Southwest will be subject to the volatility and risk of the market. Market factors that may affect the common stock price may include general market conditions and the broader economy, as well as trading and market support risk.

Potential Taxable Transaction.    The merger may create a taxable event for the limited partners in the event the IRS disagrees with our characterization of the merger as a tax-neutral event.

Reasons for the Structure and Timing of the Merger

We initiated the merger and are proposing the merger at this time because the partnerships’ properties are mature and need further significant development to exploit their value. The merger has been structured so that the limited partners of either Southwest Partners, L.P. or Southwest Royalties Inc. Income Fund VI, L.P. must

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approve the merger. Southwest Partners’ Net Asset Value constitutes 23.56% of all partnerships’ combined Net Asset Value, and Southwest Royalties Inc. Income Fund VI’s Net Asset Value constitutes 13.87% of all partnerships’ combined Net Asset Value. We believe that a certain minimum number of properties must be obtained in order to enhance our reserves materially and to achieve our strategic objectives.

Alternatives to the Merger

The alternatives to the merger include liquidating some or all of the partnerships, continuing some or all of the partnerships as separate, operating entities and selling partnership properties. See “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger.” After consideration of the various alternatives, we have determined that the proposed merger would provide the limited partners with the best opportunity to maximize the value of their interests.

Fairness of the Merger

General

We have spent significant time and resources evaluating the fairness of the proposed merger, including the hiring of an investment bank to render an opinion regarding the fairness of the merger to the partnerships. In order to evaluate the fairness of the merger, we have reviewed current industry conditions, the reserves of the partnerships and of Southwest, the nature of those reserves, the development prospects for those reserves and the likelihood of other potential third party transactions, including sales of properties to unaffiliated third parties. Further, we evaluated the stated desire of many limited partners, as well as our own stockholders, for market liquidity which would necessitate a registration of our securities. We also evaluated the costs of all of these possible actions relative to the benefits to be received by the limited partners. As a result of this analysis, we have concluded that a merger of the partnerships into Southwest’s subsidiary is fair to and in the best interests of the limited partners of each partnership.

Our decision is based on the following factors:

• The Merger Value is greater than the net book value, the going concern value, the final presentment value and the liquidation value of each of the partnerships, except that the stated net book value of Southwest Royalties, Inc. Income Fund V, L.P. is greater than the Merger Value. The right of presentment is not available to limited partners under Southwest Partners’ partnership agreement. We are not aware of any bids on the partnerships to purchase, merge, consolidate or combine any of the partnerships or any material portion of their assets over the past five years. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED—Other Methods of Determining Merger Value.”

• Our calculation of the Net Asset Value of each of the partnerships and Southwest uses a standard method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• Our method of valuation for each of the partnerships and Southwest uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of each of the properties.

• The allocation of shares of our stock is based on a standardized method of calculating and allocating value for all entities, including Southwest.

• We have received an opinion from Friedman, Billings, Ramsey & Co., Inc. (“FBR”) that the merger is fair to the limited partners of each partnership from a financial point of view.

• We are requiring a super-majority vote of 75% of outstanding limited partner interests for each partnership in order to participate in the merger.

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We believe that all or any possible combinations of the merger of the 21 partnerships is fair and beneficial to the limited partners, so long as we receive the adoption and approval of the merger by the limited partners in either Southwest Partners, L.P. or Southwest Royalties Inc. Income Fund VI, L.P.

Fairness Opinion

Friedman, Billings, Ramsey & Co., Inc., which we refer to as FBR, has issued a fairness opinion dated             , 2002, that, subject to the qualifications, assumptions and limitations expressed in the opinion, the Merger Value for each partnership and the allocation of the Merger Value of each partnership (1) to the limited partners of each partnership, including all possible combinations of the partnerships, and (2) to Southwest as the managing general partner of each partnership, is fair from a financial point of view. The full text of the written opinion of FBR is attached to this document as Appendix E. You should read all of it carefully. THE OPINION OF FBR IS DIRECTED TO OUR BOARD OF DIRECTORS. IT IS NOT A RECOMMENDATION TO YOU ABOUT HOW YOU SHOULD VOTE ON MATTERS RELATING TO THE PROPOSED MERGER OF ANY PARTNERSHIP IN WHICH YOU OWN AN INTEREST.

Recommendation to Limited Partners

On October 9, 2002, our Board of Directors unanimously approved the merger and determined that the merger of each partnership in which you own a limited partner interest is fair to you as a limited partner and in your best interest. Our Board recommends the merger to you and that you, as a limited partner, vote for the merger of each partnership in which you own a limited partner interest.

In making this recommendation, our Board of Directors considered a number of factors, including factors described under “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger,” and “RISK FACTORS.” Our Board of Directors also considered the likelihood of completion and the benefits and costs of other transactions, as well as the consequences of taking no action, as discussed under “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger.”

Although our Board of Directors has attempted to fulfill its fiduciary duties to you, our Board of Directors had conflicting interests in evaluating the merger because the Board of Directors also has fiduciary duties to the stockholders of Southwest. Also, our Chairman, President and Chief Executive Officer, H.H. Wommack, III, is a general partner of nine of the partnerships and is a significant stockholder of Southwest. Prior to the consummation of the merger, however, Mr. Wommack will transfer his general partner interests of these partnerships to Southwest for no consideration.

Our Conflicts of Interest

We have conflicts of interest with the limited partners with respect to the merger arising from, among other things:

• We determined the structure of the proposed merger and the Merger Values without any independent third party representing the limited partners of any partnership. As a result, the determination of the Merger Values and the relative ownership of Southwest by limited partners may not reflect the

      allocation of relative value that would result if the merger were negotiated with an unaffiliated third party in an arms length transaction.

• H.H. Wommack, III is an additional general partner in nine of the limited partnerships that we propose to merge into Southwest. He is also our Chairman, President and Chief Executive Officer and is a significant stockholder of Southwest. Prior to the consummation of the merger, however, Mr. Wommack will transfer his general partner interests of these partnerships to Southwest for no consideration.

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• Legal counsel was engaged by Southwest to assist with the preparation of the documentation for the merger, including this document, and did not serve, or purport to serve, as legal counsel for the limited partners.

No Independent Representative

No independent representative of the limited partners was engaged for purposes of negotiating the terms of the merger. As a result, the Merger Values and other terms of the merger may not be as favorable as the terms that might have been obtained had an independent representative been retained.

Merger of each Partnership

General

At the effective time of the merger of each partnership participating in the merger, each such partnership will be merged with and into Southwest’s subsidiary, Southwest Consolidated Partnerships, and, immediately thereafter, Southwest Consolidated Partnerships will be merged with and into Southwest’s subsidiary, Southwest Managed Assets. Southwest Managed Assets will be the surviving entity. In addition, at the effective time of the merger of each participating partnership, each of your limited partner interests in a partnership that participates in the merger will ultimately be converted into Southwest common stock. In addition, we will issue shares of our special stock into an escrow account, which shares are intended to prevent the limited partners’ stock ownership from being diluted under certain circumstances. See the diagrams in “BACKGROUND AND REASONS FOR THE MERGER” for a full description of the merger.

No Continuing Interest in the Partnerships

Upon completion of the merger of each partnership participating in the merger, you, as a limited partner of a participating partnership, will have no continuing interest in, or rights of, the partnership. The transfer books of each participating partnership will be closed on the closing date of the merger of the partnership. All partnership interests in each participating partnership will cease to be outstanding, will automatically be canceled and retired, and will cease to exist.

Fractional Shares

We will not issue fractional shares of our common stock to any limited partner upon completion of the merger. Instead, we will round any fractional shares of our common stock off to the nearest whole share. We will not issue fractional shares of our special stock into the escrow account in connection with the merger.

Termination of the Merger of a Partnership

We may terminate the merger agreements, for any or all of the partnerships, at any time, even after limited partner approval of the merger, at our sole discretion.

Conditions to Consummation of the Merger

We will complete the merger of each partnership only if certain conditions, including those in the merger agreement, are satisfied or, if permitted, waived. These conditions include:

• the adoption and approval of the merger by the limited partners of either Southwest Partners, L.P. or Southwest Royalties Inc. Income Fund VI, L.P.;

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• the consent to waive certain provisions of our Indenture governing the Senior Secured Notes due 2004 by the holders of those Senior Secured Notes and the consent to waive certain provisions in our Senior Credit Agreement by our senior lenders;

• the approval of the merger by our stockholders;

• the absence of any law or court order that prohibits the merger; and

• the absence of any lawsuit challenging the legality or any aspect of the merger.

If permitted, we may choose to complete a merger of any partnership even though a condition has not been satisfied, so long as limited partners of a partnership participating in the merger and our stockholders have approved the merger. We may complete the merger of any one or some of the partnerships, even if limited partners in other partnerships do not approve the merger.

Expenses and Fees and Source of Funds

The costs of planning and developing the merger and presenting it to you and the other limited partners will be borne by Southwest without regard to whether the merger is effectuated. The estimated amount of these costs is approximately $3.0 million. We are paying for the costs of the merger with existing cash flows from operations.

Appraisal Rights

Limited partners are not entitled to appraisal or dissenters’ rights under the laws of the State of Delaware or the State of Tennessee, which are the states of formation of the partnerships. If the merger of a partnership in which a limited partner holds an interest is approved by 75% of the outstanding limited partner interests of your partnership, limited partners of that partnership will be bound by the merger even if they vote against the merger.

Partnership Lists

Upon your written request, we will deliver to you within five business days of receipt of your request, a list of the names, addresses and interest holdings of the limited partners of the partnership(s) in which you hold limited partner interests as of the record date. See “MERGER OF EACH PARTNERSHIP—Limited Partner Lists for each Partnership” for further information about your ability to receive a partnership list.

Access to Books and Records and Separate Counsel

Books and records relating to the operations of all of the partnerships are maintained at 407 North Big Spring Street, Suite 300, Midland, Texas 79701, our principal place of business. All limited partners have access to the books and records of their respective partnership at all reasonable times, upon reasonable notice. No provision has been made to allow limited partners to obtain counsel or appraisal services at our expense.

Effects of the Merger of a Partnership on its Limited Partners who do not Vote in Favor of the Merger

You will be bound by the merger of a partnership in which you own interests if the limited partners in your partnership vote 75% of the outstanding limited partner interests in favor of the merger, even if you vote against the merger. If the merger of your partnership occurs with the approval of 75% of limited partner interests outstanding, then you will be entitled to receive only an amount of our common stock based on the Merger Value for your limited partner interests.

Future of a Partnership that does not Participate in the Merger

If your partnership does not participate in the merger for any reason, that partnership will remain in existence. Some reasons your partnership might not participate in the merger are that (1) the limited partners vote

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against the merger, (2) a condition in the merger agreements is not satisfied, or (3) we exercise a termination right with respect to the merger for that partnership.

We have not formulated an alternative business plan for any nonparticipating partnership. The business objectives of each nonparticipating partnership will continue as they are. We plan to continue to manage each nonparticipating partnership and operate it in accordance with the terms of its current partnership agreement. Each nonparticipating partnership will continue to operate as a separate legal entity with its own assets and liabilities. Distributions from any nonparticipating partnership are expected to continue to decline since its production revenues are expected to continue to decline more quickly than its production costs. Regardless of whether any nonparticipating partnership distributes cash, limited partners must continue to include their share of partnership income and loss in their individual tax returns.

Our Board of Directors will decide what, if any, actions we will take regarding any nonparticipating partnership. Potential actions might include a tender offer for partnership interests of limited partners or a proposal to acquire the assets of, or a merger of, one or more of the nonparticipating partnerships. The proposal may be on terms similar to or different from those of the merger described in this prospectus/proxy statement.

Regulatory Requirements

No federal or state regulatory requirements must be satisfied or approvals obtained in connection with the merger of any of the partnerships as described in this prospectus/proxy statement, except (1) filing a registration statement that includes this prospectus/proxy statement with the SEC and obtaining the SEC’s declaration that the registration statement is effective under the Securities Act and (2) filing certificates of merger with the Secretary of State of Delaware and the Secretary of State of Tennessee.

Meeting, Voting and Proxy Information

Meeting

The joint special meeting of the limited partners will be held at The Midland Hilton, 117 West Wall Street, Midland, Texas, 79701, at 10:00 a.m. Central Time, on             ,             , 2002 to consider and vote on the merger, the amendments to the partnership agreements and any other matters that may properly come before such meeting. With respect to the special meeting, the presence, in person or by proxy, of limited partners holding a majority of the outstanding limited partner interests of each partnership will constitute a quorum in regard to such partnership.

In connection with the joint special meeting, limited partners who approve the merger will also execute a written consent, as prospective stockholders of Southwest Consolidated Partnerships, to approve the subsequent merger of Southwest Consolidated Partnerships into Southwest Managed Partners.

Record Date

Only limited partners of record at the close of business on             , 2002, as shown on our records, will be entitled to vote, or to grant proxies to vote at the joint special meeting.

There is no record date for the merger of Southwest Consolidated Partnerships into Southwest Managed Assets; instead, a limited partner who votes in favor of the merger of its respective partnership into Southwest Consolidated Partnerships will also execute a written consent, as a prospective stockholder of Southwest Consolidated Partnerships, to approve the subsequent merger of Southwest Consolidated Partners into Southwest

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Managed Assets. The written consent will become effective upon the merger of the participating partnerships into Southwest Consolidated Partners.

Vote Required for Approval

The purpose of the joint special meeting is to ask the limited partners of each partnership to approve the merger and the amendments to each of the partnership agreements. The merger and amendments to each of the partnership agreements must be approved and adopted by at least 75% of the outstanding limited partner interests of a partnership before that partnership will be able to participate in the merger. We are requiring 75% approval in order to satisfy our obligations to demonstrate that the merger is not unfair based upon the NASD Rules.

We are generally entitled under the partnership agreements to vote any limited partner interests that we hold at the special meeting for each partnership in which we hold such an interest. See “MEETING, VOTING AND PROXY INFORMATION.” We plan to vote all our limited partner interests for the merger. The voting interest that we hold in each partnership is found in Table 4 of Appendix A. To our knowledge, none of our directors or executive officers, or any associate or affiliate of Southwest, beneficially owns any limited partner interests of any partnership or is otherwise entitled to vote any limited partner interests.

Limited partners who vote in favor of the merger of the partnerships into Southwest Consolidated Partnership will also execute a written consent, as prospective stockholders of Southwest Consolidated Partnerships, to approve the subsequent merger of Southwest Consolidated Partnership with and into Southwest Managed Assets.

Proxies

Each limited partner as of             , 2002, the record date, will receive a proxy card. A limited partner may grant a proxy to vote for or against, or to abstain from voting on, the plans of merger by marking his proxy card appropriately, executing it in the space provided, and returning it to the proxy tabulator. A limited partner may also grant a proxy by voting over the Internet at www.             or by calling 1-800-            .

Federal Income Tax Considerations

General Treatment

We believe that the merger of a partnership into Southwest’s subsidiary, Southwest Consolidated Partnerships, should be treated for federal income tax purposes as a non-taxable contribution of its assets and liabilities by the partnership to Southwest Consolidated Partnerships. Likewise, we believe that the merger of Southwest Consolidated Partnerships into Southwest Managed Assets should be treated for federal income tax purposes as a non-taxable contribution of its newly-acquired assets and liabilities to Southwest Managed Assets in exchange for the common stock in Southwest held by Southwest Managed Assets, followed by a distribution of the Southwest common stock to the former limited partners. It is possible, however, that the IRS may characterize the merger as a taxable event, in which case taxable gain or loss would be recognized by the limited partners in the year of the merger.

Treatment to Participating Partnerships

If the merger is treated as a contribution and liquidation as described above, the participating partnerships should not recognize gain or loss upon the transfer of properties to Southwest’s subsidiary in exchange for common stock in Southwest Consolidated Partnerships. A participating partnership should take an adjusted basis in the common stock received equal to the aggregate adjusted basis in the assets transferred to Southwest’s

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subsidiary. Each participating partnership will terminate upon the effective date of the merger and, accordingly, will close its tax year and distribute its assets to the limited partners. The closing of the tax year requires the partnerships to file a final tax return, which may, in turn, create a one-time tax consequence to the partnerships.

Treatment to Southwest and to its Subsidiary Southwest Managed Assets

Neither Southwest nor its subsidiary, Southwest Managed Assets, should recognize gain or loss as a result of the receipt of a participating partnership’s assets and liabilities in the transfers. Southwest’s subsidiary, Southwest Managed Assets, should take an adjusted basis in the assets ultimately received from a partnership equal to the adjusted basis that each participating partnership had in its contributed assets. Under the applicable provisions of the Internal Revenue Code and Regulations, the holding period for some assets transferred (for the purpose of determining whether the assets will be treated as capital gains or capital losses—see explanation below under “SUMMARY—Treatment to Limited Partners”) will include the period for which the participating partnerships held the assets. For other assets, a new holding period will begin upon transfer.

Treatment to Limited Partners

As a limited partner ultimately receiving Southwest common stock, you should be treated as receiving such stock in liquidation of your limited partner interest in the participating partnership. Liquidation for tax purposes, however, does not constitute liquidation under any partnership agreement or liquidation under the laws of the states of formation of any partnership. If the merger is treated as a contribution and liquidation for tax purposes, no gain or loss should be recognized by you as a limited partner of any participating partnership as a result of your receipt of Southwest common stock. Additionally, the shares of special stock to be issued into an escrow account for the benefit of the limited partners and the additional common stock to be distributed to the limited partners in the event the special stock converts into common stock will likewise be tax-neutral to the limited partners. However, there is a possibility that the IRS may disagree with our characterization of the merger.

Your adjusted basis in the Southwest stock you receive in the merger should be the same as your adjusted basis in the liquidated limited partner interest. Your holding period for the Southwest stock should be determined by the holding period that each such participating partnership had in its assets. Because the holding period for each asset held by a participating partnership varies, each share of Southwest stock received in the merger may have a split holding period. Under the applicable provisions of the Internal Revenue Code and Regulations, a capital asset held for more than one year generally results in long-term gain or loss on the disposition of the asset. In the event you dispose of Southwest stock within a year of the merger, it may be necessary to determine if a portion of your stock has a holding period of less than one year in order to determine the appropriate tax treatment to you. In the event you sell your Southwest stock at any time after holding it for one year, all gain or loss should be considered gain or loss from an asset held for more than one year.

THESE TAX MATTERS ARE VERY COMPLICATED. THE TAX CONSEQUENCES TO YOU OF THE MERGER OF A PARTNERSHIP IN WHICH YOU OWN A LIMITED PARTNER INTEREST WILL DEPEND ON THE FACTS OF YOUR PARTICULAR SITUATION. YOU SHOULD SEEK TAX ADVICE FOR A FULL UNDERSTANDING OF THE TAX CONSEQUENCES OF THE MERGER TO YOU.

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RISK FACTORS

The merger involves certain risks. By voting in favor of the merger, you will be choosing to invest in our common stock. You should carefully consider the following risk factors, in addition to the other information included elsewhere in this prospectus/proxy statement, before deciding whether or not to vote in favor of the merger.

Risks of Participating in the Merger

The terms of the merger were determined by Southwest.     The consideration to be received by the limited partners and Southwest, as the managing general partner, was calculated using an evaluation method determined by Southwest. We, however, have inherent conflicts of interest. We determined the Merger Values of the partnerships based, in part, on the value of each of the partnership’s proved oil and gas reserves for year ended 2001, as estimated by Ryder Scott Company, L.P., which estimated values were then updated by our internal engineering staff as of July 1, 2002. We derived the Merger Value for each partnership and Southwest by using a Net Asset Value calculation of each partnership and Southwest and then dividing each entity’s Net Asset Value by the total combined Net Asset Value of all partnerships and Southwest in order to determine a percentage ownership for each partnership and Southwest. We believe that the methodology employed in determining the Merger Value is fair to the limited partners, but the determination of the Merger Value involves a conflict of interest. We hold differing percentages of limited partner interests and general partner interests in the various partnerships, and we determined the allocation of the Merger Value among the partnerships and Southwest. Additionally, as the general partner of each partnership, we have a duty to manage each partnership in the best interests of the limited partners. We also have a duty to operate our business for the benefit of our stockholders. The members of our Board of Directors have duties to both the limited partners of each partnership and to our stockholders. Mr. Wommack, our Chairman, President and Chief Executive Officer, is a significant stockholder of Southwest. Mr. Wommack also serves as a general partner of nine of the partnerships that we propose to include in the merger; provided, however, Mr. Wommack will transfer his general partner interest to Southwest for no consideration prior to the consummation of the merger. Our Board of Directors is aware of these conflicts of interest and considered them in approving the merger and determining its fairness.

No independent representative was engaged to represent the limited partners in negotiating the terms of the merger, which terms may be inferior to those which could have been negotiated by an independent representative or if the partnerships’ assets were sold to an unaffiliated third party in an arm’s length transaction.     We did not engage an independent representative, such as an investment bank, to negotiate the terms of the merger on behalf of the limited partners. The consideration which limited partners will receive in the merger may not reflect the value of the net assets of the respective partnerships if an independent third party either determined all of the elements of the merger or negotiated the terms of the merger with Southwest (as general partner) or if the assets were sold to an unaffiliated third party in an arm’s length transaction. Moreover, the determination of the Merger Value may not reflect the allocation of relative value between the limited partners and Southwest if the merger was negotiated with an unaffiliated third party in an arm’s length transaction. As a result, the Merger Value and other terms of the merger may not be as favorable as the terms which an independent representative might have obtained. We retained an independent third party to render an opinion with regard to the fairness of the merger to the limited partners and to Southwest, as the managing general partner of each partnership; however, this opinion in no way constitutes a recommendation to the limited partners for or against the merger.

Determining Merger Value involves inherent risks which cannot be fully eliminated.     Your partnership’s properties may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If this is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of your partnership in relation to Southwest and the other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to

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the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties and we can give no assurance that these assumptions will prove to be correct.

The number of shares of our common stock that the limited partners of each partnership will receive may decrease between now and the completion of the merger.     The number of shares of our common stock to be received by the limited partners of each partnership, upon consummation of the merger, will be determined by (1) calculating the Net Asset Value of each partnership and Southwest and (2) dividing each entity’s Net Asset Value by the total combined Net Asset Value of all the partnerships and Southwest to determine percentage ownership for each partnership and Southwest. We will, however, update the Merger Value for each partnership between now and the completion of the merger using revised reserve values and financial statements for the month ending immediately preceding the month in which the merger becomes effective. This recalculated Merger Value will be used to determine the actual number of shares of our common stock to be issued in the merger. The recalculated Merger Value may be more or less than the Merger Value currently attributable to your partnership and as disclosed in this prospectus/proxy statement. If it is less than the Merger Value currently attributable to your partnership, you will receive fewer shares of our common stock than the illustrations in this prospectus/proxy statement show. After             , 2002, you may either call us at 1-800-             or visit our website at www.swrpartners.com to learn the final number of shares of our common stock that you will receive.

Current market prices for oil and gas or changes in the Net Asset Value of a partnership prior to the consummation of the merger may alter the Merger Value for a partnership, which may affect the evaluation of the fairness of the merger by FBR.     Oil and gas prices have fluctuated greatly in the recent past and may continue to do so in the future. We calculated each Merger Value based on oil and gas prices that we believe to be fair and that are supported by current market prices. We also intend to revise the Merger Value of each partnership prior to the closing of the merger using updated financial statements and reserve values. Changes in current oil and gas prices or a significant change in the Net Asset Value of a partnership may affect the willingness or ability of FBR to update its opinion as to the fairness of the merger from a financial point of view at the time this prospectus/proxy statement is mailed to the limited partners of each partnership. If the prices used in the calculation of each Merger Value significantly differ from current prices and if we do not modify our offer, FBR may be unable to update its opinion as to the fairness of the merger.

You may be exchanging interests in a limited partnership which does not have and which cannot incur indebtedness for shares in a corporation which has a significant level of indebtedness, which under current terms will begin maturing on April 30, 2004.     Most of the partnerships are prohibited from incurring indebtedness. As of June 30, 2002, our indebtedness included obligations under our Senior Secured Notes due 2004 in the principal amount of $59.98 million, obligations under our 10½% Senior Notes due 2004 in the principal amount of $8.87 million, obligations under our Senior Credit Agreement with Union Bank of California, N.A. (“Union Bank”), as administrative agent for the senior lenders, in the principal amount of $55.0 million, and $1.21 million attributable to other debt.

Our level of indebtedness has several important effects on our operations, including:

• the covenants associated with our indebtedness limit our ability to borrow additional funds and to dispose of assets and affect our flexibility in planning for, and reacting to, changes in business conditions;

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• our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired; and

• a substantial portion of our cash flow is dedicated to the payment of interest on our indebtedness.

Our ability to meet our debt service obligations and to reduce our total indebtedness is dependent on our future performance, which is subject to general economic conditions and to financial, business and other factors affecting our operations, many of which are beyond our control. We cannot assure you that our future performance will not be adversely affected by such economic conditions and financial, business and other factors. Further, because of our substantial level of indebtedness, a significant portion of our cash flow is dedicated to the payment of interest on our indebtedness. In the event of unforeseen circumstances such as an economic down turn in the oil and gas industry, we may not be able to make future payments required by our indebtedness. The assets of the merged partnerships will become collateral under our existing Senior Credit Agreement and Senior Secured Notes due 2004 and will be subject to collections efforts in the event that we are unable to meet these debt payment obligations.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.     Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Exchange Act and have applied to list our common stock on Nasdaq (National Market) upon consummation of the merger, we cannot assure you that an active and liquid trading market for our common stock will develop. A stockholder cannot expect to be able to readily liquidate his investment in an emergency. Future trading prices of our common stock will depend on many factors, including, among other things, our operating results and financial condition and the market for similar securities. We cannot assure you that our listing application for Nasdaq (National Market) will be approved or that an active market for our common stock will develop. The price at which our common stock will trade will be established by the market. We cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of your partnerships assets. The Merger Value is based upon a formula used to allocate shares of common stock and special stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common and special stock to each partnership, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

Limited partners who vote against the merger are not entitled to dissenters’ or appraisal rights.     For partnerships which approve the merger, the limited partners will receive our shares of common stock even if they do not vote in favor of the merger. Under the rules adopted by the NASD, limited partners in roll-up transactions such as the merger are entitled to certain dissenters’ rights unless the sponsor adopts a 75% approval requirement for the transaction or other procedures designed to protect the rights of the limited partners. Therefore, we are requiring that the merger for each of the partnerships be approved by 75% of the outstanding limited partner interests in each partnership. If the limited partners in your partnership approve the merger by a 75% vote, limited partners will be required to accept our common stock even if they did not vote in favor of the merger.

We have never paid cash dividends on our common stock and do not anticipate paying cash dividends in the foreseeable future.     We intend to retain any future earnings to finance the expansion and continuing development of our business. Thus, pursuant to the merger, you will be exchanging your investment in a partnership that has been paying cash distributions for an investment in a corporation which does not anticipate paying any dividends or other distributions in the foreseeable future. See “COMPARISON OF RIGHTS OF SOUTHWEST STOCKHOLDERS AND THE PARTNERSHIPS’ LIMITED PARTNERS—Distributions and Dividends.” We believe that the retention and reinvestment of funds that would otherwise be distributed will have the effect of increasing the market value of our common stock; however, there can be no assurance that the value of our common stock will increase.

While our Board of Directors may review our dividend policy from time to time, it is unlikely that we will pay any dividends in the foreseeable future. The future payment of dividends, if any, on our common stock is

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within the discretion of our Board of Directors and will depend upon our earnings, capital requirements, financial position, future loan covenants, general economic conditions and other relevant factors.

There are several restrictions on our ability to pay dividends, including the following:

• certain restrictive covenants in the Indenture governing our Senior Secured Notes due 2004 and in our Senior Credit Agreement with Union Bank, as administrative agent for our senior lenders; and

• the provisions of Delaware corporation laws to which we are subject permit us to pay dividends only out of out capital surplus (the excess of net assets over the aggregate par value of our outstanding shares of capital stock) or out of net profits for the fiscal year in which the dividend is declared or the preceding year.

These requirements currently work together to effectively prohibit the payment of cash dividends on our common stock.

By participating in the merger, you will trade your interest in and control over a particular partnership and its assets for a smaller interest in Southwest, a corporation.     You will own common stock in a corporation with perpetual existence rather than a limited partner interest in a partnership with a finite life, resulting in material changes in the nature of your investment. Additionally, you currently own interests in a partnership which is subject to a single level of federal and state income taxes at the limited partner level and which was organized for the purposes of acquiring producing properties and making cash distributions to you as a limited partner. Upon consummation of the merger and in the event your partnership participates in the merger, you will become a stockholder of a corporation that is subject to income tax at both the corporate and stockholder levels, with perpetual existence and with a broad business purpose. While the rights of limited partners and stockholders are in some respects similar, there are material differences to the nature of an investment in a limited partnership and a corporation. See “COMPARISON OF RIGHTS OF SOUTHWEST STOCKHOLDERS AND THE PARTNERSHIPS’ LIMITED PARTNERS.” By taking part in the merger, you will exchange the interest you now hold in a partnership for a smaller interest in a much larger corporation. Thus, your ability to influence the taking of actions of the corporation will be reduced. The economic benefit of any extraordinary increases in value attributable to specific oil and gas properties now held by your partnerships will also be diluted because those benefits will be shared by all of our stockholders.

We anticipate needing substantial additional funding; any additional funding may dilute your stock ownership percentage in Southwest.     Our operations and business plans require substantial capital and other expenditures. We intend to seek additional funding through public and private financing, including equity offerings. Any additional equity financing may dilute the voting rights of existing stockholders. In addition, we may not be able to obtain additional capital on terms favorable to us or at all. If adequate funds are not available, our business, financial condition and results of operations will be materially adversely affected.

Potential litigation challenging the merger of a partnership may delay or block the merger and, as a result, your receipt of our stock.     One or more of the limited partners opposed to the merger of a partnership in which such limited partner owns an interest may initiate legal action to stop the merger of that partnership or to seek damages for alleged violations of federal and state laws. Litigation challenging the merger of any partnership may delay or block the closing of the merger for one or more of the partnerships. In addition, if any lawsuits are filed, we may decide to terminate the merger of one or more partnerships. If the merger of a partnership in which you own an interest is delayed, blocked or terminated, we will delay or terminate the issuance of our common stock that you would otherwise receive.

We may not realize any material cost savings as a result of the merger.     Although we believe that participation by each partnership in the merger will result in general and administrative efficiencies and cost reductions in the management and operations of the properties now owned by the partnerships, we can give you no assurance that we will be able to reduce such costs. General and administrative costs to the partnerships for

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the 12 months ended December 31, 2001 were, in the aggregate, $1.44 million and the administrative overhead fees paid to us by the partnerships for the 12 months ended December 31, 2001 were, in the aggregate, $1.84 million. The aggregate cost of the merger is estimated to be approximately $3.0 million.

Tax Risks Associated with the Merger

The IRS may successfully challenge the tax treatment of the merger.     Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES,” the Internal Revenue Service (“IRS”) may successfully challenge our characterization. The merger will involve the transfer of partnership assets and liabilities to Southwest Consolidated Partnerships and, immediately thereafter, to Southwest Managed Assets, both of which are currently wholly-owned subsidiaries of Southwest. Southwest’s surviving subsidiary in the merger may at some time in the future merge into Southwest. Limited partners will ultimately receive Southwest common stock in exchange for their limited partner interests. The IRS may attempt to re-characterize this merger as a direct merger of the partnerships with and into Southwest. A direct merger of the partnerships with and into Southwest could create a taxable event to Southwest or to the limited partners. Valid non-tax business reasons for a transaction will generally not create a re-characterization by the IRS. We believe that there are valid non-tax business reasons for structuring the merger in the manner it has been structured. Consequently, we believe that a re-characterization of the merger should not occur.

We have received an opinion of counsel relating to material income tax consequences of the proposed merger. Counsel, however, has not expressed an opinion on all consequences. No rulings have been or will be requested from the IRS with respect to the tax consequences resulting from the proposed merger, and accordingly, we can give no assurance that the IRS or the courts would agree with the opinion described in “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES.” The opinion of counsel delivered in connection with this prospectus/proxy statement is not binding on the IRS.

The partnerships presently are taxed as limited partnerships and as such do not generally pay federal income tax at the partnership level; rather, the items of income, gain, loss and deduction flow through to their partners. The limited partners will receive our common stock in the merger. Because Southwest is a corporation, our income will be taxed at the corporate level and to the extent distributions are made to the stockholders, such distributions will generally be taxable to the stockholders as a dividend. As a result of the merger, the former limited partners who become Southwest stockholders will no longer receive the pass-through tax treatment accorded to limited partners.

Certain limited partners could recognize gain from the merger.     After the merger, our wholly-owned subsidiary will own the assets and liabilities of the partnerships participating in the merger. Although you generally should not recognize gain or loss from the merger, there are risks that you may recognize gain if your allocable share of partnership liabilities exceeds your adjusted basis in your limited partner interest. It is not expected that any limited partners will recognize any gain as a result of the assumption of the partnerships’ liabilities by Southwest’s wholly-owned subsidiary.

Certain partnerships participating in the merger could recognize gain or loss from the merger.     Although the partnerships participating in the merger generally should not recognize gain or loss from the merger, there are risks that a partnership may recognize gain if the liabilities of the partnership exceed the aggregate adjusted basis of the assets transferred to Southwest. It is not anticipated that any partnership will recognize any gain from the assumption of liabilities by Southwest, but in the event gain is recognized, you will be allocated a portion of the gain as part of the closing of the tax year for the partnership.

As is true with any partnership, you should be aware that you will be required to report income from any participating partnership in which you hold an interest even though such income may be more than cash distributions received, if any. Since the participating partnerships will terminate their existence, each

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partnership’s tax year will close, and all items of income, gain, loss, deduction and credit will be allocated as required. This will occur even though you may not receive any cash distributions from the partnership for the current year.

As is true for any partnership, the IRS may challenge a partnership’s allocation of income, gain, loss, deduction and credit. Any such challenge could result in adjustments of tax items previously allocated to you and you may incur expenses in contesting adjustments to your income tax return.

Risks Related to an Investment in Southwest

Under certain business, economic and operating conditions, our collateral may not be adequate to cover our secured obligations.     Under our Senior Credit Agreement with Union Bank and certain other financial institutions, and under the terms of our Senior Secured Notes due 2004, we have granted to Union Bank, as agent for the benefit of the senior lenders and the holders of our Senior Secured Notes due 2004, continuing liens on substantially all of our assets, including our accounts receivable, equipment, inventory, negotiable collateral, oil and gas properties and real property. The assets of the partnerships that participate in the merger will be included in this collateral. In the event we fail to pay our obligations under these debt instruments, Union Bank may foreclose on our collateral, including the properties from any partnership that participates in the merger.

You will have limited voting control.     As of September 30, 2002, Regiment Capital Advisors, LLC owned 12.15%, Franklin Mutual Advisers, LLC owned 32.22%, and Southwest Royalties Holdings, Inc. (“SRH”), our former parent, owned 10% of our outstanding voting capital stock. Upon consummation of the merger, assuming participation by all partnerships, the Class A stockholders and SRH will collectively own 60% of our outstanding shares of common stock. Therefore, these stockholders may be able to influence the outcome of stockholder votes on various matters, including the election of directors, extraordinary corporate transactions, and certain business combinations.

We depend heavily on the services of key personnel, and the loss of their services could have an adverse effect on our operations.     We depend to a large extent on the services of certain senior management personnel. The loss of the services of our senior management could have a material adverse effect on our operations. Although we maintain certain key man life insurance policies on senior management, the existence of such insurance does not mean that the death or disability of one of our members of senior management would not have a materially adverse effect upon us.

We may be required to purchase all of our Senior Secured Notes due 2004 upon a change of control. Upon the occurrence of a “change of control,” which is defined in the Indenture governing our Senior Secured Notes due 2004 as the sale, lease or transfer of all of our assets, a merger in which we are not the controlling or surviving company after the merger, a liquidation or dissolution or any transaction the result of which is that any person becomes the beneficial owner of more than 50% of our total voting power, each holder of the Senior Secured Notes due 2004 may require us to purchase all or a portion of such holder’s notes at 101% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of purchase. If a change of control were to occur, we may not have the financial resources to repay all of the Senior Secured Notes due 2004 and the other indebtedness that might become payable upon the occurrence of such change of control.

Our hedging transactions may limit our potential gains.     In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we have in the past and may in the future enter into oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedging arrangements may include futures contracts on NYMEX. While intended to reduce the effects of volatile oil and natural gas prices, such transactions may limit our potential gains if oil and natural gas prices were to rise

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substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

• our production is less than expected;

• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

• the counter-parties to our future contracts fail to perform the contracts; or

• a sudden, unexpected event materially impacts oil or natural gas prices.

Certain provisions of Delaware law and our Amended and Restated Certificate of Incorporation and Bylaws may inhibit changes in control of Southwest and our Board of Directors and may have the effect of depriving stockholders of receiving a premium over the prevailing market price of their shares of common stock in the event of an attempted hostile takeover.    These provisions include “blank check” preferred stock, advance notice bylaws and the Delaware Business Combination Statute. See “DESCRIPTION OF OUR CAPITAL STOCK—Anti-Takeover Effect of Delaware Law and our Amended and Restated Certificate of Incorporation and Bylaw Provisions.” The existence of these provisions may impede the marketability and market price of our common stock.

Risks Associated with our Business Activities

Revenues from our operations are highly dependent on the price of oil and gas.     The markets for oil and gas are volatile. Prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas and a variety of additional factors that are beyond our control. These factors include the level of consumer demand, weather conditions, domestic and foreign governmental regulations, market uncertainty, the price and availability of alternative fuels, political conditions in the Middle East and elsewhere, foreign supply of oil and gas, price of foreign imports and overall economic conditions. Between January and July 2002, the price of oil per barrel has fluctuated from a low of $19.64 to a high of $29.42, and the price of gas per Mmbtu has fluctuated from a low of $2.14 to a high of $3.80. It is impossible for us to predict future oil and gas prices with any certainty.

In order to reduce our exposure to price risks in the sale of oil and gas, we enter into hedging arrangements from time to time. The hedging arrangements, however, only apply to a portion of our production and provide only limited price protection against fluctuations in the oil and gas markets.

We use the full cost method of accounting for our investment in oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas reserves are capitalized into a “full cost pool” as incurred, and properties in the pool are depleted and charged to operations using the gross revenues method based on the ratio of current gross revenues to total proved future gross revenues, computed based on current prices. Significant downward revisions of quantity estimates or declines in oil and gas prices that are not offset by other factors could result in a write-down for impairment of oil and gas properties. Once incurred, a write-down of oil and gas properties is not reversible at a later date, even if oil or natural gas prices increase.

Our future performance depends upon our ability to find or acquire additional oil and gas reserves that are economically recoverable.     Unless we successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and gas production and lower revenues and cash flow from operations. While we believe that we can replace reserves through drilling and acquisitions, we may not be able to replace such reserves at acceptable costs. Under many of the partnership agreements, the partnership is currently prohibited from drilling. After consummation of the merger, we expect to engage in drilling on many of the properties formerly in these partnerships. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to maintain or expand our oil and gas reserves if cash flow from operations is reduced, due to lower oil and gas prices or otherwise, or if external

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sources of capital become limited or unavailable. In addition, our drilling activities will be subject to numerous risks, including the risk that no commercially productive oil or gas reserves will be encountered. Exploratory drilling involves more risk than developmental drilling because exploratory drilling is designed to test formations for which proved reserves have not been discovered.

Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered.     We may not be successful in future drilling activities and such failures will have an adverse effect on our future results of operations and financial condition. In addition, the cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions;

• title problems; and

• shortages or delays in the delivery of equipment.

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition.

We experience intense competition in our market, and no one competitor is dominant.     We compete with major and independent oil and gas companies for the acquisition of desirable oil and gas properties as well as for the equipment and labor required to develop and operate such properties. We also compete with major and independent oil and gas companies in the marketing and sale of oil and gas to marketers and end-users. Although we believe that we have certain advantages over these competitors, some of these competitors have greater financial and other resources than we have.

We may not be able to sell all of the oil and gas we produce.     The marketability of our oil and gas production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities. If such capacity is not available, we might have to shut-in producing wells or delay or discontinue development plans for properties. In addition, federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and gas on a profitable basis.

Our estimates of reserves and future net revenue may differ from actual results.     Estimating oil and gas reserves and their values involves numerous uncertainties, including many factors beyond our control. The reserve information set forth in this prospectus/proxy statement is only an estimate. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas which cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including the following:

• historical production from the area compared with production from other producing areas;

• the assumed effects of regulation by governmental agencies; and

• assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs.

Because of the variable factors and assumptions involved in the estimation of reserves, different engineers or the same engineers at different times may reach substantially different results in their estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, their classification of reserves based on risk recovery and their estimates of the future net cash flows expected from

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reserves. In addition, reserve estimates may be adjusted downward or upward because of changes in such factors and assumptions.

Because all reserve estimates are subjective to some degree, each of the following items may differ materially from those assumed in the estimated reserves:

• the quantities of oil and gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future oil and gas prices.

The present values of estimated future net cash flows referred to in this prospectus/proxy statement should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

• the amount and timing of actual production;

• supply and demand for oil and gas;

• curtailments or increases in consumption by gas purchasers; and

• changes in governmental regulations or taxation.

The timing of actual future net cash flows from proved reserves, and their actual present value, will be affected by both the timing of the production and the incurrence of expenses in connection with development and production of oil and gas properties.

We are subject to numerous environmental regulations, and our failure to comply with those regulations either now or in the future could result in substantial liability or suspension of operations.    Extensive federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment affect our oil and natural gas operations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, with which compliance is often difficult and costly and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. Environmental laws and regulations, however, have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position.

We are subject to a number of operating risks which may or may not be covered by insurance.    The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. Any of these occurrences could result in substantial losses to us due to injury or loss of

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life, severe damage to or destruction of property, natural resources and equipment, environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating or other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, mechanical problems, compliance with governmental requirements and shortages and delays in the delivery of equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our future results of operations and financial condition.

Although we maintain insurance coverage considered to be customary in our industry, we are not fully insured against certain risks, either because insurance is not available or because of the high premium costs. We maintain physical damage, employer’s liability, comprehensive commercial general liability, workers’ compensation insurance and sudden and accidental environmental damage liability insurance. There can be no assurance that any insurance obtained by us will be adequate to cover any losses or liabilities, or that such insurance will continue to be available or available on terms that are acceptable to us.

Our operations are subject to significant government regulation which may change over time.    Our oil and gas operations are subject to various federal, state and local governmental laws and regulations that may change in response to economic or political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds or other financial responsibility requirements, reports concerning operations, the spacing of wells, utilization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and production limitations to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation and disposal of oil and gas, their by-products and other substances and materials produced or used in connection with oil and natural gas operations are regulated under federal, state and local laws and regulations relating to the protection of health and the environment. These laws and regulations may impose increasingly strict requirements for water and air pollution control and solid waste management. Our failure to meet such requirements could result in civil and even criminal penalties.

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BUSINESS OF SOUTHWEST ROYALTIES, INC.

Our Company

Background

Formed in 1983 as a Delaware corporation, we are an independent oil and gas company engaged in the acquisition, development and production of oil and gas properties. Our primary operations are in the Permian Basin, where approximately 95% of our properties and wells are located. We have grown primarily through selective acquisitions of producing oil and gas properties, drilling and development, both directly and through the partnerships we manage. Our oil and gas properties exhibit long-lived production and multiple pay intervals. Our history of operations in the Permian Basin provides us with operational and strategic competitive advantages as well as growth opportunities.

We initially financed the acquisition of oil and gas reserves and our exploration and development efforts through public and private limited partnership offerings. We are a general partner of these limited partnerships, own interests in these partnerships and receive management fees and operating cost reimbursements from these partnerships. Since 1983, we have completed over $250.0 million of oil and gas properties acquisitions, both directly and through the limited partnerships we manage. As of July 1, 2002, we had total estimated net proved reserves of 20.5 MMBbls of oil and 78.0 Bcf of natural gas, aggregating 33.5 MMBoe, with a PV-10 Value of $220.0 million. The reserve estimates at July 1, 2002 assume a NYMEX oil price of $26.86 per Bbl with an average adjusted price, reflecting adjustments for oil quality and gathering and transportation costs, of $25.04 per Bbl and a NYMEX gas price of $3.25 per Mcf with an average adjusted price, reflecting adjustments for BTU content, gathering and transportation costs and gas processing and shrinkage, of $2.97 per Mcf.

Our proved reserves have the following characteristics:

• the half-life of our reserves is approximately 8 years;

• our R/P (reserve total divided by production rate) is 16 to 18 years; and

• classification of reserves as of July 1, 2002 based upon PV-10 Value:

60.3% is proved developed producing;

10.5% is proved developed non-producing; and

29.2% is proved undeveloped.

As shown above, our development projects are located primarily in shallow to intermediate depth (normally pressured reservoirs), resulting in moderate drilling and completion costs. Many of these development projects contain multiple producing oil and gas horizons that are potentially productive, further reducing our developmental drilling risk. As a result of our history of acquiring oil and gas properties, we have a significant inventory of potential drilling opportunities. Our inventory of non-producing reserves, which is primarily located in the Permian Basin, gives us development growth potential in a geographic area where we currently operate most of our properties and therefore have expertise.

As of September 30, 2002, we had only one subsidiary, Blue Heel Company. Blue Heel Company holds a nominal interest in certain oil and gas properties owned by Southwest. Effective August 2000, Midland Southwest Software, Inc., our former subsidiary, was merged into Southwest. Effective November 1999, Threading Products International, LLC, our former subsidiary, was liquidated. In connection with the merger, we have formed two wholly-owned subsidiaries, Southwest Consolidated Partnerships and Southwest Managed Assets.

Our Operations

Southwest has been in the oil and gas industry for nearly 20 years and operates from Midland, Texas. As an independent oil and gas company and as the managing general partner for numerous public and private limited

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partnerships, Southwest operates over 1,400 wells and oversees the production and distribution of approximately 6,700 barrels of oil equivalents per day. Southwest employs 89 professional and support personnel, including geologists, landmen, field supervisors, field foreman, pumpers, accountants and engineers. Additionally, we use approximately 29 contract pumpers. These team members are vital to the overall operation of Southwest and its various oil and gas interests.

Southwest’s operations involve the purchase of several different kinds of interests in various types of producing or non-producing oil and gas properties. In most instances, Southwest will purchase a working interest in leases for properties on which oil and gas are already being produced. A working interest entitles the holder of the interest to receive, in kind or in value, a share of the production from the lease and bear a proportionate share of all associated costs. A smaller portion of Southwest’s leasehold interests may be invested in royalty or overriding royalty interests which entitle the holder to a share of the production of oil and gas without any obligation to bear the associated costs of operation, other than local, state and federal taxes.

In determining whether a particular property should be acquired by Southwest, or retained in its inventory, Southwest considers criteria such as estimated reserves and reserve life, estimated cash flow from the sale of production, present and projected future market prices for oil and gas, the extent and probability of undeveloped and unproved reserves, the potential for secondary, tertiary and other enhanced recovery projects and the availability of markets for oil and gas production nearby. The ultimate profitability of a property acquired by Southwest is, of course, subject to numerous contingencies, such as changing governmental regulation, the shutting in or curtailment of wells, and the depletion and market for oil and gas. The success of Southwest’s activities depends largely on its ability to evaluate the properties and manage them to profitability.

Potential acquisitions of properties are most often identified through ongoing research conducted by Southwest, as well as industry contacts, financial institutions and other sources in the oil and gas industry. The evaluation process of a property is conducted by the technical and financial staff of Southwest. The initial phase of evaluation consists of applying technical and economic criteria to information and data supplied by the seller of the property or by Southwest itself, if it is evaluating whether to retain a particular property. This information may consist of independent engineering reports, discounting cash flow analysis, production curves and other technical and geological data. Using this data and that obtained from other independent sources (primarily state conservation departments), a preliminary estimate of a range of probable market values or property economics is determined. Using this range, a determination of interest in the acquisition (to purchase or to retain) or the desire and probability of a successful sale is made. In the event of a sale or divestiture and the preliminary range is outside of the seller’s or buyer’s parameters, further investigation, analysis and discussion may be necessary to determine the basis of the proposed asking price. If there is a reasonable chance of acquisition success, a detailed review of the bid parameters to be made and the suitability of the acquisition or divestiture may be further evaluated.

If it is determined by Southwest that it has an interest in acquiring a particular property or in divesting such a property, the screening process continues by Southwest and, in certain situations, an independent expert is engaged by Southwest to prepare a report on the acquisition or divestiture. This independent expert will perform an analysis of the property’s performance and will make an estimate of the nature and extent of proved reserves and, in particular, the proved developed producing reserves, if any. The technical staff of Southwest will prepare acquisition or divestiture reports with respect to any property or group of properties unless, because of the location or because of other characteristics with which the technical staff is not familiar, an outside independent expert is engaged.

The final phase of the screening process consists of another review by Southwest’s technical and financial staff (or in certain instances by an independent expert) of the analysis of the other reserve data to determine the estimated market value of the property. Southwest’s staff will then apply investment criteria to the acquisition or divestiture target in order to test cash flow assumptions relating to a particular property and, in certain instances, will perform a production and price sensitivity analysis. The application of these criteria may change from time

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to time and vary from property to property. Risk adjustment factors are used to adjust for uncertainties and contingencies such as product pricing, market conditions, mechanical failure, production curtailment and reserve estimate techniques. These criteria are constantly evaluated, reviewed and adjusted as often as market conditions and other factors dictate.

Title to Southwest’s properties is taken and held in the name of Southwest or, in some cases, in the name of a special nominee entity organized for the sole purpose of holding record title. These nominee companies engage in no other business and incur no other liabilities. As is customary in the oil and gas industry, title examination is conducted with respect to each property which is in the inventory of Southwest or which is proposed to be acquired. This review generally consists of checking the records of title at the courthouse of the county in which the property is located and the files maintained by Southwest itself or by the seller of the producing property in order to determine whether adequate documentation of title data furnished by the seller can be verified through comparison of recorded documents, title opinions, division orders and other relevant records. In the case of an acquisition of a property involving the commitment of a substantial amount of Southwest’s funds, a complete title examination will be conducted in order to determine the existence of any material liens, burdens or exceptions to title, and a formal written opinion will be procured from independent legal counsel. Southwest’s strategy is generally to hold interests in properties for the long term; however, these interests are sold from time to time if the price for the interest and/or the cost of maintaining the property warrants such a sale.

Increases or decreases in production revenue depend primarily on changes in the prices received for production, changes in volumes of production sold and the depletion of wells. Revenue increases could result from well improvement projects that enhance production. Since wells deplete over time, production can generally be expected to decline toward the end of a well’s lifespan. Well operating costs, as well as administrative and direct costs, usually do not decrease proportionately with production decline. Net income available for Southwest decreases as properties are depleted. Hence, it is critical for Southwest to continue to renew its oil and gas reserves to maintain constant, and improving, cash flow and net income.

Typically, Southwest reviews and selects properties which it believes are suitable for the long-term goals of Southwest to develop and build its reserves and maintain consistent cash flows. Field operations for Southwest’s properties are conducted usually under the terms of operating agreements. These operating agreements usually follow the model form of operating agreement approved by the American Association of Petroleum Landmen. Operations on Southwest’s properties are conducted either by Southwest, itself, or by operators retained by holders of a majority of the working interests in each of the wells in which Southwest owns an interest. In most instances, there will be third party working interest owners in addition to Southwest, who will be parties to such operating agreements.

The operating agreements generally provide for the operator to assume day-to-day responsibilities for production, recovery and sale of oil and gas produced from a producing property. The operator will be reimbursed for its direct charges incurred in operating a producing property in addition to a monthly overhead charge based upon competitive conditions in the geographic area. These charges will be incurred regardless of whether an unaffiliated party or Southwest is the operator. The terms of operating agreements entered into by Southwest are in conformity with the model operating agreements, including any accounting procedures for joint operations issued by the Council of Petroleum Accountants Societies of North America.

The majority of our oil is stored in tank batteries on location and sold to crude oil gathering companies. The major companies purchasing oil from us are Plains All American Pipeline, L.P., ExxonMobil and BP Amoco. We have recently experienced a $1.11-1.83 discount to NYMEX oil pricing. All natural gas is sold to pipelines. Pipeline companies generally own the lease gathering systems. The major pipeline purchasers are Duke Energy and Sid Richardson. Meters are installed on every gas well to ensure that working interests are properly accounted for. Most of our gas is sold through percentage of proceeds contracts. We receive a percentage of the revenue from the pipeline company’s sale of natural gas and associated NGLs. These proceeds contracts vary

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from lease to lease; however, most result in our receiving between 75% and 90% of the proceeds. We have recently experienced a $0.15-0.40 discount to NYMEX natural gas pricing.

Seasonality of Business

Our business is not seasonal, except that the demand for natural gas is higher in the colder winter months and in very hot summer months. We have been able to sell all of our natural gas, either through contracts in place or on the spot market at the then prevailing spot market price. As a result, the volumes sold by us have not fluctuated materially with the change of season.

Inventory of Drilling Opportunities

As a result of our history of acquiring oil and gas properties, we believe that we have a large inventory of developmental opportunities. These projects, if we are able to develop them, may provide significant production gains over a number of years at relatively low finding costs.

Potential Acquisitions

Major and large independent oil and gas companies have generally decided to focus their operations in geographic areas other than the Permian Basin in order to explore more significant reserve opportunities found off-shore or in foreign countries or they have consolidated with companies outside the Permian Basin. Continued consolidation in the oil and gas industry provides potential acquisition opportunities for Southwest in the Permian Basin. As a result of our past history of acquiring properties, we have established a network to take advantage of these opportunities. We also have significant experience in the assimilation of both large and small oil and gas properties and companies.

Repurchase of 10½% Senior Notes

On October 15, 1997, we completed a $200.0 million private placement of 10½% Senior Notes due 2004, Series A, which were offered and sold by underwriters only to qualified institutional buyers. On March 11, 1998, we concluded a registered offering to exchange the Series A Notes for 10½% Senior Notes due 2004, Series B, which had been registered under the Securities Act. The form and terms of the Series B Notes were identical in all material respects to the form and terms of the Series A Notes.

On March 5, 2002, we commenced an offer for $123.685 million aggregate principal amount of those 10½% Senior Notes, which represented all of the 10½% Senior Notes then outstanding, plus any interest accrued but not paid thereon, in exchange for $60.0 million principal amount of Senior Secured Notes due 2004 and 900,000 shares of our Class A common stock. On April 19, 2002, our offer to exchange the 10½% Senior Notes expired, with holders of $114.815 million principal amount of the 10½% Senior Notes tendering in exchange for the Senior Secured Notes and the Class A common stock. As of September 30, 2002, $8.87 million aggregate principal amount of the 10½% Senior Notes remained outstanding.

The Merger

The merger will add significant existing production and cash flow to our operations, as well as a substantial inventory of development projects. The partnerships’ projects are generally in the same or adjacent oil and gas fields as our oil and gas properties.

As a result of restrictions imposed by most of the partnership agreements, we have been unable to exploit developmental opportunities on the partnerships’ properties for the last 15 years, resulting in a build-up of potential projects. We have identified numerous opportunities for development of the partnerships’ properties.

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At July 1, 2002, our oil and gas properties had the following characteristics, with and without the merger:

	Southwest	Southwest Upon Completion of the Merger (Assuming 100% Participation)
Interests Owned	133,725 net leasehold acres	154,400 net leasehold acres
Estimated Proved Reserves
Crude Oil	20.5 MMBbls	23.8 MMBbls
Natural Gas	78.0 Bcf	93.5 Bcf
Total Equivalent	33.5 MMBoe	39.4 MMBoe
PV-10 Value	$220.0 million	$256.7 million
Proved Developed Reserves % of PV-10 Value	70.8%	72.3%

Our Strategy

Our objective is to increase our revenues, cash flow, earnings and reserves through the efficient development and exploitation of our inventory of projects and continued oil and gas property acquisitions in the Permian Basin.

Develop and exploit existing oil and gas properties

• We have a diversified portfolio of oil and gas properties that contain numerous identified development opportunities.

• We believe that current oil and gas prices have improved the attractiveness of accelerated development of these properties. We plan to increase our capital spending during the remainder of 2002 and in 2003 to pursue these opportunities, which consist principally of infill drilling, recompletions, enhanced recovery operations and workover opportunities.

• The partnership agreements of the partnerships do not allow for meaningful exploratory or developmental drilling. The merger and the resulting termination of the partnership agreements will allow for the full exploitation of the partnerships’ undeveloped assets.

Acquire producing oil and gas properties

• We will focus on acquisitions that provide opportunities for the addition of reserves, production and cash flow through operational improvements, production enhancement and additional development. We believe properties meeting these criteria are available in the Permian Basin due to the region’s long history of production and multiple producing oil and gas horizons.

• Major and large oil and gas companies have decided to focus their operations in geographic areas other than the Permian Basin in order to explore more significant reserve opportunities found off-shore or in foreign countries or they have consolidated with companies outside the Permian Basin. Additionally, limited access to liquidity through the capital markets and reduced availability on commercial bank lines have resulted in an increase in attractive acquisition opportunities offered by independent oil and gas companies seeking additional liquidity. We intend to pursue these acquisition opportunities.

Maintain Operations and Cost Controls

• Our oil and gas activities are located in the Permian Basin, with properties in this region representing 93% of our PV-10 Value at July 1, 2002. Our focus on the Permian Basin allows us to build upon our region-specific geological, engineering and production experience.

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• We operated 71% of our PV-10 Value as of July 1, 2002. Our significant control of operations and geographic focus have resulted in substantial operating economies of scale that have enabled us to maintain a low cost structure.

Our Principal Oil and Gas Properties

Our oil and gas properties are primarily located in the Permian Basin. Approximately 93% of our PV-10 Value is concentrated in this region at July 1, 2002. The region is characterized by numerous known producing horizons, providing significant opportunities to increase reserves, production and ultimate recoveries through additional development, horizontal drilling, recompletions, enhanced recovery methods and the use of 3-D seismic, reprocessed 2-D seismic data and other advanced technologies. As of July 1, 2002, we operated properties comprising approximately 71% of our PV-10 Value, giving us substantial control over the incurrence and timing of capital and operating expenditures.

The following table provides information for our ten largest fields which contribute 62% of our reserves and 62% of our PV-10 Value as of December 31, 2001.

	As of December 31, 2001
Field	Net Proved Reserves (MBoe)(1)	PV-10 Value (in thousands)		% of Total PV-10 Value
Huntley	2,521	$	13,485	9.40	%
Jo-Mill	2,226	$	12,373	8.63	%
Signal Peak	2,027	$	10,106	7.04	%
Foster	2,120	$	9,858	6.87	%
Huntley East	1,920	$	9,269	6.46	%
Ackerly	2,044	$	8,235	5.74	%
Halley	2,186	$	7,861	5.48	%
Flying M	2,419	$	7,503	5.23	%
Magnolia Sealy	1,248	$	5,249	3.66	%
Amacker Tippett	1,091	$	4,747	3.36	%
Total Top Ten Fields	19,802	$	88,686	61.87	%

⁽¹⁾ Does not include liquids associated with the production of gas products.

Huntley Field.    The Huntley Field is located in Garza County, Texas. The field was discovered in 1953 and produces from the San Andres and Glorieta reservoirs. We own an 87% working interest and operate 34 producing and 21 injection wells.

Jo-Mill Field.    The Jo-Mill Field is located in Borden County, Texas. The field was discovered in 1954, unitized in 1969, and produces from the Upper Spraberry, Lower Spraberry and Dean Sand reservoirs. We own a 6% working interest in the Jo-Mill Unit. Texaco, Inc. operates 172 producing and 73 injection wells.

Signal Peak.    The Signal Peak Field is located in Howard County, Texas. The field was discovered in 1997 and produces from the Wolfcamp formation. We own working interests ranging from 15% to 62% in 28 producing gas wells. Development plans include drilling an additional 9 developmental gas wells.

Foster Field.    The Foster Field is located in Ector County, Texas. The field was discovered in 1936 and produces from the Grayburg and Queen formations in the Gist Unit. We own working interests ranging from 59.5% to 100% and operate 68 producing and 31 injection wells. Numerous workover and developmental drilling opportunities exist.

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Huntley East Field.    The Huntley East Field is located in Garza County, Texas. The field was discovered in 1956 and produces from a low-relief anticline which covers approximately 1,400 surface acres. We have a 100% working interest in the Huntley East San Andres Unit, which comprises substantially the entire field, a 100% working interest in the Harold L. Davies lease, and operate 38 producing and 21 injection wells.

Ackerly (Dean) Field.    The Ackerly (Dean) Field is located in Dawson County, Texas and produces from the Dean Sand oil reservoir. The field was discovered in 1954 with the drilling and completion of the Pan American Graves “A” No. 1 well. We own a 60% working interest in the East Ackerly Dean Unit-Phase II, along with interests in two additional leases. Henry Petroleum operates 70 producing and 30 injection wells.

Halley Field.    The Halley Field is located in Winkler County, Texas and consists of two leases totaling 7,608 gross acres, of which 3,190 gross acres have been developed. We acquired working interests ranging from 43% to 70% in this field in 1995 and currently operate 110 active producing wells and 32 water injection wells. The field was discovered in 1937 and produces from multiple zones ranging from 2,400 to 3,000 feet in depth. Development plans, which have commenced, include the drilling of several proved undeveloped locations and numerous workovers.

Flying M Field.    The Flying M Field is located in northern Lea County, New Mexico and produces from the San Andres oil reservoir. The field was discovered in 1964 and was unitized in 1967 when water injection commenced. In 1997, we acquired working interests ranging from 83% to 100% in 6,160 gross acres of the field area, of which 2,240 gross acres are undeveloped. We operate all 46 producing wells and nine active water injection wells, including wells that are not contained within the unitized portion of the field. Development plans for this field include the drilling of ten 40-acre proved undeveloped locations and the conversion of ten wells to water injection. Further development of the field, including the reduction to 20-acre spacing from the current 40-acre spacing, is presently under evaluation.

Magnolia Sealy Field.    The Magnolia Sealy Field is located in Ward County, Texas and produces primarily from the Yates formation. Pay depths range from 2,400 to 3,100 feet. The field was discovered in 1940 and sparsely developed throughout the late 1940’s. We have an average working interest of 90%. We purchased the properties in 1988 and drilled 9 wells to date. Results of drilling indicate primary reserve additions of 45 to 55 MBO per well. Additional potential exists both through developmental drilling prospects and initiation of a waterflood.

Amacker Tippett Area.    The Amacker Tippett area is located in Upton County, Texas. The area is a multi-pay area with wells producing from the Bend, Wolfcamp, Devonian and Fusselman formations. We own working interests ranging from 8% to 69% in the area. Developmental drilling and workovers are planned for the area.

Our Oil and Gas Reserves

The following table summarizes the estimates of our historical net proved reserves and the related present values of such reserves at the dates shown. The reserve and present value data for our existing properties as of December 31, 2001, 2000, and 1999 were audited by Ryder Scott Company, L.P. The reserve and present value data for our existing properties as of July 1, 2002 were prepared by our internal staff of engineers.

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	As of June 30, 2002			As of December 31,
				2001			2000			1999
Proved Reserves:
Oil and Condensate (MBbls)		20,484			19,937			25,797			24,828
Natural Gas (MMcf)		78,017			74,783			70,374			65,078
Total (MBoe)		33,487			32,401			37,526			35,674
Proved Developed Reserves:
Oil and Condensate (MBbls)		15,001			14,274			18,161			16,618
Natural Gas (MMcf)		50,503			50,251			46,592			43,023
Total (MBoe)		23,418			22,649			25,926			23,789
PV-10 Value (in thousands) (1)	$	220,008		$	143,455		$	473,457		$	228,748
Discounted Future Cash Flows (2)
Future cash flows	$	745,262		$	544,205		$	1,342,066		$	727,615
Future production and development costs	$	(307,955	)	$	(259,063	)	$	(415,022	)	$	(284,354	)
Future net cash flows before income taxes	$	437,307		$	285,142		$	927,044		$	443,261
Future income tax expense	$	(125,783	)	$	(53,417	)	$	(274,566	)	$	(103,067	)
Future net cash flows, net of tax	$	311,524		$	231,725		$	652,478		$	340,194
10% annual discount for estimated timing of cash flows	$	(158,951	)	$	(113,660	)	$	(319,246	)	$	(164,634	)
Standardized measure of discounted future net cash flows, net of tax	$	152,573		$	118,065		$	333,232		$	175,560

⁽¹⁾ The present value of future net revenues attributable to our reserves was prepared using prices in effect at the end of the respective periods presented, discounted at 10% per annum on a pre-tax basis.

⁽²⁾ Discounted future cash flows, including taxes, are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and gas prices, interest rate, changes in development and production costs and risks associated with future production. Because of these considerations, any estimate of fair value is necessarily subjective and imprecise.

In accordance with applicable requirements, estimates of our proved reserves and future net revenues are made using oil and natural gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation.) The average prices used in the reserve report were $25.04/Bbl of oil and $2.97/Mcf of natural gas, $18.44/Bbl of oil and $2.36/Mcf of natural gas, $25.62/Bbl of oil and $9.68/Mcf of natural gas and $23.90/Bbl of oil and $2.06/Mcf of natural gas as of June 30, 2002 and December 31, 2001, 2000 and 1999, respectively.

Estimated quantities of proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. In general, the volume of production from oil and natural gas properties decline as reserves are depleted. Except to the extent we acquire properties containing

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proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves. Exploring for, developing or acquiring new reserves requires substantial amounts of capital.

Net Production, Unit Prices and Costs

The following table presents certain information with respect to oil and gas production, prices and costs attributable to all oil and gas property interests owned by us for the six months ended June 30, 2002 and for the years ended December 31, 2001, 2000 and 1999:

	For the Six Months Ended June 30, 2002			For the Year Ended December 31,
				2001		2000		1999
Production Volumes:
Oil and condensate (MBbls)		561			1,227		1,236		1,306
Natural gas (MMcf)		2,381			5,119		4,784		4,627
Total (MBoe)		958			2,080		2,033		2,077
Average Daily Production:
Oil and condensate (Bbls)		3,101			3,361		3,376		3,578
Natural Gas (Mcf)		13,156			14,025		13,070		12,677
Total (Boe)		5,294			5,698		5,555		5,691
Average Realized Prices:
Oil and condensate (per Bbl)	$	22.43		$	24.88	$	28.56	$	16.23
Natural gas (per Mcf)	$	2.57		$	3.91	$	3.89	$	2.19
Per Boe	$	19.51		$	24.29	$	26.51	$	15.09
Expenses (per Boe):
Lease operating (including production taxes)	$	7.36		$	8.56	$	7.45	$	5.22
Oil and gas depletion	$	3.35		$	4.66	$	2.46	$	2.36
General and administrative (“G&A”), net	$	2.09	(1)	$	1.51	$	1.25	$	.78

⁽¹⁾ G&A included approximately $1.0 million of non-cash expenses attributable to the exchange of a note receivable from an officer and stockholder of Southwest in return for stock in a privately held company which collateralized the note. G&A without the non-cash expense was $1.07 per Boe.

Producing Wells

The following table sets forth the number of productive wells in which we owned an interest as of December 31, 2001:

	Gross Wells	Net Wells
Oil	6,552	643
Natural Gas	718	87
Total	7,270	730

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections and oil wells awaiting connection to production facilities. Wells that are completed in more than one producing horizon are counted as one well. A gross well is a well in which an interest is owned. A net well is the fractional working interest in a gross well. The number of net wells is the sum of the fractional interest owned in gross wells.

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Acreage

The following table sets forth our developed and undeveloped gross and net leasehold acreage as of December 31, 2001:

	Gross	Net
Developed	89,822	28,206
Undeveloped	296,212	101,725
Total	386,034	129,931

Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is the fractional working interest in a gross acre. The number of net acres is the sum of the fractional interests owned in gross acres.

Drilling Activities

The table below sets forth our drilling activity on our properties for the periods ending December 31, 2001, 2000, and 1999.

	Year Ended December 31,
	2001		2000		1999
	Gross	Net	Gross	Net	Gross	Net
Developmental wells:
Productive	54.0	18.1	28.0	11.2	12.0	5.1
Non-productive	—	—	4.0	1.0	1.0	9.0
Total	54.0	18.1	32.0	12.2	13.0	6.0
Exploratory wells:
Productive	—	—	3.0	6.0	—	—
Non-productive	2.0	1.3	—	—	—	—
Total	2.0	1.3	3.0	6.0	—	—

Our Principal Executive Offices

Our principal executive offices are located at 407 North Big Spring, Suite 300, Midland, Texas 79701, and our telephone number is (915) 686-9927. We own a 22,000 square foot building in which we occupy approximately 11,000 square feet and lease the remaining space to outside parties. We lease an additional 23,004 square feet of an adjacent building. Our website is located at www.swrinc.com. Information contained on our website is not part of this prospectus/proxy statement.

Customers

During 2001, Conoco, Inc. accounted for 26.9% and Duke Energy Services accounted for 12.23% of our consolidated revenues. No other customer accounted for 10% or more of our consolidated revenues during 2001. We do not believe the loss of any purchaser would have a material adverse effect on our operations, revenues or cash flow.

Legal Proceedings

From time to time, we are party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. We are not involved in any legal proceedings nor are we party to any pending or threatened claims that could reasonably be expected to have a materially adverse effect on our financial condition, cash flow or results of operations.

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Employees

As of December 31, 2001, we employed 89 people, including our own Information Technology personnel. We have developed and own our oil and gas accounting and management software. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel in spite of our current financial difficulties. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

Competition

The oil and natural gas industry is highly competitive. Our oil and gas business competes for the acquisition of oil and natural gas properties, primarily on the basis of the price to be paid for such properties, with numerous entities including major oil companies, other independent oil and natural gas concerns and individual producers and operators. Many of these competitors are large, well established companies and have financial and other resources substantially greater than ours.

Our ability to acquire additional oil and gas properties and to discover reserves in the future will depend upon our ability to restructure debt facilities and/or procure non-recourse funding as well as our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Financial Information about Geographic Areas

Since inception our revenues are attributed to customers located only in the United States. Since inception our long-lived assets, long-term customer relationships of financial institutions, mortgages and other servicing rights, deferred policy acquisition costs and deferred tax assets are located only in the United States.

Operating Hazards and Risks

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. Any of these occurrences could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating or other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, mechanical problems, compliance with governmental requirements and shortages and delays in the delivery of equipment and services. Our future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our future results of operations and financial condition.

Although we maintain insurance coverage considered to be customary in each industry in which we participate, we are not fully insured against certain risks, either because insurance is not available or because of the high premium costs. We do maintain physical damage, employer’s liability, comprehensive commercial general liability and workers’ compensation insurance. There can be no assurance that any insurance obtained by us will be adequate to cover any losses or liabilities, or that such insurance will continue to be available or available on terms which are acceptable to us.

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Regulation

General.     Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In the past, the federal government has regulated the prices at which oil and natural gas could be sold. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”). The Decontrol Act removed all remaining NGA and NGPA price and nonprice controls affecting wellhead sales of natural gas effective January 1, 1993.

Regulation of Sales and Transportation of Natural Gas.     Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. While the United States Court of Appeals upheld most of Order No. 636, certain related FERC orders, including the individual pipeline restructuring proceedings, are still subject to judicial review and may be reversed or remanded in whole or in part. While the outcome of these proceedings cannot be predicted with certainty, we do not believe that we will be affected materially differently than our competitors.

The FERC has also announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service rate making methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. In February 1997, the FERC announced a broad inquiry into issues facing the natural gas industry to assist the FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. Similarly, the Texas Railroad Commission has been reviewing changes to its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes being considered by these federal and state regulators would affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters, however, we do not believe that it will be affected by any action taken materially differently than other natural gas producers with which it competes.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Oil Price Controls and Transportation Rates.     Sales of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market.

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Environmental and Health Controls.     Extensive federal, state and local regulatory and common laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment affect our oil and natural gas operations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position. Additionally, given the intense litigation environment in the United States, a threat exists of lawsuits alleging personal injury and property damage from environmental contamination alleged to be created by us or related entities. Potential liability in such lawsuits can include not only compensatory, but substantial punitive damages as well. We are not aware of any such suits currently pending or threatened.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA such persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. Potential liability also exists under CERCLA for natural resource damage. A Natural Resource Damage Action (NRDA) could result in liability being assessed for restoration to natural resources.

The Federal Oil Pollution Act of 1990 (“OPA”) regulates the release of oil into water or other areas designated by the statute. A release could result in our being held responsible for the cost of remediating the release, OPA specified damages and natural resource damages. The extent of such liability could be extensive. A release of oil in harmful quantities or other materials into water or other specified areas could also result in our being held responsible under the Clean Water Act for the costs of remediation, and any civil and criminal fines and penalties.

The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”), regulates the generation, transportation, storage, treatment and disposal of solid and hazardous wastes and can require cleanup of abandoned hazardous waste disposal sites as well as waste management areas operating facilities. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as “hazardous waste.” Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes” thereby potentially subjecting such wastes to more stringent handling,

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disposal and cleanup requirements. If such legislation were enacted it could have a significant impact on the operating costs of Southwest and Sierra, as well as the oil and natural gas industry and well servicing industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted. In addition, if our operations were to trigger regulation under RCRA, we could be required to satisfy certain financial criteria to ensure financial ability to comply with RCRA regulations. Proof of financial responsibility could be required in the form of dedicated trust funds, irrevocable letters of credit, posting of bonds, etc.

The Federal Clean Water Act (“CWA”) contains provisions that may result in the imposition of certain water pollution control requirements with respect to water releases from our operations. We may be required to incur certain capital expenditures in the next several years for water pollution control equipment in connection with obtaining and maintaining National Pollutant Discharge Elimination Systems (“NPDES”) permits. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities or well surfacing activities.

Our operations are also subject to the federal Clean Air Act (“CAA”) and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities or well servicing activities.

We maintain insurance against “sudden and accidental” occurrences, which may cover some, but not all, of the environmental risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such costs or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.

Limited partners should be aware that the assessment of liability associated with environmental liabilities is not always correlated to the value of a particular project. Accordingly, liability associated with the environment under local, state, or federal regulations, particularly clean ups under CERCLA, can exceed the value of our investment in the associated site.

Regulation of Oil and Natural Gas Exploration and Production.     Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the utilization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties. See “RISK FACTORS.”

55

Market Price of and Dividends on our Common Stock and Related Stockholder Matters

Market Information and Holders

We have two classes of common equity outstanding: our common stock and our Class A common stock. As of September 30, 2002, the number of holders of our common stock was one, our former parent SRH, and the number of holders of record of our Class A common stock was 36. Our common stock and Class A common stock are not currently traded through an organized exchange, and there is no known established public trading market for either our Class A common stock or common stock. We are not aware of the prices at which any purchase or sale, if any, of either our common stock or Class A common stock were made.

There is currently no public market for our common stock. We have applied to have our common stock listed on Nasdaq (National Market) under the symbol “SWRI.” We can give no assurance, however, that our listing application to Nasdaq (National Market) will be approved or that a market will develop for our common stock. In the event our common stock becomes authorized for quotation of Nasdaq (National Market), our shares of Class A common stock will automatically convert into shares of common stock.

Distributions

We have never paid cash dividends on either our Class A common stock or common stock and do not anticipate paying cash dividends in the foreseeable future. There are several restrictions on our ability to pay dividends, including (i) the provisions of the Delaware General Corporation Law, (ii) certain restrictive provisions in the Indenture governing our Senior Secured Notes due 2004, and (iii) certain restrictive covenants in our Senior Loan Agreement with Union Bank, as administrative agent for our senior lenders. These requirements work together to effectively prohibit the payment of cash dividends. We intend to retain any future earnings to finance the expansion and continuing development of our business.

The future payment of dividends, if any, on our Class A common stock or common stock is within the discretion of our Board of Directors and will depend upon our earnings, capital requirements, and financial position, future loan covenants, general economic conditions and other relevant factors. There is no assurance that we will pay any dividends.

Bondholder Consent

In connection with the merger, we are required to seek the consent of the holders of our Senior Secured Notes due 2004 to waive certain provisions of the Indenture governing those Senior Secured Notes. The approval of noteholders holding a majority of the principal amount of Senior Secured Notes outstanding is necessary to waive these Indenture provisions. We are in the process of seeking this approval.

56

SUMMARY HISTORICAL FINANCIAL DATA OF SOUTHWEST

The following tables set forth our selected historical financial information for the six months ended June 30, 2002 and 2001 and each of the five years in the period ended December 31. The following information should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS,” and Southwest’s Financial Statements and notes thereto included elsewhere in this prospectus/proxy statement.

	Six Months Ended June 30,						Year Ended December 31,
	2002			2001			2001			2000			1999			1998			1997
	(in thousands except per share data)						(in thousands except per share data)
Consolidated Income Statement Data:
Operating revenues:
Oil and gas	$	18,775		$	31,503		$	50,991		$	54,263		$	31,425		$	32,467		$	38,500
Other		165			133			249			377			1,212			1,412			1,227
Total operating revenue		18,940			31,636			51,240			54,640			32,637			33,879			39,727
Operating expenses:
Oil and gas		7,054			8,541			17,798			15,153			10,833			18,395			18,544
General and administrative		2,001			1,412			3,133			2,973			1,430			2,558			3,630
Depreciation, depletion and amortization		3,478			5,380			10,249			5,597			5,502			16,305			12,974
Impairment of oil and gas properties		—			—			—			—			—			64,000			—
Other		119			126			238			848			798			1,235			1,342
Total operating expenses		12,652			15,459			31,418			24,571			18,563			102,493			36,490
Operating income (loss)		6,288			16,177			19,822			30,069			14,074			(68,614	)		3,237
Other income (expense):
Interest expense		(6,918	)		(9,846	)		(19,579	)		(21,945	)		(22,382	)		(22,544	)		(12,372	)
Interest income		117			427			813			993			993			1,323			838
Other		(522	)		(136	)		(890	)		305			(308	)		66			200
		(7,323	)		(9,555	)		(19,656	)		(20,647	)		(21,697	)		(21,155	)		(11,334	)
Income (loss) before income taxes, minority interest, equity loss and extraordinary item		(1,035	)		6,622			166			9,422			(7,623	)		(89,769	)		(8,097	)
Income tax benefit (provision)		—			(2,251	)		(6,000	)		6,000			—			2,522			2,788
Minority interest in subsidiaries, net of tax		—			—			—			—			(1	)		(1	)		(15	)
Equity in loss in subsidiary and partnerships, net of tax		—			—			—			—			(931	)		(1,177	)		—
Extraordinary item, net of tax		4,856			—			—			12,690			14,541			—			(2,409	)
Net income (loss)	$	3,821		$	4,371		$	(5,834	)	$	28,112		$	5,986		$	(88,425	)	$	(7,733	)
Income (loss) per common share before extraordinary item	$	(2.26	)	$	43.71		$	(58.34	)	$	154.22		$	(85.55	)	$	(884.25	)	$	(53.24	)
Weighted average shares outstanding		458,011			100,000			100,000			100,000			100,000			100,000			100,000
Consolidated Balance Sheet Data
Cash and cash equivalents	$	6,901		$	9,846		$	6,469		$	15,595		$	15,528		$	12,375		$	24,257
Net property and equipment		90,588			88,883			92,175			78,254			73,477			81,373			156,302
Total assets		110,054			124,291			111,114			119,357			112,567			110,276			203,636
Long term debt, including current portion		140,104			174,033			174,099			173,863			196,672			199,314			199,350
Consolidated Cash Flow
Statement Data
Net cash provided by (used in) operating activities	$	2,707		$	10,715		$	15,997		$	19,718		$	(8,412	)	$	(5,309	)	$	4,920
Net cash provided by (used in) investing activities		(1,940	)		(16,518	)		(24,708	)		(11,691	)		3,022			(5,803	)		(104,912	)
Net cash provided by (used in) financing activities		(335	)		54			(415	)		(7,960	)		8,543			(770	)		116,680

57

Selected Operating Data

The following table sets forth selected information with respect to our operating data for the periods shown.

	Six Months Ended June 30,					Year Ended December 31,
	2002			2001		2001		2000		1999		1998		1997
	(in thousands, except per share data)					(in thousands, except per share data)
Production volumes:
Oil and condensate (MBbls)		561			626		1,227		1,236		1,306		1,689		1,308
Natural gas (MMcf)		2,381			2,464		5,119		4,784		4,627		5,556		5,639
Total (MBoe)		958			1,037		2,080		2,033		2,077		2,615		2,248
Average daily production:
Oil and condensate (Bbls)		3,101			3,461		3,361		3,376		3,578		4,628		3,584
Natural gas (Mcf)		13,156			13,614		14,025		13,070		12,677		15,222		15,449
Total (Boe)		5,294			5,730		5,698		5,555		5,691		7,165		6,159
Average realized prices(1):
Oil and gas condensate     (per Bbl)	$	22.43		$	27.92	$	24.88	$	28.56	$	16.23	$	12.73	$	19.12
Natural gas (per Mcf)		2.57			5.50		3.91		3.89		2.19		1.85		2.24
per Boe		19.51			29.94		24.29		26.51		15.09		12.16		16.75
Expenses (per Boe):
Lease operating (including production taxes)	$	7.36		$	8.24	$	8.56	$	7.45	$	5.22	$	7.03	$	8.23
Oil and gas depletion	$	3.35		$	4.82	$	4.66	$	2.46	$	2.36	$	5.97	$	5.52
Oil and gas general and administrative, net(2)	$	2.09	(3)	$	1.36	$	1.51	$	1.25	$	.78	$	1.04	$	1.63

⁽¹⁾ Reflects the actual realized prices received by Southwest, including the results of Southwest’s hedging activities. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF SOUTHWEST.”

⁽²⁾ Certain related party management fees received from oil and gas partnerships have been reclassified as a reduction of general and administrative expenses for all periods presented and represent a reimbursement of costs incurred by Southwest as the general partner.

⁽³⁾ G&A included approximately $1.0 million of non-cash expenses attributable to the exchange of a note receivable from an officer and stockholder of Southwest in return for stock in a privately held company which collateralized the note. G&A without the non-cash expense was $1.07 per Boe.

58

SUMMARY UNAUDITED PRO FORMA FINANCIAL INFORMATION OF SOUTHWEST

The following table sets forth summary unaudited pro forma combined financial information and has been prepared to assist in the analysis of the financial effects of the merger involving Southwest and the partnerships (assuming participation in the merger by all 21 partnerships). This pro forma information is based on the historical financial statements of the partnerships and Southwest.

The information was prepared based on the following assumptions:

• After completion of the merger, 1,688,347 shares of Southwest common stock are assumed to be outstanding. For information regarding the Merger Value of the limited partners’ share of the partnerships, see “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED.”

• Both Southwest and the partnerships utilize the full cost method of accounting for their oil and gas activities.

• The merger is completed by June 30, 2002.

• The merger is accounted for as a reorganization of interests under common control in a manner similar to a pooling of interests.

• The unaudited pro forma balance sheet has been prepared as if the merger occurred on June 30, 2002. The unaudited pro forma statements of operations and cash flows have been prepared as if the merger occurred on January 1, 2001.

• Targeted annual general and administrative expense savings from the merger have not been reflected as an adjustment to the historical data.

• Costs of the merger incurred are estimated to be $3.0 million. Costs related to the merger of the partnerships will be expensed by Southwest in the period the merger is completed.

The unaudited pro forma data is presented for illustrative purposes only. If the merger had occurred in the past, Southwest’s financial position or operating results might have been different from those presented in the unaudited pro forma information. The unaudited pro forma information should not be relied on as an indication of the financial position or operating results that Southwest would have achieved if the merger had occurred as of June 30, 2002, or January 1, 2001. The unaudited pro forma information also should not be relied on as an indication of the future results that Southwest will achieve after the completion of the merger.

The unaudited pro forma combined financial data should be read together with (1) the historical consolidated financial statements of Southwest found elsewhere in this prospectus/proxy statement, (2) the historical financial statements of each partnership contained elsewhere in this prospectus/proxy statement, and (3) the unaudited pro forma combined financial statements found elsewhere in this prospectus/proxy statement. With respect to future cash distributions, see “COMPARISON OF RIGHTS OF SOUTHWEST SHAREHOLDERS AND THE PARTNERSHIPS’ LIMITED PARTNERS—Distributions and Dividends.” See also “WHERE YOU CAN FIND MORE INFORMATION” on the inside front cover page of this prospectus/proxy statement.

59

	Pro Forma
	Six Months Ended June 30, 2002			Year Ended December 31, 2001
	(in thousands except per share data)
STATEMENT OF OPERATIONS:
Operating revenues:
Oil and gas	$	23,693		$	64,668
Other		165			249
		23,858			64,917
Costs and expenses:
Oil and gas production		9,759			23,815
General and administrative		3,302			5,716
Depreciation, depletion and amortization		3,827			11,985
Interest expense		6,922			19,585
Other		490			270
		24,300			61,371
Income (loss) before income taxes		(442	)		3,546
Income tax expense		(201	)		(7,149	)
Loss before transaction expenses		(643	)		(3,603	)
Transaction expenses		3,000			3,000
Loss after transaction expense	$	(3,643	)	$	(6,603	)
Net income (loss) per common share:
Basic—before transaction expenses	$	(.56	)	$	(4.57	)
Basic—after transaction expenses	$	(3.18	)	$	(8.38	)
Weighted average number of shares outstanding		1,146,358			788,347
CASH FLOW INFORMATION:
Net cash provided by operating activities		3,759			22,770
Net cash used in investing activities		(2,714	)		(26,382	)
Net cash used in financing activities		(862	)		(6,999	)
BALANCE SHEET DATA (AT PERIOD END):
Oil and gas properties, net	$	97,034			—
Total Assets	$	120,592			—
Long-term debt (including current maturities)	$	140,465			—
Stockholders’ deficit	$	(32,140	)		—

60

SUMMARY OIL AND GAS RESERVE INFORMATION

The following table sets forth summary information on Southwest’s and the 21 partnerships’ proved oil and gas reserves at July 1, 2002, and the summary pro forma combined information of the proved oil and gas reserves assuming the merger of each partnership had taken place on January 1, 2002. Southwest and the combined partnerships’ historical and Southwest’s pro forma combined proved oil and gas reserve information set forth below are only estimates based primarily on the Ryder Scott Reports as of December 31, 2001 and updated to July 1, 2002 by Southwest’s engineers. The reserve information as of July 1, 2002 is based on the prices of oil and gas as of that time. The discounted future net cash flows set forth in this prospectus/proxy statement should not be considered as the current market value of the estimated oil and gas reserves attributable to Southwest, the combined partnerships’ or any partnership’s properties. Under applicable SEC requirements, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.

Summary Historical and Pro Forma Oil and Gas Reserve Information at July 1, 2002

	Oil and NGLS (MMBbls)		Natural Gas (Bcf)	Barrels of Equivalents (MMBoe)
NET PROVED RESERVES (HISTORICAL):
SOUTHWEST:
Developed		15.0	50.5	23.4
Undeveloped		5.5	27.5	10.1
Total		20.5	78.0	33.5
COMBINED PARTNERSHIPS:
Developed		3.8	15.2	6.3
Undeveloped		0.5	5.6	1.4
Total		4.3	20.8	7.7
NET PROVED RESERVES (PRO FORMA COMBINED):
Developed		17.9	61.6	28.2
Undeveloped		5.9	31.9	11.2
Total		23.8	93.5	39.4
RESERVE VALUATION INFORMATION (IN MILLIONS):
SOUTHWEST:
PV-10 Value(1)	$	220.0
Estimated future net cash flows	$	311.5
Standardized measure of discounted future net cash flows	$	152.6
COMBINED PARTNERSHIPS:
PV-10 Value(1)	$	48.1
Estimated future net cash flows	$	86.6
Standardized measure of discounted future net cash flows(2)	$	46.0
PRO FORMA COMBINED:
PV-10 Value(1)	$	256.7
Estimated future net cash flows	$	358.0
Standardized measure of discounted future net cash flows(2)	$	168.7

⁽¹⁾ The present value of future net revenues attributable to our reserves was prepared using prices in effect at the end of the respective periods presented, discounted at 10% per annum on a pre-tax basis.

⁽²⁾ The combined partnerships do not reflect a federal income tax provision since the limited partners of each partnership include the income of the partnership in their respective individual federal income tax returns. However, the pro forma combined assumes partnership income is tax effected using a 34% statutory rate.

61

COMPARATIVE PER SHARE DATA

The following tables summarize the per share information for historical Southwest, pro forma combined Southwest, historical partnership information per $500 limited partner investment and pro forma partnership information per $500 limited partner investment on an equivalent per share basis. The pro forma information gives effect to the merger of each partnership accounted for by Southwest as a reorganization of interests under common control similar to a pooling of interest. You should read this information together with the historical financial statements (1) of Southwest included elsewhere in the prospectus/proxy statement and (2) of each partnership included elsewhere in the prospectus/proxy statement. With respect to future cash distributions, see “COMPARISON OF RIGHTS OF SOUTHWEST STOCKHOLDERS AND THE PARTNERSHIPS’ LIMITED PARTNERS—Distributions and Dividends” and “RISK FACTORS.” You should not rely on the pro forma combined information as being indicative of the results that would have occurred had the merger of each partnership been completed on January 1, 2002, or the future results that Southwest will experience after the merger of each partnership. In addition, because Southwest has both a different legal structure and purpose from each partnership, the information about Southwest and the information about the combined partnerships are not necessarily comparable.

We use the full cost method of accounting for our investment in oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas reserves are capitalized into a “full cost pool” as incurred, and properties in the pool are depleted and charged to operations using the units of revenue method based on the ratio of current gross revenues to total proved future gross revenues, computed based on current prices. Significant downward revisions of quantity estimates or declines in oil and gas prices that are not offset by other factors could result in an impairment of oil and gas properties.

In 1998, because of low oil and gas prices, the estimated present value, discounted at 10% and adjusted for related income taxes, based on year end pricing, of our and gas properties fell below the carrying value as reported in our financial statements and resulted in a $64.0 million non-cash write down. This $64.0 million “write-down”, resulted in a decrease in stockholders’ equity. Once incurred, a write-down is not reversible. Our negative book value per share is primarily a result of this non-cash impairment to our oil and gas property carrying value.

Our stockholders deficit, at December 31, 2001 and June 30, 2002 is $74.0 million and $40.4 million respectively, which reflects the non-cash write-down of the oil and gas property values as previously described. Although oil and gas pricing has increased since the 1998 impairment and the estimated present value, based on prices in effect on July 1, 2002, of our oil and gas properties has also increased, GAAP does not allow for the subsequent “write-up” of properties; therefore, our stockholders deficit may not be a fair representation of Southwest’s value. The large stockholders’ deficit of Southwest combined with the equity amounts from the Partnerships creates the negative pro forma amounts as presented herein.

Historical and Pro Forma Combined—Southwest

	Six Months Ended June 30, 2002		Year Ended December 31, 2001
HISTORICAL—SOUTHWEST:
Income from continuing operations per share:
Basic	(2.26	)	(5.84	)
Diluted	(2.26	)	(5.84	)
Book value per share	(40.38	)	(740.29	)
Cash dividends per common share	N/A		N/A
PRO FORMA COMBINED—SOUTHWEST:
Income from continuing operations per share:
Basic	(.56	)	(4.57	)
Diluted	(.56	)	(4.57	)
Book value per share	(19.04	)	N/A
Cash dividends per common share	N/A		N/A

62

Historical—Partnership Information per $500 Limited Partner Investment

	Income			Book Value				Cash Distributions
	Six Months Ended June 30, 2002		Year Ended December 31, 2001	Six Months Ended June 30, 2002		Year Ended December 31, 2001		Six Months Ended June 30, 2002	Year Ended December 31, 2001
Southwest Royalties, Inc. Income Fund V, L.P.	(1.87	)	2.01	64.42		66.30		—	13.50
Southwest Royalties, Inc. Income Fund VI, L.P.	(5.14	)	25.73	113.43		118.57		—	50.74
Southwest Oil & Gas Income Fund VII-A, L.P.	8.84		15.33	74.56		73.76		8.04	25.53
Southwest Royalties Institutional Income Fund VII-B, L.P.	15.52		28.39	93.86		96.34		18.00	43.60
Southwest Oil & Gas Income Fund VIII-A, L.P.	6.45		27.58	34.39		30.06		2.12	41.05
Southwest Royalties Institutional Income Fund VIII-B, L.P.	7.69		35.98	50.00		51.62		9.31	55.02
Southwest Oil & Gas Income Fund IX-A, L.P.	9.29		34.07	47.72		47.04		8.61	55.63
Southwest Royalties Institutional Income Fund IX-B, L.P.	8.91		33.56	45.01		44.84		8.74	49.91
Southwest Oil & Gas Income Fund X-A, L.P.	.18		.65	13.91		13.73		—	5.15
Southwest Royalties Institutional Income Fund X-A, L.P.	.15		5.95	19.27		19.12		—	15.91
Southwest Oil & Gas Income Fund X-B, L.P.	1.60		10.86	35.50		33.90		—	31.36
Southwest Royalties Institutional Income Fund X-B, L.P.	2.84		19.76	45.57		46.75		4.02	32.34
Southwest Oil & Gas Income Fund X-C, L.P.	(4.85	)	15.93	40.35		45.20		—	52.09
Southwest Royalties Institutional Income Fund X-C, L.P.	(6.17	)	9.79	32.84		39.01		—	49.73
Southwest Developmental Drilling Fund 91-A, L.P.	3.14		10.83	47.60		48.35		3.89	24.20
Southwest Developmental Drilling Fund 92-A, L.P.	16.67		49.95	69.97		72.27		18.98	66.04
Southwest Partners, L.P.	(8.45	)	10.25	315.60		348.67		—	12.43
Southwest Combination Income/ Drilling Program 1988, L.P.	1.22		2.32	6.89		5.68		—	2.66
Southwest Developmental Drilling Fund 1990, L.P.	4.55		7.18	(25.24	)	(25.38	)	4.41	8.82
Southwest Developmental Drilling Fund 1993, L.P.	16.52		43.69	144.58		149.48		21.42	71.09
Southwest Developmental Drilling Fund 1994, L.P.	4.66		18.44	28.42		30.53		6.77	24.96

63

Pro Forma Partnership Information per $500 Limited Partner Investment on an Equivalent per Share Basis⁽¹⁾

		Income
	Estimated Number of Shares of Southwest Common Stock Offered	Six Months Ended June 30, 2002				Year Ended December 31, 2001				Book Value June 30, 2002
		Basic		Diluted		Basic		Diluted
Southwest Royalties, Inc. Income Fund V, L.P.	2.00	(1.12	)	(1.12	)	(9.14	)	(9.14	)	(38.08	)
Southwest Royalties, Inc. Income Fund VI, L.P.	6.00	(3.36	)	(3.36	)	(27.42	)	(27.42	)	(114.24	)
Southwest Oil & Gas Income Fund VII-A, L.P.	3.00	(1.68	)	(1.68	)	(13.71	)	(13.71	)	(57.12	)
Southwest Royalties Institutional Income Fund VII-B, L.P.	5.00	(2.80	)	(2.80	)	(22.85	)	(22.85	)	(95.20	)
Southwest Oil & Gas Income Fund VIII-A, L.P.	3.00	(1.68	)	(1.68	)	(13.71	)	(13.71	)	(57.12	)
Southwest Royalties Institutional Income Fund VIII-B, L.P.	5.00	(2.80	)	(2.80	)	(22.85	)	(22.85	)	(95.20	)
Southwest Oil & Gas Income Fund IX-A, L.P.	5.00	(2.80	)	(2.80	)	(22.85	)	(22.85	)	(95.20	)
Southwest Royalties Institutional Income Fund IX-B, L.P.	5.00	(2.80	)	(2.80	)	(22.85	)	(22.85	)	(95.20	)
Southwest Oil & Gas Income Fund X-A, L.P.	1.00	(0.56	)	(0.56	)	(4.57	)	(4.57	)	(19.04	)
Southwest Royalties Institutional Income Fund X-A, L.P.	2.00	(1.12	)	(1.12	)	(9.14	)	(9.14	)	(38.08	)
Southwest Oil & Gas Income Fund X-B, L.P.	2.00	(1.12	)	(1.12	)	(9.14	)	(9.14	)	(38.08	)
Southwest Royalties Institutional Income Fund X-B, L.P.	3.00	(1.68	)	(1.68	)	(13.71	)	(13.71	)	(57.12	)
Southwest Oil & Gas Income Fund X-C, L.P.	3.00	(1.68	)	(1.68	)	(13.71	)	(13.71	)	(57.12	)
Southwest Royalties Institutional Income Fund X-C, L.P.	2.00	(1.12	)	(1.12	)	(9.14	)	(9.14	)	(38.08	)
Southwest Developmental Drilling Fund 91-A, L.P.	4.00	(2.24	)	(2.24	)	(18.28	)	(18.28	)	(76.16	)
Southwest Developmental Drilling Fund 92-A, L.P.	11.00	(6.16	)	(6.16	)	(50.27	)	(50.27	)	(209.44	)
Southwest Partners, L.P.	4201.00	(2,352.56	)	(2,352.56	)	(19,198.57	)	(19,198.57	)	(79,987.04	)
Southwest Combination Income/ Drilling Program 1988, L.P.	0.00	0.00		0.00		0.00		0.00		0.00
Southwest Developmental Drilling Fund 1990, L.P.	56.00	(31.36	)	(31.36	)	(255.92	)	(255.92	)	(1,066.24	)
Southwest Developmental Drilling Fund 1993, L.P.	12.00	(6.72	)	(6.72	)	(54.84	)	(54.84	)	(228.48	)
Southwest Developmental Drilling Fund 1994, L.P.	5.00	(2.80	)	(2.80	)	(22.85	)	(22.85	)	(95.20	)

⁽¹⁾ Represents the “Pro Forma Combined—Southwest” amounts multiplied by the estimated number of shares of Southwest common stock to be received per $500 limited partner investment for each Partnership.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS OF SOUTHWEST

General

We are principally involved in the business of oil and gas development and production, as well as organizing and serving as managing general partner for various public and private limited partnerships engaged in oil and gas development and production. We are also the general partner of Southwest Partners II, L.P. and Southwest Partners III, L.P. which own common stock in Basic Energy Services, Inc. (“Basic”). We sell our oil and gas production to a variety of purchasers, and the prices we receive are dependent upon the oil and gas commodity prices.

We regularly pursue and evaluate recapitalization strategies and acquisition opportunities (including opportunities to engage in mergers, consolidations or other business combinations) and at any given time may be in various stages of evaluating such opportunities.

Critical Accounting Policies

We use the full cost method of accounting for our investment in oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas reserves are capitalized into a “full cost pool” as incurred, and properties in the pool are depleted and charged to operations using the units of revenue method based on the ratio of current gross revenues to total proved future gross revenues, computed based on current prices. Significant downward revisions of quantity estimates or declines in oil and gas prices that are not offset by other factors could result in a writedown for impairment of oil and gas properties. Once incurred, a writedown of oil and gas properties is not reversible at a later date, even if oil or natural gas prices increase. For the six months ended June 30, 2002 and for the years ended December 31, 2001, 2000 and 1999, no write down was deemed necessary.

The full cost method of accounting subjects us to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. If our capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense.

Our discounted present value of proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of depreciation, depletion and amortization.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than our long-term price forecast.

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Depletion of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depletion is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Results of Operations

Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001

The following table summarizes production volumes and average sales prices for our oil and gas operations, including the effect on revenues, for the periods indicated:

	Six Months Ended June 30,				2002 Compared to 2001
	2002		2001		% Increase (Decrease)		Revenue Increase (Decrease)
							(in thousands)
Production volumes:
Oil and condensate (MBbls)		561		626	(10	%)	$	(1,458	)
Natural gas (MMcf)		2,381		2,464	(3	%)		(213	)
Average sales prices:
Oil and condensate (per Bbl)	$	22.43	$	27.92	(20	%)	$	(3,437	)
Natural gas (per Mcf)	$	2.57	$	5.50	(53	%)		(7,220	)

Revenues.    Our revenues decreased 40% to $18.9 million in 2002 from $31.6 million in 2001.

Oil and gas revenue decreased 40% to $18.8 million in 2002 from $31.5 million in 2001. Decreases in oil and gas prices resulted in a decrease of approximately $10.7 million in oil and gas revenue. Decreases in oil and gas production resulted in a decrease of approximately $1.7 million in oil and gas revenues. Oil and gas partnership distributions decreased $0.4 million from the prior year.

Net oil and gas production decreased 9% or approximately 500 Boepd to 5300 Boepd in 2002 from approximately 5,800 Boepd in 2001.

Operating Expenses.    Operating expenses, before general and administrative expense, depreciation, depletion and amortization, for Southwest decreased 17% to $7.2 million in 2002 from $8.7 million in 2001.

Oil and gas operating expense decreased approximately 17% to $7.1 million in 2002 from $8.5 million in 2001. The decrease is due primarily to a decrease in repairs and maintenance such as electrical repairs and chemical treatment and pulling expenses performed during the six months ended June 30, 2002 and to the decrease in ad valorem and production taxes, which is in relation to the decline in oil and gas production and prices received for the six months ended June 30, 2002. The average operating expense decreased 11% to $7.36 per Boe in 2002 from $8.24 per Boe in 2001.

General and Administrative (“G&A”) Expense.    Our G&A expense increased 42% to $2.0 million in 2002 from $1.4 million in 2001. The increase is due primarily to approximately $1.0 million being charged to compensation expense relating to the exchange of a note receivable from an officer and stockholder of Southwest in return for stock in a privately held company (Southwest Royalties Holdings, Inc.), which collateralized the Note. The carrying value of the Note Receivable was approximately $1.6 million and the value of the stock was approximately $0.6 million. This increase was partially offset by an overall decrease in compensation expense of approximately $0.4 million due to a reduction in staff and bonuses. G&A expense per Boe increased 54% to $2.09 per Boe in 2002, from $1.36 per Boe in 2001.

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Depreciation, Depletion and Amortization (“DD&A”) Expense.    Our DD&A expense decreased 36% to $3.4 million in 2002 from $5.4 million in 2001. Depletion, which comprises the largest percentage of DD&A, is calculated using the units of revenue method of amortization. This method is calculated by dividing current period gross revenues by the total estimated future gross revenues and multiplying the resulting percentage by the net book value of the oil and gas properties being depleted. The current period gross revenues are the result of the average commodity prices actually received during the amortization period. Future gross revenues are based on the commodity prices in effect as of the date of the reserve estimate. Therefore, large fluctuations between actual average commodity prices received during the amortization period and the commodity prices in effect as of the date of the reserve estimate can result in large increases or decreases in the computation of depletion expense for the period. The average price received for oil and gas during 2002 was $22.43 per bbl of oil and $2.57 per Mcf of gas as opposed to the prices required to be used in determining the future gross revenues in the reserve estimate of $25.04 per bbl of oil and $2.97 per Mcf of gas. Oil and gas depletion expense, on a Boe basis, decreased 32% to $3.35 per Boe in 2002 from $4.82 per Boe in 2001.

Interest Expense.    Our interest expense decreased 30% to $6.9 million in 2002 from $9.8 million in 2001. The reduction in interest expense is due primarily to the Exchange Transaction and the Refinance Transaction, both of which closed in April, 2002. See detailed discussion of these transactions below under “Extraordinary Items, net of tax.”

Other Income (Expense).    Other income (expense) represents interest income, interest expense, as discussed above, and other, net. Other net income (expense) excluding interest expense for Southwest decreased 175% to expense of approximately $0.4 million in 2002 from income of approximately $0.3 million in 2001. The other expense in 2002 represented approximately $0.4 million of fair value adjustments on oil and gas hedges. The other income in 2001 represented approximately $0.2 million of fair value adjustments on oil and gas hedges.

Extraordinary Item, net of tax.    On March 5, 2002, we commenced an Offer to Exchange and Consent Solicitation with respect to our 10½% Senior Notes due 2004. The Offer to Exchange and Consent Solicitation closed on April 19, 2002. As part of the Exchange Transaction, approximately $114.8 million face amount of the 10½% Senior Notes plus $2.9 million of net accrued and unpaid interest since October 15, 2001, was exchanged for approximately $60.0 million face amount of new Senior Secured Notes and 900,000 shares of our Class A common stock, which represents approximately 90% of the voting stock of Southwest after the Exchange Transaction. The value of the Class A common stock was approximately $29.6 million. We paid approximately $1.3 million, including all fees, to exchange the 10½% Senior Notes and wrote off approximately $1.6 million of deferred loan issue costs, approximately $628,000 of the original issue discount and recognized approximately $15.1 million, as established by applying FASB No. 15 “Accounting by Debtors and Creditors for Troubled Debt Restructurings,” in additional carrying costs associated with the issuance of the $60.0 million face Senior Secured Notes to recognize a $9.5 million extraordinary gain on the exchange of the Notes. We recorded an income tax provision on the extraordinary gain of $3.2 million. The net extraordinary gain on the exchange was approximately $6.3 million. The extraordinary gain per share, net of tax, is approximately $13.67.

On April 22, 2002, we refinanced our revolving loan facility (the “Refinance Transaction”) and recorded an extraordinary loss from early extinguishment of debt in the amount of approximately $2.1 million. We recognized an income tax benefit on the extraordinary loss of $0.7 million. The net extraordinary loss on early extinguishment of debt was approximately $1.4 million. The extraordinary loss per share is approximately $(3.07).

Net Income.    Due to the factors described above, net income for Southwest decreased 13% to $3.8 million in 2002 as compared to $4.4 million in 2001.

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Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

The following table summarizes production volumes and average sales prices for our oil and gas operations, including the effect on revenues, for the periods indicated:

	Year Ended December 31,				2001 Compared to 2000
	2001		2000		% Increase (Decrease)		Revenue Increase (Decrease)
							(in thousands)
Production volumes:
Oil and condensate (MBbls)		1,227		1,236	(1	%)	$	(224	)
Natural gas (MMcf)		5,119		4,784	7	%		1,310
Average sales prices:
Oil and condensate (per Bbl)	$	24.88	$	28.56	(13	%)	$	(4,548	)
Natural gas (per Mcf)	$	3.91	$	3.89	1	%		96

Revenues.    Our revenues decreased 6% to $51.2 million in 2001 from $54.6 million in 2000.

Oil and gas revenue decreased 6% to $51.0 million in 2001 from $54.3 million in 2000. Decreases in oil prices resulted in a decrease of approximately $4.5 million in oil and gas revenue. Increases in gas production offset the decrease in oil prices by approximately $1.3 million. Oil and gas partnership distributions decreased $0.1 million from the prior year.

Net oil and gas production increased 3% or approximately 143 Boepd to 5,698 Boepd in 2001 from approximately 5,555 Boepd in 2000.

Operating Expenses.    Our operating expenses, before general and administrative expense, depreciation, depletion and amortization, increased 13% to $18.0 million in 2001 from $16.0 million in 2000.

Oil and gas operating expense increased approximately 17% to $17.8 million in 2001 from $15.2 million in 2000. The increase is due primarily to bringing higher lifting cost wells back on line, increases in electricity costs, workover expenses and repairs associated with maintaining and/or increasing existing production. The average operating expense increased 15%, to $8.56 per Boe in 2001 from $7.45 per Boe in 2000. Other operating expense decreased approximately 72% to $0.2 million in 2001 from $0.8 million in 2000. The decrease is due to cut backs in computer outsourcing services that we provided.

General and Administrative (“G&A”) Expense.    Our G&A expense increased 5% to $3.1 million in 2001 from $3.0 million in 2000.

Oil and gas G&A expense increased 23% to $3.1 million in 2001 from $2.6 million in 2000 and averaged $1.51 per Boe in 2001, a 21% increase compared to $1.25 per Boe in 2000. The increase is due primarily to legal expenses associated with evaluating business strategies relating to our highly leveraged capital structure. Other G&A expense decreased 100% to $0.0 million in 2001 from $0.4 million in 2000. The decrease is due to cut backs in computer outsourcing services that we provided.

Depreciation, Depletion and Amortization (“DD&A”) Expense.    Our DD&A expense increased 83% to $10.2 million in 2001 from $5.6 million in 2000. Depletion, which comprises the largest percentage of DD&A, is calculated using the units of revenue method of amortization. This method is calculated by dividing current period gross revenues by the total estimated future gross revenues and multiplying the resulting percentage by the net book value of the oil and gas properties being depleted. The current period gross revenues are the result of the average commodity prices actually received during the amortization period. Future gross revenues are based on the commodity prices in effect as of the date of the reserve estimate. Therefore, large fluctuations between actual

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average commodity prices received during the amortization period and the commodity prices in effect as of the date of the reserve estimate can result in large increases or decreases in the computation of depletion expense for the period. The average price received for oil and gas during 2001 was $24.88 per Bbl of oil and $3.91 per Mcf of gas as opposed to the prices required to be used in determining the future gross revenues in the reserve estimate of $18.44 per Bbl of oil and $2.36 per Mcf of gas; a difference of 26% in the price per Bbl of oil and 39% in the price per Mcf of gas. Oil and gas depletion expense, on a Boe basis, increased 89% to $4.66 per Boe in 2001 from $2.46 per Boe in 2000.

Interest Expense.    Our interest expense decreased 11% to $19.6 million in 2001 from $21.9 million in 2000. The reduction in interest expense is due primarily to the reduction of the deferred debt costs being amortized to interest expense due to the refinance of the revolving loan facility with Foothill Capital Corporation in August 2000.

Net Income (Loss).    Due to the factors described above, our net income (loss) decreased 121% to a net loss of $(5.8) million in 2001 as compared to net income of $28.1 million in 2000. Included in net income for 2000 is an extraordinary gain associated with the repurchase of approximately 19% of the 10½% Senior Notes of approximately $14.1 million. The extraordinary gain of $14.1 million in 2000 was partially offset by an extraordinary loss of approximately $1.4 million associated with the refinancing of our $50.0 million revolving loan facility with Foothill Capital Corporation in August 2000.

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

The following table summarizes production volumes, average sales prices and period to period comparisons for our oil and gas operations, including the effect on revenues, for the periods indicated:

	Year Ended December 31,				2000 Compared to 1999
	2000		1999		% Increase (Decrease)		Revenue Increase (Decrease)
							(in thousands)
Production volumes:
Oil and condensate (MBbls)		1,236		1,306	(5	%)	$	(2,005	)
Natural gas (MMcf)		4,784		4,627	3	%	$	609
Average sales prices:
Oil and condensate (per Bbl)	$	28.56	$	16.23	76	%	$	16,103
Natural gas (per Mcf)	$	3.89	$	2.19	78	%	$	7,866

Revenues.    Our revenues increased 67% to $54.6 million in 2000 from $32.6 million in 1999.

Oil and gas revenues increased 73% to $54.3 million in 2000 from $31.4 million in 1999. The increase in oil and gas revenue is due primarily to increases in oil and gas prices. Increases in oil and gas prices resulted in increased oil and gas revenues of approximately $24.0 million. Net decreases in production offset the increase in prices by approximately $1.4 million. Increased oil and gas partnership distributions added approximately $279,000 to increased oil and gas revenues. Other revenues decreased 69% to $0.4 million in 2000 from $1.2 million in 1999. The decrease in other revenues is due primarily to the liquidation of TPI in November of 1999.

Oil and gas production decreased 2% or approximately 136 Boepd to 5,555 Boepd in 2000 from approximately 5,691 Boepd in 1999. In an ongoing effort to increase our cash position and/or reduce the number of high operating expense properties in our oil and gas portfolio, management sold oil and gas properties for approximately $566,000 in 2000 and $5.6 million in 1999.

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Operating Expenses.    Operating expenses, before general and administrative expense, impairment of oil and gas properties and depreciation, depletion and amortization, increased 38% to $16.0 million in 2000 from $11.6 million in 1999.

Oil and gas operating expense increased approximately 40% to $15.2 million in 2000 from $10.8 million in 1999. The increase is due primarily to increased production taxes, associated with the 73% increase in oil and gas revenue as discussed above, and increased workover expense and repairs associated with bringing wells back on line, which were deemed uneconomical due to depressed oil and gas prices experienced during 1998 and a portion of 1999. The average operating expense increased 43% to $7.45 per Boe in 2000 from $5.22 per Boe in 1999.

General and Administrative (“G&A”) Expense.    Our G&A expense increased 108% to $3.0 million in 2000 from $1.4 million in 1999. Oil and gas G&A expense per Boe increased 60% to $1.25 per Boe in 2000 from $.78 per Boe in 1999. The increase in G&A expense is due primarily to increased personnel and insurance costs as well as increased legal and professional fees associated with evaluating business strategies and opportunities.

Depreciation, Depletion and Amortization (“DD&A”) Expense.    Our DD&A expense increased 2% to $5.6 million in 2000 from $5.5 million in 1999. Oil and gas depletion expense, on a Boe basis, increased 2% to $2.46 per Boe in 2000 from $2.36 per Boe in 1999.

Interest Expense.    Our interest expense decreased 2% to $21.9 million in 2000 from $22.4 million in 1999.

Equity Loss in Partnerships.    Our indirect investment in Basic upon recording our portion of Basic’s losses for the three months ended March 31, 1999 was reduced to zero. Therefore, according to GAAP, the equity method was suspended. We did not record our ownership percentage of Basic’s losses in 2000. If Basic subsequently begins to report net income, we will resume applying the equity method only after our share of net income equals the share of net losses not recognized during the period the equity method is suspended.

Net Income.    Due to the factors described above, our net income increased 370% to $28.1 million in 2000 as compared to $6.0 million in 1999. Included in oil and gas net income for 2000 is an extraordinary gain associated with the repurchase of approximately 19% of the original issue $200.0 million face 10½% Senior Notes issued in October 1997, of approximately $14.1 million which was netted with an extraordinary loss associated with the refinancing of the $50.0 million revolving loan facility in August 2000, of approximately $1.4 million, for a net extraordinary gain of $12.7 million. Included in oil and gas net income for 1999 is an extraordinary gain associated with the repurchase of approximately 19% of the original issue $200.0 million face 10½% Senior Notes issued in October 1997, of approximately $14.5 million.

Liquidity and Capital Resources

Funding for our business activities has historically been provided by operating cash flows, bank borrowings, debt issuances, reserve-based financings and equity placements. Any future capital expenditures, other than those with previously arranged financing, will likely require additional equity or other financing and will be dependent upon availability.

Management is constantly monitoring our cash position and our ability to meet financial obligations as they become due, and in this effort, is continually exploring various strategies for addressing our current and future liquidity needs. As of December 31, 2001, our cash balance was $7.1 million. As of June 30, 2002, our cash balance was $7.5 million.

As of June 30, 2002, our total indebtedness was $140.1 million, including $8.8 million attributable to our obligations under the 10½% Senior Notes due October 2004, $75.1 million attributable to our obligations under the Senior Secured Notes due June 2004, $55.0 million attributable to our obligations under our revolving credit agreement and $1.2 million attributable to other debt. See Note 5 of the notes to our Consolidated Financial Statements included elsewhere in this prospectus/proxy statement.

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We have a highly leveraged capital structure. As of September 1, 2002 we expect to have approximately $0.1 million of principal due for the remainder of 2002, $0.1 million in 2003, and $123.9 million in 2004 for an aggregate of $124.1 million of principal due between June 30, 2002 and December 31, 2004. We are constantly monitoring our cash position and our ability to meet our financial obligations as they become due, and in this effort, we are continually exploring various strategies for addressing our current and future liquidity needs. We regularly pursue and evaluate recapitalization strategies and acquisition opportunities (including opportunities to engage in mergers, consolidations or other business combinations) and at any given time may be in various stages of evaluating such opportunities.

Based on current production, commodity prices and cash flow from operations, we have adequate cash flow to fund debt service, developmental projects and day to day operations, but it is not sufficient to build a cash balance which would allow us to meet our debt principal maturities scheduled for 2004. Therefore we must renegotiate the terms of our various obligations or seek new lenders or equity investors in order to meet our financial obligations, specifically those maturing in 2004. We would also consider disposing of certain assets in order to meet our obligations.

There can be no assurance that our debt restructuring efforts will be successful or that the debt holders will agree to a course of action consistent with our requirements in restructurings the obligations. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to us.

Net Cash Provided by (used in) Operating Activities.    Our operating activities provided cash of $2.7 million for the six months ended June 30, 2002, $16.0 million in 2001, $19.7 million in 2000 and used $8.4 million in 1999. Our ability to generate cash flow from operating activities has been substantially improved since 1999 based on the increase in oil and gas commodity prices.

Net Cash Provided by (used in) Investing Activities.    Cash used in our investing activities was $1.9 million for the six months ended June 30, 2002, $24.7 million in 2001, $11.7 million in 2000 and in 1999, investing activities provided $3.0 million. Oil and gas acquisitions and development activities were the primary uses of funds in each period.

The following table sets forth capital expenditures, including acquisitions, made by us during the periods indicated.

	June 30, 2002		Year Ended December 31,
			2001		2000		1999
	(in thousands)		(in thousands)
Oil and gas properties
Development	$	1,681	$	15,262	$	8,770	$	3,195
Exploration		340		536		476		76
Acquisitions		129		8,120		1,318		417
Oil and gas other		35		320		475		538
Total	$	2,185	$	24,238	$	11,039	$	4,226

We have tentatively budgeted $9.0 million for the remainder of 2002 in capital expenditures for oil and gas development projects. This budget is subject to change based on financial strategies currently being developed, future drilling costs, hedging strategies, as well as the level of oil and gas prices in the future. We plan to fund our capital expenditure budget with current cash balances along with cash flow from operations, based on current commodity prices and estimated results of current and future capital projects. There can be no assurance that our estimated results of current and future capital projects will be achieved.

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Net Cash Provided by (used in) Financing Activities.    Cash used in our financing activities was $0.3 million for the six months ended June 30, 2002, $0.4 million in 2001, $8.0 million in 2000, and in 1999 financing activities provided cash of $8.5 million.

We used $0.3 million in our financing activities during the six months ended June 30, 2002 to consummate the offer to exchange, which closed in April, 2002, and to refinance our revolving loan facility. We used $8.0 million in our financing activities in 2000 primarily to repurchase and retire a portion of our 10½% Senior Notes and refinance our $50.0 million revolving loan facility. The $8.5 million provided by financing activities in 1999 was used primarily to fund working capital. For a complete listing of our debt obligations see Notes 4 and 5 of the notes to our Consolidated Financial Statements included elsewhere in this prospectus.

Exchange Transaction.    On March 5, 2002, we commenced an offer to exchange with respect to our 10½% Senior Notes due 2004 (the “Exchange Transaction”). The offer to exchange expired on April 19, 2002. As part of the offer to exchange, approximately $114.8 million principal amount of the 10½% Senior Notes plus approximately $2.9 million in accrued but unpaid interest was exchanged for approximately $60.0 million principal amount of new Senior Secured Notes and 900,000 shares of our Class A common stock. The value of the 900,000 shares of Class A common stock issued was approximately $29.6 million and represents 90% of our voting stock after the exchange. See Notes 4 and 5 of the notes to our Consolidated Financial Statements included elsewhere in this prospectus/proxy statement for a more detailed discussion of the offer to exchange.

In connection with the offer to exchange, we issued 200,000 shares of special stock to SRH. The special shares have no voting rights, no rights to receive dividends and no rights to participate in any liquidation or dissolution. We also issued 100,000 shares of common stock to SRH, which represents 10% of our issued and outstanding voting share capital. If prior to or on October 19, 2003, we pay in cash in full the Senior Secured Notes, the special shares held by SRH will automatically convert on the date of such payment into shares of common stock, on a basis of one share of common stock per share of special stock issued and outstanding. Upon conversion of the special shares into shares of common stock, combined with the 100,000 shares of common stock which is currently held by SRH, SRH would then own 25% of our issued and outstanding voting share capital. If, prior to or on October 19, 2003, we either (i) fail to pay in cash in full the Senior Secured Notes or (ii) there is a voluntary or involuntary bankruptcy filing by or against us, then upon the earlier of such events, the shares of special stock shall be deemed canceled, shall be null and void and of no further effect. Upon the cancellation of the special shares, SRH would continue to own only 10% of our issued and outstanding voting share capital.

Refinance Transaction.    On April 19, 2002, we entered into a revolving credit agreement with a syndicate of banks. The credit agreement provides for an aggregate of $80.0 million senior secured revolving line of credit and is secured by all of our assets and is guaranteed by our subsidiaries. The credit agreement has a maturity date of April 30, 2004. See Note 5 of the notes to our Consolidated Financial Statements included elsewhere in this prospectus/proxy statement.

All outstanding balances under the credit agreement may be designated, at our option, as either prime rate or LIBOR rate options, provided that no more than four LIBOR rate options may be outstanding at any given time. The prime rate option is the greater of (i) the rate publicly announced from time to time by the Union Bank as its prime rate or (ii) the federal funds rate plus .50% per annum. The LIBOR rate option is equal to LIBOR plus 225 to 275 basis points, depending on the borrowing base usage percentage. Both options will accrue on the basis of a 360-day year.

The purpose of the credit agreement is to provide funds for (i) the refinancing of the revolving loan facilities due August, 2002 (the refinance of the revolving loan facility funded on April 22, 2002), (ii) to purchase oil and gas properties and (iii) working capital and letters of credit. Letters of credit may be issued subject to availability under the credit agreement and the total of all outstanding letters of credit may not exceed $5.0 million in the aggregate and the term shall not exceed 12 months or the maturity, whichever comes first. As of June 30, 2002,

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we had drawn approximately $55.0 million, issued letters of credit for approximately $2.9 million and have approximately $1.1 million remaining available.

The Credit Agreement imposes certain limitations on the ability of Southwest and its subsidiary guarantors to, among other things, incur additional indebtedness or issue disqualified capital stock, make payments in respect to capital stock, enter into transactions with affiliates, incur liens, sell assets, change the nature of its business, merge or consolidate with an other person or renew, extend, modify or amend the indentures.

Our new credit agreement also includes restrictive covenants related to the maintenance of quarterly cash flow and interest coverage. We believe we will be able to meet these quarterly covenants over the next 12 months based on our current financial projections. However, if circumstances were to change and an event of default were to occur we would be required to renegotiate with our current lender or secure other suitable secured financing. No assurance can be given that we would be able to accomplish such refinancing.

We were in violation of the Funded Debt Coverage Ratio at June 30, 2002. Funded Debt is defined in the Revolving Credit Agreement, as the face amount owed on the 10.5% Senior Notes, the Senior Secured Notes and the Revolving Credit Agreement. On September 10, 2002, this violation was waived by the Banks and the credit agreement was amended to delete the Funded Debt coverage Ratio covenant in its entirety. Also, as part of the amendment, the borrowing base was reviewed and it was determined that, effective September 1, 2002, the borrowing base shall be $60.0 million and the monthly commitment reduction shall be $0 until such time as it may change based on future redeterminations. The next redetermination is scheduled for April 30, 2002, however, an unscheduled redetermination can take place prior to this date at the sole discretion of the lenders.

Hedging Activities.    From time to time, we use option contracts to mitigate the volatility of price changes on commodities we produce and sell as well as to lock in prices to protect the economics related to certain capital projects.

Other Issues

Derivative Instruments and Hedging Activities

We have only limited involvement with derivative financial instruments and do not use them for trading purposes. They are used to manage commodity price risks. We are exposed to credit losses in the event of nonperformance by the counter-parties to our commodity hedges. We do not obtain collateral or other security to support financial instruments subject to credit risk but monitor the credit standing of the counter-parties.

Through December 31, 2000, premiums paid for commodity option contracts which qualified as hedges under Statement of Accounting Standards (“SFAS”) No. 80 “Accounting for Futures Contracts,” were amortized to oil and gas sales over the term of the agreements. Unamortized premiums were included in other assets in the consolidated balance sheet. Amounts receivable or payable under the commodity option contracts were accrued as an increase or decrease in oil and gas sales for the applicable periods. Effective January 1, 2001, derivative financial instruments are accounted for in accordance with SFAS 133 as amended by SFAS 138.

As of January 1, 2001, we adopted Statement of Financial Accounting Standards SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to changes in the fair value of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign

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currency denominated forecasted transaction. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in our statement of operations. We recorded a net transition adjustment gain of $1,030,000 in accumulated other comprehensive income on January 1, 2001. The transition adjustment as of June 30, 2002 has been fully amortized to oil and gas sales.

Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (“FASB”) issued Statements of Financial Accounting Standards (SFAS) No. 141 “Business Combinations” and SFAS No. 142 “Goodwill and Other Intangible Assets.” SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method and SFAS No. 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. There is no impact to our financial statements, as we have not entered into any business combinations subsequent to June 30, 2001 that required the recording of goodwill or other intangible assets.

In October 2001, FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. We are currently assessing the impact on our financial statements.

In October 2001, the FASB issued SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supersedes SFAS No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed” and eliminates the requirement of SFAS No. 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. We adopted SFAS No. 144 on January 1, 2002. We believe that the impact from SFAS No. 144 on our financial position and results of operations should not be significantly different from that of SFAS No. 121.

SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” was issued in April 2002. SFAS No. 145 provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions, SFAS No. 145 is effective for us in January 2003. We are currently evaluating the impact of SFAS No. 145.

In July 2002, the FASB issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities” which establishes requirements for financial accounting and reporting for costs associated with exit or disposal activities initiated after December 31, 2002. We are currently evaluating the impacts of SFAS No. 146.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about financial instruments to which we are a party as of June 30, 2002, and from which we may incur future earnings gains or losses from changes in market interest rates or commodity prices.

Quantitative Disclosures

Interest rate sensitivity.    The following table provides information about our debt obligations, which are sensitive to changes in interest rates. The table presents cash maturities by expected maturity dates together with the weighted average interest rates expected to be paid on the debt, given current contractual terms and market conditions. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that we are obligated to periodically pay on the debt; for variable rate debt, the average interest rate represents the average rates being paid on the debt at June 30, 2002.

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	As of June 30,
	2003			2004			2005			2006			2007			Thereafter			Total		Fair Value
Total debt maturities	$	18,204		$	112,159		$	8,870		$	17		$	19		$	835		$	140,104	$	140,104
Fixed rate debt	$	180		$	114		$	8,870		$	17		$	19		$	835		$	10,035	$	10,035
Weighted average interest rate		10.23	%		10.26	%		8.05	%		8.05	%		8.05	%		8.05	%
Variable rate debt	$	18,024		$	112,045		$	—		$	—		$	—		$	—		$	130,069	$	130,069
Average interest rate		12.13	%		12.13	%		—	%		—	%		—	%		—	%

Commodity price sensitivity.    See Note 1 of the Notes to our Consolidated Financial Statements included elsewhere in this prospectus for a description of the accounting procedures followed by us relative to hedge derivative financial instruments and for specific information regarding the terms of our derivative financial instruments which are sensitive to changes in natural gas and crude oil commodity prices.

From time to time, we use option contracts to mitigate the volatility of price changes on commodities we produce and sell as well as to lock in prices to protect the economics related to certain capital projects.

On December 30, 1999, we entered into a basket revenue protection agreement, which provided us with an oil and gas revenue floor. The contract was for the period January 1, 2000 through December 31, 2000. The agreement was to be calculated on a calendar year quarter as disclosed in the following table based on NYMEX Natural Gas and NYMEX Crude Oil:

	Notional Volumes		Strike Prices
	Crude Oil (Bbls)	Natural Gas (MMBtu)	Crude Oil		Natural Gas		Boe		Minimum Revenue
Quarter 1	269,254	976,676	$	21.12	$	1.91	$	28.76	$	7,552,096
Quarter 2	263,058	910,325	$	18.80	$	1.92	$	26.56	$	6,714,359
Quarter 3	257,206	857,728	$	18.00	$	1.97	$	25.88	$	6,319,432
Quarter 4	251,914	813,400	$	18.00	$	2.20	$	26.80	$	6,323,932

Payments were required to be made no later than five business days after each quarterly floating price was determined by NYMEX. The cost of the floor was approximately $638,000 and was amortized monthly as a reduction of oil and gas revenues. The cost of the floor was fully amortized at the conclusion of the December 31, 2000 contract period.

On September 6, 2000, we entered into a floor option, which provided us with a crude oil price floor. The contract was for the period January 1, 2001 through December 31, 2001. The option was for a notional amount of 1,100 Bbls of oil a day at a floor price of $25, based on NYMEX Light Sweet Crude. The agreement was calculated on a monthly basis with payments to be made no later than five business days after the calculation period. The cost of the floor was approximately $466,000.

On October 11, 2000, we entered into a floor option, which provided us with a crude oil price floor. The contract was for the period January 1, 2001 through December 31, 2001. The option was for a notional amount of 500 Bbls of oil a day at a floor price of $27, based on NYMEX Light Sweet Crude. The agreement was calculated on a monthly basis with payments to be made no later than five business days after the calculation period. The cost of the floor was approximately $224,000.

On November 20, 2000, we entered into a floor option, which provided us with a crude oil price floor. The contract was for the period June 1, 2001 through May 31, 2002. The option was for a notional amount of 1,000 Bbls of oil a day at a floor price of $22, based on NYMEX Light Sweet Crude. The agreement was calculated on a monthly basis with payments to be made no later than five business days after the calculation period. The cost of the floor was approximately $310,000.

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On December 1, 2000, we entered into a floor option, which provided us with a natural gas price floor. The contract was for the period June 1, 2001 through May 31, 2002. The option was for a notional amount of 3,325 MMBtu of natural gas a day at a floor price of $3.00, based on NYMEX Henry Hub. The agreement was calculated on a monthly basis with payments to be made no later than five business days after the calculation period. The cost of the floor was approximately $140,000.

On December 8, 2000, we entered into a floor option, which provided us with a natural gas price floor. The contract was for the period April 1, 2001 through March 31, 2002. The option was for a notional amount of 1,700 MMBtu of natural gas a day at a floor price of $4.50, based on NYMEX Henry Hub. The agreement was calculated on a monthly basis with payments to be made no later than five business days after the calculation period. The cost of the floor was approximately $416,000.

On February 14, 2001, we entered into a floor option, which provided us with a natural gas price floor. The contract was for the period April 1, 2001 through March 31, 2002. The option was for a notional amount of 3,000 MMBtu of natural gas a day at a floor price of $4.25, based on NYMEX Henry Hub. The agreement was calculated on a monthly basis with payments to be made no later than five business days after calculation period. The cost of the floor was approximately $296,000.

On February 14, 2001, we entered into a floor option, which provided us with a natural gas price floor. The contract was for the period March 1, 2001 through August 31, 2001. The option was for a notional amount of 5,000 MMBtu of natural gas a day at a floor price of $4.50, based on NYMEX Henry Hub. The agreement was calculated on a monthly basis with payments to be made no later than five business days after calculation period. The cost of the floor was approximately $156,000.

In May, 2002, we entered into a collar, which provides us with a natural gas price ceiling and floor. The contract is for the period June, 2002 through May, 2003. The collar is for a notional amount of 6,000 MMBtu of natural gas a day at a ceiling price of $5.70 and a floor price of $3.00, based on NYMEX Henry Hub.

In May, 2002, we entered into a collar, which provides us with a crude oil price ceiling and floor. The contract is for the period June, 2002 through May, 2003. The collar is for a notional amount of 1,500 Bbls of oil a day at a ceiling price of $27.25 and a floor price of $21.00, based on NYMEX Light Sweet Crude.

In July, 2002, we entered into a collar, which provides us with a natural gas price ceiling and floor. The contract is for the period June, 2003 through August, 2003. The collar is for a notional amount of 5,000 MMBtu of natural gas a day at a ceiling price of $4.90 and a floor price of $3.00, based on NYMEX Henry Hub.

In July, 2002, we entered into a collar, which provides us with a crude oil price ceiling and floor. The contract is for the period June, 2003 through August, 2003. The collar is for a notional amount of 1,300 Bbls of oil a day at a ceiling price of $27.60 and a floor price of $21.00, based on NYMEX Light Sweet Crude.

We have not elected to use hedge accounting on the above noted instruments, and therefore, effective January 1, 2001, we marked to market these items and recorded all gains and losses through earnings.

Enron Bankruptcy

In the fourth quarter of 2001, we and many others throughout the oil and gas industry were affected by the bankruptcy filing of Enron Corp. and subsidiaries. All of the Commodity Option Contracts referred to above, which had any affect on 2001 activity, were with Enron. As a result of our evaluation of the increased credit risk associated with Enron pursuant to Enron’s bankruptcy filing, we set up an allowance for all amounts owed to us by Enron, which was approximately $1.1 million and marked to market all remaining Enron related Commodity Option Contracts by setting up an allowance for the fair market value of the contracts as of December 1, 2001 of approximately $2.1 million. The total charge to other expense during the fourth quarter of 2001, relating to the Enron bankruptcy was approximately $3.2 million.

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Qualitative Disclosures

Non-derivative financial instruments.    We are a borrower under fixed rate and variable rate debt instruments that give rise to interest rate risk. Our objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing our costs of capital. To realize our objectives, we borrow under fixed and variable rate debt instruments, based on the availability of capital and market conditions. See Note 5 of the Notes to our Consolidated Financial Statement included elsewhere in this prospectus for a discussion relative to our debt instruments.

Derivative financial instruments.    Revenues from our operations are highly dependent on the price of oil and gas. The markets for oil and natural gas are volatile and prices for oil and gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas and a variety of additional factors that are beyond our control. These factors include the level of consumer demand, weather conditions, domestic and foreign governmental regulations, market uncertainty, the price and availability of alternative fuels, political conditions in the Middle East, foreign imports and overall economic conditions. It is impossible for us to predict future oil and gas prices with any certainty. In order to reduce our exposure to oil and gas price risks, from time to time we enter into commodity price derivative contracts to hedge commodity price risks.

As of June 30, 2002, our primary risk exposures associated with financial instruments to which we are a party include natural gas and crude oil price volatility and interest rate volatility.

THE PARTNERSHIPS

The partnerships that we propose to include in the merger consist of institutional income funds, oil and gas income funds, developmental drilling funds, a combination income/drilling fund and an investment fund. We are the managing general partner of each partnership. The principal executive office for all of the partnerships is located at 407 North Big Spring, Suite 300, Midland, Texas 79701 and the telephone number is (915) 686-9927.

General information about the partnerships is provided below. Appendix A to this prospectus/proxy statement sets forth additional information for each partnership, including jurisdiction of organization, number of limited partners, aggregate Merger Value and historical partnership distributions to limited partners. In addition, the prospectus supplement for each partnership constitutes an integral part of this prospectus/proxy statement. You should read Appendix A and the prospectus supplement for any partnership in which you are a limited partner carefully in its entirety.

General

The partnerships were formed by us from 1986 through 1994. Of the 21 partnerships that we propose to include in the merger, 14 were formed for the purpose of acquiring, selling, leasing, exchanging and otherwise dealing in producing oil and gas properties and producing and marketing crude oil and natural gas obtained from those properties. These “Income Fund” partnerships, per their partnership agreements, cannot participate in drilling activities or leverage their assets. Five of the partnerships were organized to engage primarily in the business of drilling developmental wells and producing and marketing crude oil and natural gas obtained from those wells. These “Drilling Fund” partnerships could allocate up to 20% of their original net capital contributions to drill exploratory wells but cannot incur indebtedness. These original net capital contributions, however, have been expended, and the Drilling Fund partnerships are no longer able to engage in drilling or the exploration of new reserves. One partnership had dual investment abilities and engaged in the business of acquiring producing oil and gas properties, drilling developmental and/or exploratory oil and gas wells and producing and marketing crude oil and natural gas derived from those properties. This “Combination Fund” is also prohibited from incurring indebtedness and, likewise, has no available capital for drilling or enhancements. One partnership, an “Investment Fund,” was formed to acquire or invest in mid-market oil and gas companies. Target acquisitions were to be in the range of $1.0 million to $50.0 million. This Investment Fund can purchase direct interests in oil and gas properties and drilling developmental and exploratory wells. Unlike the other partnerships, this Investment Fund can borrow funds not to exceed 400% of its capital contributions at any given time.

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Set forth below is a table identifying each of these partnerships and the type of initial offering of limited partner interests, the contribution, if any, made by Southwest as the managing general partner, and the allocation percentages of net profits and losses between the limited partners and general partners for each partnership.

Income Funds

Name of Partnership	Type of Offering	Contribution by Managing General Partner	Distribution Split (Limited Partner %-   General Partner %)
Southwest Royalties, Inc. Income Fund V, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties, Inc. Income Fund VI, L.P.	Public Offering	None	90% LP-10% GP
Southwest Oil & Gas Income Fund VII-A, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties Institutional Income Fund VII-B, L.P.	Public Offering	None	90% LP-10% GP
Southwest Oil & Gas Income Fund VIII-A, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties Institutional Income Fund VIII-B, L.P.	Public Offering	None	90% LP-10% GP
Southwest Oil & Gas Income Fund IX-A, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties Institutional Income Fund IX-B, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties Institutional Income Fund X-A, L.P.	Public Offering	None	90% LP-10% GP
Southwest Oil & Gas Income Fund X-A, L.P.	Public Offering	None	90% LP-10% GP
Southwest Oil & Gas Income Fund X-B, L.P.	Public Offering	None	90% LP-10% GP
Southwest Oil & Gas Income Fund X-C, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties Institutional Income Fund X-B, L.P.	Public Offering	None	90% LP-10% GP
Southwest Royalties Institutional Income Fund X-C, L.P.	Public Offering	None	90% LP-10% GP

Drilling Funds

Name of Partnership	Type of Offering	Contribution by Managing General Partner	Distribution Split (Limited Partner %-   General Partner %)
Southwest Developmental Drilling Fund 1990, L.P.	Private Placement	None	85% LP-15% GP
Southwest Developmental Drilling Fund 91-A, L.P.	Public Offering	1% of lease acquisition and drilling costs	89% LP-11% GP
Southwest Developmental Drilling Fund 92-A, L.P.	Public Offering	1% of lease acquisition and drilling costs	89% LP-11% GP
Southwest Developmental Drilling Fund 1993, L.P.	Private Placement	1% of lease acquisition and drilling costs	89% LP-11% GP
Southwest Developmental Drilling Fund 1994, L.P.	Private Placement	1% of lease acquisition and drilling costs	89% LP-11% GP

Combination Fund

Name of Partnership	Type of Offering	Contribution by Managing General Partner	Distribution Split (Limited Partner %-   General Partner %)
Southwest Combination Income/Drilling Program 1988, L.P.	Private Placement	None	85% LP-15% GP

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Investment Fund

Name of Partnership	Type of Offering	Contribution by Managing General Partner	Distribution Split (Limited Partner %- General Partner %)
Southwest Partners, L.P.	Private Placement	10% of total limited partner capital contributions	85% LP-15% GP

Each of the partnerships raised capital either through a private placement or a public offering. As of June 30, 2002, there are approximately 8,390 limited partners that in the aggregate own limited partner interests in the partnerships. H.H. Wommack, III, a significant stockholder of Southwest and our Chairman, President and Chief Executive Officer, serves as a 1% “additional general partner” in Oil & Gas Income Fund IX-A, Institutional Income Fund IX-B, Institutional Income Fund X-B, Oil & Gas Income Fund X-B, Institutional Income Fund X-A, Oil & Gas Income Fund X-A, Institutional Income Fund X-C, Oil & Gas Income Fund X-C, and Combination Income Drilling Program 1988. Mr. Wommack, however, plans to transfer his general partner interests in these partnerships to Southwest for no consideration prior to the consummation of the merger. All of the partnerships were offered to investors as “blind pools” in which the funds raised were not allocated to the purchase of specific properties.

Set forth below is a table identifying the following information regarding the initial offering for each partnership: the closing date for the initial offering of limited partner interests, the aggregate proceeds from limited partners in the initial offering and the price per unit of limited partner interests.

Income Funds

Name of Partnership	Closing Date of Initial Offering	Aggregate Proceeds from Initial Offering (Limited Partner Investment only)		Limited Partner Unit Price
Southwest Royalties, Inc. Income Fund V, L.P.	7/22/86	$	7,499,130	$	1,000
Southwest Royalties, Inc. Income Fund VI, L.P.	1/29/87	$	10,000,000	$	500
Southwest Oil & Gas Income Fund VII-A, L.P.	9/21/87	$	7,500,000	$	500
Southwest Royalties Institutional Income Fund VII-B, L.P.	12/1/87	$	7,500,000	$	500
Southwest Oil & Gas Income Fund VIII-A, L.P.	3/31/89	$	6,798,000	$	500
Southwest Royalties Institutional Income Fund VIII-B, L.P.	3/31/89	$	5,073,500	$	500
Southwest Oil & Gas Income Fund IX-A, L.P.	3/31/90	$	5,226,500	$	500
Southwest Royalties Institutional Income Fund IX-B, L.P.	3/31/90	$	4,891,000	$	500
Southwest Royalties Institutional Income Fund X-A, L.P.	11/30/90	$	5,658,000	$	500
Southwest Oil & Gas Income Fund X-A, L.P.	11/30/90	$	5,242,000	$	500
Southwest Oil & Gas Income Fund X-B, L.P.	9/30/91	$	5,444,500	$	500
Southwest Oil & Gas Income Fund X-C, L.P.	4/30/92	$	3,123,000	$	500
Southwest Royalties Institutional Income Fund X-B, L.P.	9/30/91	$	5,590,500	$	500
Southwest Royalties Institutional Income Fund X-C, L.P.	4/30/92	$	2,991,500	$	500

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Drilling Funds

Name of Partnership	Closing Date of Initial Offering	Aggregate Proceeds from Initial Offering (Limited Partner Investment only)		Limited Partner Unit Price
Southwest Developmental Drilling Fund 1990, L.P.	12/31/90	$	1,735,000	$	10,000
Southwest Developmental Drilling Fund 91-A, L.P.	4/30/92	$	1,144,500	$	1,000
Southwest Developmental Drilling Fund 92-A, L.P.	12/31/92	$	1,407,000	$	1,000
Southwest Developmental Drilling Fund, 1993, L.P.	12/27/93	$	2,078,000	$	1,000
Southwest Developmental Drilling Fund 1994, L.P.	12/27/94	$	2,235,000	$	1,000

Combination Fund

Name of Partnership	Closing Date of Initial Offering	Aggregate Proceeds from Initial Offering (Limited Partner Investment only)		Limited Partner Unit Price
Southwest Combination Income/Drilling Program 1988, L.P.	10/31/89	$	1,754,500	$	500

Investment Fund

Name of Partnership	Closing Date of Initial Offering	Aggregate Proceeds from Initial Offering (Limited Partner Investment only)		Limited Partner Unit Price
Southwest Partners, L.P.	11/19/93	$	4,350,000	$	100,000

The investment objective for each partnership was to use the proceeds from its initial offering to either purchase and/or develop producing properties or engage in developmental drilling and, in each case, make distributions from the profits generated from such activities. We believe that we have achieved this investment objective in the case of each partnership.

Business

The following information is generally applicable to the business and operations of all of the partnerships. It does not contain all of the individual partnership information which may be important to you. For more specific information regarding the business and operations of individual partnerships, see the prospectus supplement(s) for each partnership in which you are a limited partner. The prospectus supplement for each partnership constitutes an integral part of this prospectus/proxy statement.

Institutional Income Funds.     The institutional income funds were formed to acquire non-operating interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. These partnerships acquired and hold royalty, overriding royalty and net profit interests in oil and gas properties primarily located in the Permian Basin. All activities of the partnerships are confined to the continental United States. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business.

Oil and Gas Income Funds.     The oil and gas income funds were formed to acquire working and other interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. These partnerships acquired and hold working interests in oil and gas properties located primarily in the Permian Basin.

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All activities of the partnerships are confined to the continental United States. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business.

Drilling Funds.     The drilling funds were formed to engage in drilling developmental and exploratory wells for oil and natural gas primarily in the Permian Basin. All drilling activity ceased upon the use of designated partnership funds. The partnerships are now limited to producing and marketing the oil and gas derived from their drilling activities. The partnerships are prohibited from engaging in off-shore drilling.

Combination Drilling/Income Fund.     The combination income/drilling fund combines the objectives of an income and drilling program. The partnership owns producing oil and gas properties located in the Permian Basin and was formed to engage in drilling developmental and exploratory wells. All drilling activity ceased upon use of designated partnership funds. The partnership is now limited to producing and marketing the oil and gas derived from their drilling activities. The partnerships is prohibited from engaging in off-shore drilling.

Investment Fund.     The investment fund was formed to acquire or invest in mid-market oil and gas companies. Acquisition purchase prices and amounts to be invested were to range from $1.0 million to $50.0 million. In addition, the investment fund could purchase direct interests in oil and gas properties and drilling developmental and exploratory wells.

All of the partnerships have expended their capital and produce and market the crude oil and natural gas produced from their properties. In many cases, the partnerships purchased royalty or overriding royalty interests and working interests in oil and gas properties that were converted into net profits interests or other nonoperating interests. The partnerships purchased either all or part of the rights and obligations under various oil and gas leases.

Southwest, as the managing general partner of the partnerships, and its staff of 89 individuals, together with certain independent consultants used on an “as needed” basis, perform various services on behalf of the partnerships, including the selection of oil and gas properties and the marketing of production from such properties.

Principal Products; Marketing and Distribution

The revenues generated from each partnership’s oil and gas activities are dependent upon the current market for oil and gas. The prices received by each partnership for its oil and gas production depend upon numerous factors beyond its control, including competition, economic, political and regulatory developments and competitive energy sources, and make it particularly difficult to estimate future prices of oil and natural gas.

During 2001, despite fears of a global recession, crude oil prices held steady between $26 and $28 per barrel due in part to a series of OPEC and non-OPEC production cuts. Then, following the terrorist attacks on September 11, crude prices plunged immediately to $22 and gradually fell to below $18 per barrel. Slower demand across the United States caused by the threat of recession and warmer than expected weather also led to declining prices in the latter half of 2001. However, OPEC and other non-member countries agreed for the fourth time since February to curb output in an effort to stabilize prices. Crude oil contracts trading on the NYMEX closed in 2001 at approximately $20 per barrel.

Spot prices in 2001 climbed to their highest levels ever, with the yearly average price nationwide reaching $4.14/MMBtu, up 9.77% from the 2000 average of $3.77/MMBtu. Prices reached their highest level in the first quarter of 2001 before beginning a steady decline throughout the remainder of the year. The terrorist attacks of September 11, 2001, closed the NYMEX market for several days and shook the spot marketplace into a maintenance mode. As companies measured the impact of the attacks on the United States economy, spot prices deteriorated further. In the fourth quarter, prices bottomed out for the year with the three-month average falling to $2.31/MMBtu. As for 2002, record-high storage levels and the expectation of a flat economy through the first

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half of the year are leading industry experts to predict prices to average $2.05/MMBtu, remaining above the $2.00 per MMBtu level for a fifth consecutive year.

Seasonality of Business

The partnerships’ business is not seasonal, except that the demand for natural gas is higher in the colder winter months and in very hot summer months. The partnerships have been able to sell all of their natural gas, either through contracts in place or on the spot market at the then prevailing spot market price. As a result, the volumes sold by the partnerships have not fluctuated materially with the change of season.

Competition

Because the partnerships have utilized all of its funds available for the acquisition of net profits or royalty interests in producing oil and gas properties or drilling operations, as applicable, they are not subject to competition from other oil and gas property purchasers.

Factors that may adversely affect the partnerships include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.

Regulation

Oil and Gas Production.     The production and sale of oil and gas is subject to federal and state governmental regulation in several respects, such as existing price controls on natural gas and possible price controls on crude oil, regulation of oil and gas production by state and local governmental agencies, pollution and environmental controls and various other direct and indirect regulations. Many jurisdictions have periodically imposed limitations on oil and gas production by restricting the rate of flow for oil and gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of wells. The federal government has the power to permit increases in the amount of oil imported from other countries and to impose pollution control measures.

Various aspects of the partnerships’ oil and gas activities are regulated by administrative agencies under statutory provisions of the states where such activities are conducted and by certain agencies of the federal government for operations on federal leases. Moreover, certain prices at which the partnerships may sell their natural gas production are controlled by the Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act of 1989 and the regulations promulgated by the Federal Energy Regulatory Commission.

Environmental.     The partnerships’ oil and gas activities are subject to extensive federal, state and local laws and regulations governing the generation, storage, handling, emission, transportation and discharge of materials into the environment. Governmental authorities have the power to enforce compliance with their regulations, and violations carry substantial penalties. This regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. We are unable to predict what, if any, effect our compliance burdens will have on the partnerships.

Industry Regulations and Guidelines.     Certain industry regulations and guidelines apply to the registration, qualification and operation of oil and gas programs in the form of limited partnerships. The partnerships are subject to these guidelines which regulate and restrict transactions between Southwest, as the managing general partner, and the partnerships. The partnerships comply with these guidelines and we do not anticipate that continued compliance will have a material adverse effect on partnership operations.

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Partnership Employees

The partnerships have no employees; however, Southwest, as the managing general partner, has a staff of geologists, engineers, accountants, landmen and clerical staff who engage in partnership activities and operations and perform additional services for the partnerships as needed. In addition to our staff, the partnerships engage independent consultants such as petroleum engineers and geologists as needed. As of December 31, 2001, there were 89 individuals directly employed by Southwest in various capacities.

Financial Information About Geographic Areas

Since inception of each of the partnerships, their revenues are attributed to customers located only in the United States. Since inception of each of the partnerships, their long-lived assets, long-term customer relationships with financial institutions, mortgages and other servicing rights, deferred policy acquisition costs and deferred tax assets, if any, are located only in the United States.

Properties

In determining whether an interest in a particular producing property was to be acquired, we, as the managing general partner, considered such criteria as estimated oil and gas reserves, estimated cash flow from the sale of production, present and future prices of oil and gas, the extent of undeveloped and unproved reserves, the potential for secondary, tertiary and other enhanced recovery projects and the availability of markets.

Legal Proceedings

There are no material pending legal proceedings to which any of the partnerships are a party.

Market for the Partnerships’ Limited Partner Interests and Related Partnership Matters

Market Information

With the exception of Southwest Income Fund V, Southwest Developmental Drilling Fund 91-A, Southwest Developmental Drilling Fund 92-A, Southwest Developmental Drilling Fund 1994, Southwest Developmental Drilling Fund 1990, Southwest Developmental Drilling Fund 1993 and Southwest Partners, all limited partner interests were initially offered and sold for a price of $500. Limited partner interests in Income Fund V, Developmental Drilling Fund 91-A, Developmental Drilling Fund 92-A, and Developmental Drilling Fund 1994, were initially offered and sold for a price of $1,000. Limited partner interests in Drilling Fund 1990 were initially offered and sold for a price of $10,000. Limited partner interests in Southwest Partners were initially offered and sold for a price of $100,000. Limited partner interests are not traded on any exchange and there is no public or organized trading market for them. We, as the managing general partner, are aware of certain limited and sporadic transfers of interests between limited partners and third parties, but have no verifiable information regarding the prices at which such interests have been transferred. Further, a transferee may not become a substitute limited or general partner without our consent, as the managing general partner.

Holders

There are a total of approximately 8,390 holders of limited partner interests in all 21 partnerships as of June 30, 2002.

Dividends

For information on dividends of each partnership, we encourage you to read the section entitled  “COMPENSATION AND DISTRIBUTIONS” in each prospectus supplement in which you are a limited partner, as well as review Table 5 of Appendix A of this prospectus/proxy statement. The average quarterly cash distributions per $500 limited partner investment in each partnership for 2000, 2001 and year-to-date in 2002 are set forth in Table 5 of Appendix A.

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SOUTHWEST CONSOLIDATED PARTNERSHIPS

Southwest Consolidated Partnerships, Inc. is a newly-formed Delaware corporation and a wholly-owned subsidiary of Southwest. The principal executive office for Southwest Consolidated Partnerships is located at 407 North Big Spring, Suite 300, Midland, Texas 79701 and the telephone number is (915) 686-9927. General information about the business activities of Southwest Consolidated Partnerships is described below.

General

Southwest Consolidated Partnerships was formed in October, 2002 by Southwest for the purpose of structuring the merger. The partnerships will merge with and into Southwest Consolidated Partnerships, and limited partners will receive shares of Southwest Consolidated Partnerships common stock in exchange for their limited partner interests based on the relative value of their ownership interest in their partnership compared to the total value of Southwest and all partnerships that participate in the merger. Upon consummation of the merger of the partnerships with and into Southwest Consolidated Partnerships, limited partners will own 100% of Southwest Consolidated Partnerships.

Business

Southwest Consolidated Partnerships is a newly-formed corporation and a wholly-owned subsidiary of Southwest. It currently holds no assets and has no liabilities. Upon the consummation of the merger of the partnerships with and into Southwest Consolidated Partnerships, all of the assets and liabilities of the partnership that participate in the merger will become the assets and liabilities of Southwest Consolidated Partnerships. Immediately thereafter, Southwest Consolidated Partnerships will merge with and into Southwest Managed Assets, a wholly-owned subsidiary of Southwest, and Southwest Consolidated Partnerships will cease to exist.

SOUTHWEST MANAGED ASSETS

Southwest Managed Assets, Inc. is a newly-formed Delaware corporation and a wholly-owned subsidiary of Southwest. The principal executive office for Southwest Managed Assets is located at 407 North Big Spring, Midland, Texas 79701 and the telephone number is (915) 686-9927. General information about the business activities of Southwest Managed Assets is provided below.

General

Southwest Managed Assets was formed in October, 2002 by Southwest for the purpose of structuring the merger. After the partnerships merge with and into Southwest Consolidated Partnerships, Southwest Consolidated Partnerships will immediately merge with and into Southwest Managed Assets.

Business

Southwest Managed Assets is a newly-formed corporation and a wholly-owned subsidiary of Southwest. It currently holds no assets and has no liabilities. Prior to the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, we will transfer to Southwest Managed Assets 688,347 shares of our common stock (assuming all 21 partnerships participate in the merger). Upon the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, stockholders of Southwest Consolidated Partnerships, which are the former limited partners of the partnerships participating in the merger, will receive shares of our common stock in exchange for their Southwest Consolidated Partnerships common stock. Upon the consummation of the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, Southwest Consolidated Partnerships will cease to exist and the assets and liabilities of Southwest Consolidated Partnerships will become the assets and liabilities of Southwest Managed Assets. Southwest Managed Assets will remain a wholly-owned subsidiary of Southwest.

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BACKGROUND AND REASONS FOR THE MERGER

Overview

We are proposing the merger of 21 public and private partnerships of which we are the managing general partner into Southwest’s subsidiary, Southwest Consolidated Partnerships and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest’s subsidiary, Southwest Managed Assets. Limited partners will ultimately receive shares of our common stock in the merger. Additionally, we will issue shares of our special stock into an escrow account, which shares are intended to prevent the limited partners from being diluted under certain circumstances. Upon consummation of the merger, all assets and liabilities of the partnerships participating in the merger will become the assets and liabilities of our wholly-owned subsidiary, Southwest Managed Assets, and the participating partnerships and Southwest Consolidated Partnerships will cease to exist.

Set forth below are diagrams detailing the proposed structure of the merger:

⁽¹⁾ Class A common stock will automatically convert into our common stock on the basis of one share of common stock for each share of Class A common stock issued and outstanding upon completion of the merger and in the event our common stock becomes authorized for quotation on Nasdaq (National Market).

⁽²⁾ Prior to the merger, we will capitalize Southwest Managed Assets, Inc. with shares of our common stock.

⁽³⁾ Prior to the merger, we will issue shares of our special stock, which we will designate as Series B special stock, into an escrow account. In the event our shares of Series A special stock held by our former parent, SRH, convert into common stock, the Series B special stock will likewise convert into common stock. Thereafter, the escrow agent will distribute those shares of common stock to the limited partners.

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⁽¹⁾ The partnerships will merge into Southwest Consolidated Partnerships, Inc. Limited partners will momentarily receive shares of common stock of Southwest Consolidated Partnerships, Inc., but upon the subsequent merger of Southwest Consolidated Partnerships into Southwest Managed Assets (as illustrated in Step 3), former limited partners will receive shares of common stock of Southwest Royalties, Inc.

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⁽¹⁾ Southwest Consolidated Partnerships, Inc. will merge into Southwest Managed Assets, Inc., which has been capitalized by Southwest Royalties, Inc. with shares of Southwest Royalties, Inc. common stock, as shown in Step 1 above. Upon the merger of Southwest Consolidated Partnerships, Inc. into Southwest Managed Assets, Inc., Southwest Managed Assets will distribute the shares of Southwest Royalties, Inc. common stock to the former limited partners in exchange for the former limited partners’ shares of common stock in Southwest Consolidated Partnerships, Inc.

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⁽¹⁾ As discussed in Step 1, Class A common stock will automatically convert on the basis of one share of common stock for each share of Class A common stock issued and outstanding upon completion of the merger and in the event the common stock becomes authorized for quotation on Nasdaq (National Market).

⁽²⁾ Upon the completion of the merger, former limited partners will own shares of Southwest Royalties, Inc. common stock. Southwest Managed Assets will own all of the limited partnership assets and will continue to be a wholly-owned subsidiary of Southwest Royalties, Inc.

The merger agreement must be approved by at least 75% of the outstanding limited partner interests of a partnership before that partnership will be able to participate in the merger. We will not consummate the merger unless the limited partners of either Southwest Royalties, Inc. Income Fund VI, L.P. or Southwest Partners, L.P. approve the merger.

We are furnishing this prospectus/proxy statement to the limited partners of the partnerships in connection with our solicitation of proxies, for use at the special meeting of limited partners and at any adjournments or postponements of the special meeting.

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Background of the Merger

The partnerships were formed as either Delaware or Tennessee limited partnerships from 1986 through 1994, each under the sponsorship of Southwest. Southwest is the sole or managing general partner of all of the partnerships. Southwest chose to formulate a business plan in which it managed limited partnerships involved in the acquisition, exploration and development of oil and gas properties for several reasons. At that time, using limited partnerships as vehicles for raising capital was advantageous to Southwest due to the tax benefits it offered investors. Also, Southwest, in putting together the partnerships, received a carried-interest in each partnership, which was accretive to its own total oil and gas production.

In the mid-1990’s, limited partnership syndication slowed in the oil and gas industry, making it difficult for Southwest to access this type of capital. At the same time, Southwest desired to pursue its own corporate growth strategy and determined that it could not do so while continuing to devote substantial time and effort to the sponsorship of the partnerships and their activities. In 1995, Southwest stopped sponsoring oil and gas, drilling and income partnerships and began an aggressive development program to build its own reserve base. Southwest formulated a strategic plan to focus on its own core oil and gas assets, to build reserves through acquisitions and to eliminate ancillary operations. Through the 1990’s, Southwest completed over $250.0 million of oil and gas property acquisitions, both directly and through the partnerships it manages.

Between 1995 and 2000, Southwest had general, internal discussions about whether to consolidate each partnership pursuant to a merger or similar transaction. Southwest internally discussed potential transactions involving each partnership, including the basis for valuing each partnership and what type of consideration should be given to each partnership in connection with such transactions. On several occasions, Southwest engaged legal counsel and had discussions with investment banks about a possible combination with each of the partnerships. Several structures for a combination of the partnerships were outlined during these internal discussions and have included issuances of common stock, combinations of common stock and cash, and cash-only transactions through asset sales, mergers, tender offers, and combinations of these types of transactions. See “BACKGROUND AND REASONS FOR THE MERGER—Reasons for the Structure of the Merger” for a discussion of why Southwest is pursuing the merger in its current form.

In each of the prior instances when Southwest considered a combination of the partnerships, it decided not to complete a transaction for a variety of reasons. In some early cases, it wanted to avoid adverse tax consequences to either Southwest or the limited partners. In other cases, volatility in oil and gas prices made such a transaction unreasonable. On several occasions, Southwest was involved in other corporate transactions that could not be completed on schedule if a transaction involving the partnerships was also pending.

In early 2000, Southwest began to discuss the methods for valuing each partnership. At that time, Southwest engaged Baker, Donelson, Bearman & Caldwell, P.C. (“Baker Donelson”), its legal counsel, to assist it in evaluating a potential transaction with the partnerships. Southwest’s Board of Directors also engaged Jefferies & Company, based in Houston, Texas (“Jefferies”), its financial advisor, to review any proposed transaction and to render an opinion as to the fairness of the offer price, from a financial point of view, to the limited partners of each partnership.

In May 2000, Southwest’s Board of Directors met with Baker Donelson and Jefferies to discuss the proposed merger of each partnership. Jefferies presented an overview of the analysis it planned to perform in evaluating the fairness of the proposed transaction. Baker Donelson then reviewed and discussed with the Board the procedures that would be involved in completing the proposed transaction with the partnerships.

Members of the Southwest Board of Directors met informally on several occasions during July and early August of 2000 to discuss the proposed terms of the merger and other potential alternative transactions, including the formation of a master limited partnership into which the partnerships would merge.

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In the fall of 2000, Southwest decided to discontinue further discussions regarding a proposed merger. Because of the strengthening price of oil and gas and the unfavorable lending environment for oil and gas companies, Southwest pursued other potential growth opportunities, including the possibility of merging with a better capitalized strategic partner or partners.

During 2001, Southwest and Baker Donelson met on several occasions to discuss again the possibility of completing a merger transaction. In June 2001, Baker Donelson presented to Southwest’s management a comprehensive plan for the merger of the 21 partnerships with and into Southwest. Throughout the summer and fall of 2001, Southwest’s management and Baker Donelson formulated a strategy for the proposed merger and prepared regulatory and contractual documentation for the merger. In October 2001, however, due to Southwest’s significant debt service obligations and management’s belief that a merger proposal might not be well received by the limited partners at that time because of this significant level of debt, Southwest decided to postpone a potential merger transaction. In 1997, Southwest had completed a $200.0 million offering of 10½% Senior Notes due 2004 and, as of October 2001, $123.685 million of those notes remained outstanding. In the fourth quarter of 2001, based upon discussions with FBR, Southwest’s financial advisor, Southwest concluded that it needed to reduce its level of indebtedness in order to reduce the costs of servicing its debt; to enhance Southwest’s ability to obtain financing for working capital, capital expenditures and other needs; and to increase cash flow, which in turn, could be used to increase Southwest’s asset base and production.

On March 5, 2002, Southwest commenced an offer for its 10½% Senior Notes, plus any interest accrued but not paid thereon, in exchange for $60.0 million principal amount of Senior Secured Notes and 900,000 shares of Southwest Class A common stock. On April 19, 2002, the offer to exchange the 10½% Senior Notes expired, with holders of $114.815 million principal amount of the 10½% Senior Notes tendering in exchange for the Senior Secured Notes and Class A common stock. As of September 30, 2002, $8.87 million aggregate principal amount of the 10½% Senior Notes remained outstanding. Upon completion of the exchange, Southwest reduced its debt by approximately $54.815 million and decreased its annual interest payments by approximately $5.8 million. In connection with the exchange, a new Board of Directors was installed consisting of H.H. Wommack, III and six new members.

In late April 2002, as oil and gas prices continued to improve, and as a result of Southwest’s improved financial condition, Southwest renewed its internal discussions to consider a transaction involving each of the partnerships. For a discussion of why Southwest selected the proposed merger in its current form, see “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger.” Southwest determined that using its common stock as consideration for the merger would be appropriate, based upon improvements resulting from the recapitalization of Southwest.

On May 21, 2002, Southwest’s Board of Directors met with Baker Donelson and FBR to discuss legal and valuation issues of the merger. The Board of Directors reviewed the preliminary terms of the transaction during the FBR presentation, including possible pricing models and how the merger consideration would be structured. The Board of Directors engaged FBR to render an opinion as to the fairness of the merger at this meeting. FBR gave an initial assessment on the fairness of the merger based upon the data available at that time. Southwest’s Board of Directors discussed the fairness opinion to be delivered by FBR and decided to hold another meeting at which FBR would present, in detail, its methodology in determining that the Merger Value for each partnership and the allocation of the Merger Value of each partnership was fair (a) to the limited partners of each partnership as a group and (b) to Southwest as the managing general partner of each partnership, from a financial point of view. The Board of Directors tentatively decided to proceed but withheld final approval of the merger and any recommendation to the limited partners until it had reviewed the transaction further.

Between May and August 2002, management and legal counsel prepared materials for the merger, including Southwest and partnership financial statements and disclosure documentation to file with the SEC.

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On August 21, 2002, Southwest’s Board of Directors again met with Baker Donelson and FBR to discuss several legal issues Baker Donelson considered important to the merger and to receive a report from FBR on its fairness analysis. In particular, Baker Donelson reviewed the merger structure, the tax structure and the necessity for receiving 75% approval of the outstanding limited partner interests in each partnership to satisfy the fairness requirements under the NASD Rules. After evaluation of these issues, the Board of Directors directed Baker Donelson to proceed with the preparation of merger materials to file with the SEC. FBR then reported to the Board of Directors on its updated analysis, which presented more recent data and contained certain modifications with respect to its determination of fairness. The Board’s conclusion from this review was that the merger, as proposed, was fair to, and in the best interest of, the limited partners.

On October 9, 2002, Southwest’s Board of Directors held a special meeting to review the terms of the merger, to receive a fairness update, and to approve the merger. Counsel again reviewed the principal terms of the merger with the Board. The Board discussed the parameters of the fairness opinion to be delivered by FBR. The Board also reviewed the registration statement on S-4 to be filed with the SEC and discussed proposed changes to the document. FBR then gave a presentation to the Board on the fairness of the merger, updating the Board on the minor changes to its analysis since the last Board meeting. The Board then unanimously approved the merger, affirmed its earlier conclusion that the merger is fair to, and in the best interest of, the limited partners, and authorized the filing of the registration statement with the SEC.

Benefits of the Merger to the Limited Partners

The following are the principal anticipated benefits of the merger to the limited partners. We cannot assure you, however, that the merger will achieve any of the benefits and objectives described below. You should analyze the anticipated benefits and objectives of the merger in light of all of the terms of the merger as described in this prospectus/proxy statement and the supplement(s) of your partnership(s).

Greater Access to Capital Markets and Increased Growth and Investment Appreciation.     Other than Southwest Partners, L.P., which has a limited ability to raise capital, none of the partnerships can raise additional funds under the terms of their respective partnership agreements. Following the merger, we believe that a larger, combined business will have greater access to public and private capital markets because of its larger and more diverse asset base. This market access will expand our potential investor base and enable us to raise capital on more favorable terms than are now available. Additional capital, in turn, should enable us to take advantage of opportunities with respect to acquisitions, developmental and exploratory drilling, improved recovery and other projects, which will generate future production and revenues.

Increased Liquidity.     The transfer of your limited partner interests is restricted, and there has never been a public market for your limited partner interests. We have applied to list our common stock on Nasdaq (National Market). Therefore, we believe that the participation in the merger will provide you with shares of common stock for which there may be a public market in the near future. We cannot assure you, however, that our listing application for Nasdaq (National Market) will be approved or that an active market for our common stock will, in fact, develop.

Increased Exploratory and Developmental Drilling.     Most of the partnerships cannot directly engage in exploratory or developmental drilling. These partnerships, however, hold interests in a number of properties with what we believe to be relatively low cost and low risk development opportunities. Except for Southwest Partners, L.P., which can develop its own properties, the partnerships must depend on third parties to identify and develop these properties. If a third party is interested in developing a partnership’s property, the partnership must negotiate an arrangement with the third party, usually relinquishing most of that partnership’s ownership interest in the development property in order for the third party to agree to pay for the partnership’s portion of the development costs. We believe that following the merger, we will be able to take advantage of such development opportunities in properties currently owned by the partnerships without relinquishing ownership and thereby possibly realizing a larger return on investment.

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Reduction of Tax Reporting Requirements and Costs.     As a stockholder in Southwest, you will not be required to include information regarding our operations on your personal tax returns as you now do for partnership operations and will no longer receive Schedule K-1. Thus, we believe that the exchange of your limited partner interests for common stock will eliminate some complex partnership tax reporting requirements and certain associated costs. Additionally, many states, including New Mexico, have started to require limited partners to individually file state tax returns if a partnership owns property in that state, and we believe that other states will follow suit with respect to this requirement. The merger will reduce or alleviate individual state filings by limited partners.

Increased Reinvestment of Cash Flow and Growth Potential.     Following the merger, we intend to retain and reinvest the partnerships’ net cash flow in our combined business. We believe that the increase in overall asset size, along with the retention and reinvestment of the cash flow that would otherwise be distributed, will increase our financial strength and flexibility and will facilitate the acquisition and development of oil and gas properties.

Administrative Efficiencies.     We believe that participation in the merger will result in general and administrative efficiencies and cost reductions in the management and operations of the properties and the partnerships. We believe that the merger will result in a significant decrease in the costs associated with managerial, audit, accounting, tax return preparation, engineering, data processing, and record maintenance services, and financial and SEC reporting requirements. For the 12 months ended December 31, 2001 these costs, in the aggregate, were $1,442,000 and for the 6 months ended June 30, 2002, these costs, in the aggregate, were $717,000. Although we will lose the benefit of each partnership’s reimbursement for general and administrative expenses, we will be able to use the additional time of our personnel to achieve our corporate strategic goals for the combined business. You will also no longer have to pay the per well administrative overhead fee to us for those properties owned by the partnerships but operated by Southwest. These fees normally range from $150 to $350 per well. These fees totaled $1.842 million for all of the partnerships for the 12 months ended December 31, 2001 and $931,000 for all of the partnerships for the 6 months ended June 30, 2002.

Maturity of Partnerships’ Properties.     Although each partnership held many long-lived properties at inception, because of the restrictions on property development imposed by the partnership agreements, we anticipated that at some point each partnership would need to be liquidated. We are recommending the merger for each partnership at this time because:

• Maintenance of properties and administrative expenses for each partnership are increasing relative to production. As the properties continue to deplete, maintenance of properties and administrative costs as a percentage of production will continue to increase.

• As each partnership’s properties have matured, the net cash flows from operations for each partnership have generally declined, except in periods of substantially increased commodity pricing. Most of the partnerships cannot develop their non producing properties, if any, and therefore, without continued development, the producing reserves continue to deplete causing cash flow to steadily decline. See Table 5 in Appendix A of this prospectus/proxy statement for each partnership’s historical cash distributions.

Geographic and Operational Efficiencies.     Our primary operations are located in the Permian Basin. The partnerships also hold interests, or produce and market oil and gas drilled from properties, in the Permian Basin. We own interests in many of the same properties as the partnerships and operate many of the properties in which the partnerships own an interest. The merger of the partnerships should create geographic and operational efficiencies for the management of our properties and the properties of the partnerships.

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Disadvantages of the Merger to the Limited Partners

The following are what we believe to be the principal disadvantages of the merger to the limited partners:

Different Investment Objective.     Limited partners of each partnership will own stock in a corporation, which is a different investment objective from an investment in a partnership that is designed to generate recurring cash distributions. It is unlikely that we will make cash contributions to our stockholders in the foreseeable future.

Significant Indebtedness of Southwest.     Limited partners who become Southwest stockholders will be exchanging partnership interest in a partnership that generally cannot incur indebtedness for shares of common stock in Southwest, which has a significant level of indebtedness.

Increased Risks from Operations.     We plan to engage in the acquisition, exploration and development of oil and gas properties that will expose limited partners of each partnership to all of the attendant risks associated with such activities. Each partnership owns producing properties and does not conduct drilling activities. Our activities may, therefore, involve greater risks than the activities of each partnership. Additionally, each partnership’s properties will be part of a larger group of properties, which may have increased liabilities attendant to those partnerships which are currently not borne by another partnership.

Volatility of Market Price of Common Stock.     Limited partnership investments are not currently subject to any market risk or volatility, other than oil and gas price fluctuations. Upon becoming a Southwest stockholder, a limited partner’s investment in Southwest will be subject to the volatility and risk of the market. Market factors that may affect the common stock price may include general market conditions and the broader economy, as well as trading and market support risk.

Potential Taxable Transaction.     The merger may create a taxable event for the limited partners in the event the IRS disagrees with our characterization of the merger as a tax-neutral event.

Reasons for the Structure of the Merger

Issuance of Shares.     The merger has been structured as an exchange of limited partner interests for our common stock. We are issuing shares of our common stock rather than paying cash or a combination of stock/cash because the Indenture governing our Senior Secured Notes due 2004 and covenants in our Senior Credit Agreement effectively prevent us from paying cash in the merger. Also, we plan to use our available cash reserves to develop the partnerships’ properties and to fund acquisition and development strategies.

Critical Mass, Operating and Administrative Efficiencies.    As described in “Advantages of the Merger to the Limited Partners,” we believe that certain operating and administrative efficiencies can be obtained through the merger of the partnerships. It is our opinion that a certain minimum number of properties must be acquired before these efficiencies can become practical for both the combined business and each individual partnership. We have made the approval of the merger by the limited partners in either Southwest Partners, L.P. or Southwest Royalties Inc. Income Fund VI, L.P. a condition to the consummation of the merger. Southwest Partners’ Net Asset Value constitutes 23.56% of all partnerships’ combined Net Asset Value, and Southwest Royalties, Inc. Income Fund VI’s Net Asset Value constitutes 13.87% of all partnerships’ combined Net Asset Value. Both of these partnerships also own many properties of which Southwest operates a large portion. We believe that operating and administrative efficiencies may be obtained so long as one of these two partnerships is included in the merger.

Reasons for the Timing of the Merger

Property Maturity.    As the properties owned by the partnerships mature, cash flow will naturally decrease as a result of declining production and increasing operational expenses (barring product price increases). Most of the partnerships have properties that contain oil and/or gas reserves that are not currently producing. These

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reserves have been identified by standardized engineering and geological studies and testing and are classified as proved developed non-producing (PNP) and proved undeveloped (PUD) reserves. To produce oil and gas from these reserves, workovers and/or drilling must occur. Except for Southwest Partners, L.P., the partnerships are unable to drill or workover these properties because of capital and partnership restrictions. There are, however, various methods available to the partnerships that may allow them to participate in the production of these additional reserves under certain circumstances. See “BACKGROUND AND REASONS FOR THE MERGER—Benefits of the Merger to the Limited Partners—Increased Exploratory and Developmental Drilling” and “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger—Continuation Alternatives” for a description of these circumstances. By way of the merger, these reserves can be exploited to the fullest extent of their ownership as opposed to bartering away ownership for investment or receiving an onerous penalty for inability to participate up front. Successful completion of workovers and/or drilling to produce these reserves would increase production, thereby increasing cash flow and asset value. It is our opinion that many of the properties owned by the partnerships have come to a maturity level that requires additional development to maximize production and minimize expenses per barrel of oil equivalent produced.

Capital Market Access and Acquisition Opportunities.    We believe that prior to April 2002, our substantial debt burden made it difficult to pursue a merger with the partnerships. Now that our debt obligations have been lessened, we believe the merger is more attractive to the limited partners and that a combined entity may have more opportunities to access the capital markets. During the last four years, the oil and gas industry has endured both low and high price extremes. Although it would seem likely that the capital markets or buyers of properties or other means of liquidity for the partnerships would become readily available during periods of price increases, liquidity has, in fact, not been available. Sellers and buyers have not aligned, and the capital markets have not opened for public or private offerings for energy companies. Capital markets are difficult to predict and, at present, we believe that they remain rather inactive for smaller, less well-capitalized companies. We believe, however, that the capital market’s interest in energy investment opportunities will return in the foreseeable future. We believe that the value of our combined assets can be maximized at that time by accessing the capital markets and taking advantage of acquisition opportunities.

Alternatives to the Merger

The alternatives to the merger include liquidating all or some portion of the assets of the partnerships or continuing the operations of the partnerships. For the following reasons, we determined that the proposed merger would provide the limited partners with greater overall benefits than either of these alternatives.

Liquidation Alternatives

The principal benefit of liquidating the partnerships would be the immediate realization of cash, based on a current sale. Limited partners would also avoid the market risks associated with owning our common stock. The prices paid by purchasers of partnership properties in liquidation, however, would likely include a substantial discount for the risks and uncertainties of future cash flows, as well as development risks. Most of the partnerships’ ownership consists of non-operated interests, which are not likely to be valued favorably in the property market, resulting in a highly discounted sales price. Liquidation would also result in a taxable transaction to the limited partners whereas we believe the merger will not. Because we own interests in many of the same properties and also operate many of the properties in which the partnerships own an interest, we believe that we can give more value to the properties through a merger than through a liquidation offering to unaffiliated third parties.

Continuation Alternatives

We considered continuing the partnerships without change. If the partnerships did not merge, the limited partners would avoid the risks associated with the merger and would continue to receive quarterly cash distributions if available. Continuing operations, however, would expose the limited partners to an inevitable decline in operating results and distributions of cash. Most of the partnerships’ producing properties are mature and their production will continue to decrease based on the natural decline of the reserves. Lifting costs do not normally decline in relation to production and, therefore, would continue to increase as a percentage of production. Because the partnerships are

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normally allowed to receive the non-consent party’s portion of the revenues, if any, from production until it has received 300% of their investment. Once this penalty amount is received, the non-consent party begins receiving its portion of revenues. Under certain conditions, the partnership may have the option to “farm out” acreage to a third party. This procedure may be available when the interest owner cannot participate in the costs of the development work. The third party investor often receives a large portion of the partnership ownership percentage in compensation for his risk and investment. We believe that the resulting production, if any, which might be received by the partnership under these two arrangements, is not enough to materially offset the rate of production decline.

Fairness of the Merger

General

We have spent significant time and resources evaluating the fairness of the proposed merger, including hiring an investment bank to render an opinion regarding the fairness of the merger to the limited partners and to Southwest, as the managing general partner of each partnership. In order to evaluate the fairness of the merger, we have reviewed current industry conditions, the reserves of the partnerships and of Southwest, the nature of those reserves, the development prospects for those reserves and the likelihood of other potential third party transactions, including sales of properties to unaffiliated third parties. Further, we evaluated the stated desire of many limited partners, as well as our own stockholders, for some market liquidity which would necessitate a registration and a listing of our securities. We also evaluated the costs of all of these possible actions relative to the anticipated benefits to be received by the limited partners.

We believe that all possible combinations of the merger of the 21 partnerships is fair and beneficial to the limited partners, so long as we receive the adoption and approval of the merger by the limited partners in either Southwest Partners, L.P. or Southwest Royalties, Inc. Income Fund VI, L.P. Our belief is based on the reasons described below.

The Merger Value attributable to each partnership is based upon a fair methodology. We have considered various methods of valuation and believe that our method (see “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED”) is fair to all the partnerships and limited partners as a result of many factors, including:

• The use of a standardized price in the calculation of Net Asset Value. All computations of the discounted net proved value of reserves for Southwest and each of the partnerships’ properties use the same standardized product price adjusted only for individual characteristics of each property, such as

gravity adjustments, sour or sweet oil (sulfur and other impurity contents), and other such individual characteristics of the property. The use of a standardized pricing method removes ambiguity and subjectivity from the calculation. We believe that the standardized method used to calculate each participating partnership’s net assets, as well as the net assets of Southwest, is a more fair method than other alternative methods that we researched. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED—Other Methods of Determining Merger Value.”

• The allocation of shares of common stock is based on a standardized method of calculating and allocating value for all the partnerships and Southwest. The method of calculating the Net Asset Value is standardized for all entities and, therefore, the percentage of ownership in the combined business is allocated based on a standardized calculation of value under the same and constant terms and factors.

• The use of industry standard engineering to calculate the fair value of the remaining cash flow from the reserves of each partnership and Southwest. The calculation of the Net Asset Value of each partnership and Southwest uses a standard method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

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Valuation, however, is not an exact science. Other formulas or approaches to the valuation process, which might also be considered fair, could yield materially different results. See “RISK FACTORS.”

The Merger Value is greater than values derived from other methods of determining value, such as net book value, going concern value, liquidation value and final presentment value for each of the partnerships, except that the stated net book value of Southwest Royalties, Inc. Income Fund V, L.P. is higher than the Merger Value. The Merger Value also is greater than any value calculated using any right of presentment formula currently available under the partnership agreements of the partnerships. The right of presentment, however, is not available to the limited partners of Southwest Partners, L.P. under the terms of its partnership agreement. We are not aware of any bid process on the limited partner interests in the last five years. Other than repurchase offers made by us for limited partner interests, we are not aware of any other offers to purchase, merge, consolidate, or combine any of the partnerships or a material portion of their assets being made over the last five years. For the foregoing reasons, we believe that the Merger Value and the allocation of our common stock is fair to the limited partners. Our reasons for this belief are more fully detailed and discussed in “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger,” “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED—Other Methods of Determining Merger Value” and in the tables presented under “Supplemental Information” in the prospectus supplements for each of the partnerships in which you own an interest.

We are requiring that holders of 75% of the outstanding limited partner interests in each partnership approve the merger before that partnership is able to participate in the merger. This requirement satisfies NASD Rules and further demonstrates the fairness of the merger. We will also receive an opinion from FBR that the merger is fair to the limited partners of each partnership, from a financial point of view. See “Fairness Opinion.”

General Partner Recommendation to the Limited Partners

On October 9, 2002, our Board of Directors, acting in its capacity for Southwest as the general partner of each of the partnerships, unanimously approved the merger and determined that the merger of each of the partnerships, under the terms described, is fair to, and in the best interest of, the limited partners of each of the partnerships. The Board of Directors, therefore, recommends the merger to you and that you, as a limited partner, vote for the merger of each partnership in which you own a limited partnership interest.

In making this recommendation, our Board of Directors considered a number of factors, including those discussed in “BACKGROUND AND REASONS FOR THE MERGER” and “RISK FACTORS”. The Board of Directors also considered the benefits and costs of other transactions, as well as the likelihood of completing such transactions. All factors were considered equally. We did not consider it practical to, and did not attempt to, quantify or assign relative weight to each of the factors considered in reaching our decision. Our recommendation is based on the total information presented. In making such recommendation, we are subject to a conflict of interest since we are the general partner of all of the partnerships, an interest holder of limited partner interests in certain of the partnerships and the issuer of the common stock to be received by limited partners in the merger.

On the basis of the entire terms, provisions, and conditions of the merger, including the consideration that limited partners will receive, the principal objectives and benefits of the merger, our anticipated business activities, the potential results of future operations and the costs of the merger, we believe that the merger is advisable and in the best interests of the limited partners. Consequently, Southwest, as the general partner of the partnerships, recommends that you vote in favor of the merger.

Although our Board of Directors has attempted to fulfill its fiduciary duties to you, our Board of Directors had conflicting interests in evaluating the merger because we also have fiduciary duties to our stockholders.

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Furthermore, our Chairman, President and Chief Executive Officer, H.H. Wommack, III, is a general partner of nine of the partnerships and is a significant stockholder of Southwest; provided, however, that Mr. Wommack will transfer his general partner interest to Southwest for no consideration prior to the consummation of the merger.

Fairness Opinion

We have engaged FBR, an independent financial advisory firm, to conduct an independent review and deliver a written opinion in connection with the merger of each partnership. FBR analyzed the Merger Value for each partnership and the allocation of the shares of common stock and special stock of Southwest, which are derived from the Merger Value of each partnership, and opined on the fairness of the merger from a financial point of view to Southwest, as the managing general partner, and to the limited partners of each partnership. The full text of FBR’s fairness opinion is attached as Appendix E to this prospectus/proxy statement and is incorporated into this prospectus/proxy statement by reference. Limited partners of each partnership are urged to read the opinion in its entirety. This summary of FBR’s fairness opinion is qualified in its entirety by reference to the full text of the opinion. FBR has advised Southwest that arriving at a fairness opinion is a complex analytical process not necessarily susceptible to partial analysis or amenable to summary description. For a description of all the material assumptions and qualifications to the fairness opinion, see “—Qualifications to Fairness Opinion” and “—Assumptions” below.

Except for assumptions described below in “—Assumptions,” which Southwest advised FBR would be reasonable and appropriate in its view, neither Southwest nor any of the 21 partnerships imposed any conditions or limitations on the scope of the investigation by FBR or the methods and procedures to be followed by FBR in rendering the fairness opinion. In addition, Southwest has agreed to indemnify FBR against certain liabilities arising out of FBR’s engagement to prepare and deliver its opinion.

Experience of FBR

Founded in 1989, FBR is a NYSE listed, international investment banking firm with offices across the United States and Europe. FBR has provided research, institutional sales and trading, investment banking, asset management and private client financial services to clients located throughout the United States and Europe. FBR’s investment banking activities include merger and acquisition advisory and fairness opinion services, initial public offerings, secondary and follow-on public offerings, private placements, venture capital and industry and company research and analysis. FBR focuses its investment banking practice on six industry sectors: Financial Services, Real Estate, Technology, Energy, Diversified Industries and Healthcare. FBR was selected because of its experience in the valuation of businesses and their securities, including the valuation oil and gas assets, in connection with mergers, acquisitions, reorganizations and other transactional purposes.

Qualifications to Fairness Opinion

In the fairness opinion, FBR specifically states that it was not requested to, and did not:

• make any recommendations to Southwest, any partnership or the limited partners of any partnership with respect to whether to approve or reject the merger of any partnership;

• determine or negotiate the amount or form of the Merger Value for any partnership to be paid for the partnership’s interests in the merger of the partnership;

• offer the assets of any partnership for sale to any third party.

FBR further states that it did not express any opinion as to:

• the financial impact on Southwest or any partnership that does not participate in the proposed merger transaction;

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• the tax consequences of the merger of any partnership on Southwest, any partnership or the limited partners of any of the partnerships;

• the impact upon the value of partnerships’ reserves if the oil and gas assets were operated under operating agreements with terms different from the agreements presently in place;

• the impact upon the value of the partnerships if they were administered in accordance with partnership agreements having terms different from those agreements presently governing the partnerships;

• the value of the partnerships or the partnerships’ assets if they were managed and/or operated by a party other than Southwest;

• whether or not alternative methods of determining the Merger Value for each partnership were plausible and whether or not such alternative methods would have also provided fair results or results substantially similar to the methodology used;

• alternatives to the merger of each partnership, including the offering of such assets for sale to third party buyers;

• the value of the shares of Southwest common stock or the market performance of Southwest common stock if it were to ever become publicly registered and listed for trading on an organized exchange;

• the financial condition of Southwest or any of the partnerships, including solvency and liquidity matters; or

• any other terms of the merger of any partnership.

Summary of Information Considered and Investigation Undertaken

FBR’s analysis of the merger of each partnership involved a review of the following information:

• a draft of the preliminary S-4, of which this prospectus/proxy statement is a part;

• a draft of the merger agreement which Southwest has indicated is substantially the form which will be executed in connection with the merger of each partnership;

• financial statements of each partnership for the three and six months ended March 31, 2002 and June 30, 2002 and for the years ended December 31, 2001 and 2000. Where applicable, the partnership’s Forms 10-Q and Forms 10-K were reviewed for the same time periods.

• the reserve reports prepared by Southwest as of July 1, 2002, relating to the reserves of each partnership and Southwest;

• the reserve reports audited by Ryder Scott Company, L.P., as of December 31, 2001, relating to the reserves of each partnership and Southwest;

• calculations prepared by Southwest of the Merger Value per $500 of limited partner investment in each partnership;

• information regarding other alternatives to the merger of each partnership;

• information provided by Southwest which was ultimately used in the development of the Going Concern Value, Liquidation Value and Right of Presentment Value per $500 of limited partner investment in each partnership;

• the financial statements of Southwest for the 3 months ended March 31, 2002, the 5 months ended May 31, 2002, the 6 months ended June 30, 2002, the 12 months ended December 31, 2001 and its Form 10-K for the years ended December 31, 2000 and 1999;

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• the terms and conditions of the recapitalization of Southwest in the form of a debt for equity exchange where approximately $115.0 million of 10½% Senior Notes due 2004 were exchanged for $60.0 million of New Senior Secured Notes due 2004 and 90% of the outstanding voting capital stock of Southwest; and

• pro forma financial data for Southwest assuming the completion of the merger.

In the course of its analysis, FBR interviewed senior management personnel of Southwest. During such interviews, FBR and the senior management personnel reviewed the financial statements of each partnership, the reserve value estimates for each partnership, the assumptions used to construct the reserve value estimate for each partnership, the governing partnership documents, the rationale for merging the subject partnerships into Southwest, the benefits to the respective stockholders of Southwest and the partnerships with respect to the proposed merger, the estimated timing of the merger of each partnership and other relevant matters.

FBR reviewed information submitted by Southwest regarding the Merger Value, Going Concern Value, Liquidation Value and Right of Presentment Value. FBR investigated whether or not there had been any secondary market trading of any of the partnerships, and if so, what prices were observed in those transactions. FBR also investigated whether or not management personnel of Southwest were aware of any solicited or unsolicited tender offers received by either the general or limited partners of each partnership. FBR’s analysis is summarized below.

Review of Merger Value for each Partnership

FBR reviewed the calculation of the Merger Value for each partnership prepared by Southwest. FBR observed that such calculation was based on a Net Asset Value approach. The first step in determining the Merger Value for each partnership was the calculation of the Total Reserve Value, as described below, for each partnership’s oil and gas assets. The Total Reserve Value was then adjusted to account for the Working Capital in each partnership, determined from the June 30, 2002 balance sheet for each partnership. Working Capital was calculated by reducing the current assets as of June 30, 2002, by the current liabilities as of the same balance sheet date. The Total Reserve Value was next adjusted by adding the net book value of any other non-oil and gas assets as of June 30, 2002 and then subtracting any debt owed by the partnership as of the same balance sheet date. FBR observed that none of the estimated expenses and fees associated with the merger of the partnerships was allocated to the partnerships. FBR also observed that Southwest intended to suspend any cash distributions from the partnerships after its Registration Statement on Form S-4 has been declared effective by the SEC.

FBR analyzed the summary reserve report for each partnership prepared by Southwest as of July 1, 2002. FBR noted that each summary reserve report was prepared based upon the following pricing case: (1) a five-year NYMEX futures price for oil and gas as of July 1, 2002, with prices held constant after year five at the year five price and (2) historical operating costs adjusted only for those items affected by commodity prices, such as production taxes and ad valorem taxes. For 2002, the oil and gas prices were based on the average NYMEX futures price for the six-month period beginning on July 1, 2002 and ending December 31, 2002. The five-year NYMEX prices used for 2002, 2003, 2004, 2005, 2006 and thereafter were $26.46, $24.74, $23.30, $22.44 and $21.84 per barrel of oil and $3.42, $3.86, $3.96, $3.99 and $4.02 per thousand cubic feet of gas. FBR further noted that NYMEX prices upon which each reserve report was based were subject to the standard industry adjustments peculiar to each partnership’s particular oil and gas assets. The standard industry adjustments reflect oil quality, BTU content, oil and gas gathering and transportation costs, gas processing costs and regional commodity price differences.

FBR observed that the Total Reserve Value was calculated by summing the present values of the three classes of proved reserves. The present values were determined using a discount rate of 10.0% for proved developed producing reserves (“PDP”), a discount rate of 15.0% for proved non-producing reserves (“PNP”) and a discount rate of 20.0% for proved undeveloped reserves (“PUD”). Probable or possible reserves were not considered by the summary reserve reports for any of the partnerships. FBR further observed that the sum of the discounted cash flow values for the PDP, PNP and PUD reserve classes for each partnership resulted in a per barrel of oil equivalent, or Boe, value of the total proved reserves that ranged from $3.04 to $8.28 and averaged

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$5.62. Additionally, FBR observed other non-quantitative characteristics of the partnership’s reserves that would impact the value of such assets in the marketplace. Specifically, FBR confirmed that the partnership’s oil and gas properties were 1) non-operated, 2) subject to COPAS overhead charges by Southwest, 3) generally low-volume, 4) generally longer-lived and 5) predominately were in the form of crude oil in terms of hydrocarbon mix. Also, FBR concluded that the respective discount rates PDP, PNP and PUD reserves were appropriate for measuring the risk between the different classes of proved reserves. FBR further concluded that the discount rates employed were in a range that was consistent with oil and gas industry standards.

In the course of its engagement and as an ongoing part of its financial advisory practice, FBR reviewed selected comparable transactions in terms of the range of value paid per Boe, reserve life and percentage of reserves in the form of natural gas for oil and gas assets in the Permian Basin. Specifically, FBR reviewed a total of 37 transactions dating back to 1997 involving assets predominately located in the Permian Basin. These 37 transactions totaled approximately $11.0 billion and averaged $297.0 million. The largest such transaction was $3.6 billion and the smallest was $27.8 million. Such transactions, including one involving Southwest, provided a range of value per Boe of $2.52 to $9.13, an average of $5.03 and a median value of $4.89. The average and median values observed for reserve life were 14.9 and 13.3 years, respectively. The average transaction was 59% crude oil in terms of the hydrocarbon composition of the reserves.

During its evaluation, FBR observed a substantial difference in the average and range of value paid per Boe. Specifically, FBR examined 16 transactions dating back to 1992 involving assets predominately located in the Permian Basin where the individual transaction value was less than $25.0 million. These transactions totaled $205.5 million and averaged $12.8 million. The largest such transaction was $23.0 million and the smallest was $0.3 million. Such transactions, including two involving Southwest, provided a range of value per Boe of $1.86 to $6.22, an average of $3.81 and a median value of $3.54. The average and median values observed for reserve life were 12.6 and 13.5 years, respectively. The average transaction was 69% crude oil in terms of the hydrocarbon composition of the reserves. While there is limited public information available for smaller, private transactions, the data reviewed by FBR was effective in corroborating the widely held oil and gas industry belief that smaller property transactions in the private market attract lower valuations.

FBR observed that, individually, collectively and in any combination, the Total Reserve Value determined for the partnerships was in the range of values paid per Boe for the selected comparable transactions for both those sets of transactions above and below $25.0 million. FBR further observed that the perfunctory adjustments made to the Total Reserve Value for each partnership for the purpose of determining Merger Value, were consistent with the prescribed methodology for determining Merger Value and the financial statements of each partnership dated June 30, 2002.

FBR further observed that, for the purpose of allocating ownership of the common stock and special stock subsequent to the merger of the partnerships, Southwest was valued in accordance with the methodology used for determining the Merger Value of each partnership. See the supplemental information of the supplement for each partnership for its Merger Value.

Going Concern Value

The Going Concern Value calculation is based upon:

The sum of (1) the estimated net cash flow from the sale of reserves during a 12-year operating period and (2) the estimated residual value from the sale of the remaining reserves at the end of that 12-year operating period. With respect to the estimated net cash flow during the 12-year operating period, the same commodity price and discount rate assumptions were used as in the Merger Value calculation. For the reserves remaining at the end of the 12-year period, a value per Boe of $3.85 was used to determine the nominal value of these reserves, then this value was discounted back to the present using a 10.0% rate. The sum of the estimated net cash flow from sale of the reserves during a 12-year operating period and the estimated residual value of the reserves after year 12 were then adjusted

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to account for the maximum annual allowable total of partnership general and administrative expenses. Without exception, for each of the subject partnerships, the maximum annual allowable total of partnership general and administrative expenses was equal to no more than 2% of total original capital contributions to each partnership. FBR noted that with respect to certain partnerships, the maximum annual allowable total of partnership general and administrative expenses was equal to no more than 3% of total original capital contributions to such partnerships during the first 12 months of the life of such partnerships; however, due to the age of the subject partnerships, that provision was no longer relevant. For each partnership, the nominal total of the general and administrative expenses over the economic life of each partnership was discounted back to the present using a 7% discount rate. The discounted present value of the general and administrative expenses was then subtracted from the sum of the discounted present values of the estimated net cash flow from the sale of reserves during a 12-year operating period and the estimated residual value of the reserves after year 12.

The economic life for each partnership in the Going Concern Value analysis was determined by comparing the discounted present value of the general and administrative expenses, calculated as described above, to the discounted present value of the net cash flow from the sale of reserves, calculated using the same discount rate and commodity price assumptions as in the Merger Value calculation. If at any time prior to year 12 the discounted present value of the general and administrative expenses exceeded the discounted present value of the net cash flow from the sale of reserves for a partnership, the partnership was deemed uneconomic. In cases where a partnership was determined not to be economic for the entire 12-year observation period, the partnership was assumed to be operated up to the point in time where it became uneconomic and the residual reserves were assumed sold at that point. FBR observed that the following six partnerships were not economic for the 12-year observation period and were, therefore, subject to the modified analysis described above:

Southwest Royalties, Inc. Income Fund V, L.P.

Southwest Oil & Gas Income Fund X-A, L.P.

Southwest Oil & Gas Income Fund X-B, L.P.

Southwest Oil & Gas Income Fund X-C, L.P.

Southwest Royalties Institutional Income Fund X-C, L.P.

Southwest Combination Income/Drilling Program 1988, L.P.

FBR observed that the Going Concern Value of each partnership ranged from 0.51% to 94.52% less than the Merger Value for each partnership. See the supplemental information table of the supplement for each partnership for its Merger Value and its Going Concern Value, in each case per $500 limited partner investment.

Liquidation Value

The Liquidation Value calculation is based upon the sale of the oil and gas reserves at the liquidation value price of $3.85 per Boe of reserves, plus any net working capital attributable to each partnership on the day of liquidation, less liquidation expenses which are estimated to be the sum of (A) 3% of the partnership’s reserve value, (B) $20,000 of wind up costs per partnership, and (C) any debt attributable to the partnerships. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of each partnership and the legal, accounting and tax advisory costs associated with terminating the legal existence of each partnership. FBR observed that such merger expenses are intended to reflect Southwest’s estimate of the cost associated with brokers’ commissions on asset sales and the additional termination costs of the partnership.

FBR further observed that the Liquidation Value of each partnership’s reserves at a liquidation price of $3.85 per Boe ranged from $78,065 to $3,846,457. The average Liquidation Value for each partnership’s reserves was $1,355,452. These values were all well below the $25.0 million threshold where historical comparable transaction data demonstrated that reserves were sold at an average price of $3.81 per Boe. Due to the size of the theoretical liquidation transaction for each partnership’s reserves and the fact that all such reserves

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were non-operated, it is reasonable to conclude that the reserves would sell for less than $3.85 per Boe in an open market transaction.

FBR observed that the Liquidation Value for each partnership ranged from 7.58% to 52.99% less than the Merger Value for each partnership. See the supplemental information table of the supplement for each partnership for its Merger Value and its Liquidation Value, in each case per $500 limited partner investment.

Secondary Market Prices

FBR observed that none of the 21 subject partnerships was ever listed for trading on an organized securities exchange. Southwest was unaware of any secondary market transactions involving any of the subject 21 partnerships.

Tender Offers

FBR observed that Southwest reported receiving no solicited or unsolicited tender offers from unaffiliated third parties for interests in any of the 21 partnerships during the period January 1998 through July 2002.

Right of Presentment

FBR evaluated Right of Presentment prices for those partnerships where the agreement of limited partnership contemplated some form of Right of Presentment. Specifically, FBR noted that 20 of the 21 partnerships subject to the merger had some form of presentment right in the agreement of limited partnership. FBR observed that with respect to certain partnerships, Southwest, as the managing general partner, was obligated subject to certain limitations, to repurchase limited partner interests upon demand of a limited partner. Southwest’s repurchase obligation with respect to these partnerships was limited to 10% of the initial partnership capital. FBR specifically observed that this was the case for each of the six partnerships listed below, which FBR calls the “Mandatory Repurchase Partnerships”:

Southwest Royalties, Inc. Income Fund V, L.P.

Southwest Royalties, Inc. Income Fund VI, L.P.

Southwest Oil & Gas Income Fund VII-A, L.P.

Southwest Royalties Institutional Income Fund VII-B, L.P.

Southwest Oil & Gas Income Fund VIII-A, L.P.

Southwest Royalties Institutional Income Fund VIII-B, L.P.

FBR further observed that for 14 of the partnerships, Southwest, as the managing general partner, could be petitioned by a limited partner under certain circumstances to repurchase limited partner interests. Under the terms of the agreement of limited partnership, the circumstances under which a limited partner could petition Southwest, as the managing general partner, to repurchase limited partner interests generally involved circumstances where any representation, warranty or covenant made by the limited partner in the subscription agreement became untrue or if the limited partner somehow became unqualified to hold interests in oil and gas leases. Under the terms of the agreement of limited partnership for these 14 partnerships, Southwest had the right, but was not obligated, to purchase or cause to be purchased any or all of the affected limited partner interests. FBR specifically observed that this was the case for each of the 14 partnerships listed below, which FBR calls the “Optional Repurchase Partnerships”:

Southwest Oil & Gas Income Fund IX-A, L.P.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Southwest Oil & Gas Income Fund X-A, L.P.

Southwest Royalties Institutional Income Fund X-A, L.P.

Southwest Oil & Gas Income Fund X-B, L.P.

Southwest Royalties Institutional Income Fund X-B, L.P.

Southwest Oil & Gas Income Fund X-C, L.P.

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Southwest Royalties Institutional Income Fund X-C, L.P.

Southwest Developmental Drilling Fund 1990, L.P.

Southwest Developmental Drilling Fund 91-A, L.P.

Southwest Developmental Drilling Fund 92-A, L.P.

Southwest Developmental Drilling Fund 1993, L.P.

Southwest Developmental Drilling Fund 1994, L.P.

Southwest Combination Income/Drilling Program 1988, L.P.

Although Southwest was never required to consummate a repurchase of any of the interests of these Optional Repurchase Partnerships, the fact that the partnership agreements prescribed a methodology for determining a conditional repurchase price creates a fair value expectation on behalf of the limited partner for their limited partner interests.

FBR observed that there was no presentment right of any kind in the agreement of limited partnership for Southwest Partners, L.P. Therefore, no Right of Presentment purchase price was evaluated for this partnership.

The process by which the purchase price is determined for Right of Presentment repurchases is substantially similar between the Mandatory Repurchase Partnerships and the Optional Repurchase Partnerships. Southwest, as the managing general partner, is required under the partnership agreement for each partnership to offer to repurchase units of limited partner interest in the partnership once a year at a price based upon a formula using an annual reserve report and a balance sheet. FBR noted that the date of the reserve report and balance sheet is unspecified in the agreements of limited partnership and that there is no time deadline for Southwest to present a repurchase offer. FBR also noted that, for the purpose of making a meaningful comparison, the same commodity price and discount rate assumptions were used as in the Merger Value calculation. The Right of Presentment repurchase offer was assumed made as of July 1, 2002.

A Right of Presentment repurchase price is calculated by taking the sum of (1) the present value of the estimated future net revenues, calculated using a discount rate equal to the prime rate plus 1%, from a partnership’s estimated reserves as determined by independent petroleum consultants, reduced by a factor of 33.33%, (2) the net working capital of the partnership, and (3) the book value of any non-oil and gas partnership assets, and then subtracting (1) any partnership debt, and (2) any cash distributions made subsequent to the balance sheet date.

FBR observed that in the case of the Mandatory Repurchase Partnerships, Southwest was required to make a repurchase offer only once a year. Although there was some variety between the various partnership agreements for the Mandatory Repurchase Partnerships, FBR observed that each limited partner who intends to exercise its presentment right generally has 15 days to accept Southwest’s repurchase offer and that Southwest generally must consummate the repurchase with each limited partner who accepts the repurchase offer within 60 days of acceptance. In the case of the Optional Repurchase Partnerships, Southwest was only required to make a non-binding repurchase offer upon the request of a qualifying limited partner.

FBR observed that the repurchase prices calculated for the Mandatory Repurchase Partnerships and the Optional Repurchase Partnerships as of July 1, 2002 ranged from 7.59% to 20.56% less than the Merger Value of each partnership. See the supplemental information table of the supplement for each partnership for its Merger Value and its Right of Presentment Value, in each case per $500 limited partner investment.

Assumptions

Southwest advised FBR that the oil and gas properties owned by each partnership are subject to operating agreements with Southwest and other third party operators and that:

• such operating agreements provide for the payment of overhead charges and that such charges are reasonable and consistent when compared with amounts charged for similar services by other oil and gas operators in the general operating region where the partnership assets are located;

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• except for cause, such operating agreements do not provide for the termination of Southwest or another third party as operator;

• such operating agreements do not provide for the revision of the overhead charges, except as escalated under the terms of such operating agreements.

Furthermore, Southwest advised FBR that if each partnership’s oil and gas assets were offered for sale to a third party, after a sale, those assets would still continue to be subject to the operating agreements with Southwest or another operator which require the payment of overhead charges. Therefore, it would be appropriate to assume, when estimating the value of such oil and gas assets, that such overhead charges would continue to burden the economic value of the partnership’s oil and gas assets.

In addition, Southwest advised FBR that the reserve value and working capital balance of each partnership had been properly allocated between the general partners and the limited partners of each partnership in accordance with the partnership agreement.

FBR did not conduct any engineering studies and has relied on estimates provided by Southwest with respect to oil and gas reserve volumes, prices, operating costs and overhead charges with respect to the reserve value estimates. Furthermore, FBR has relied upon the summary reserve reports prepared by Southwest as of July 1, 2002.

FBR also relied on the assurance of Southwest and each partnership that:

• the summary reserve reports audited by Ryder Scott Company, L.P. dated December 31, 2001 and prepared by Southwest as of July 1, 2002, and provided to FBR was in the judgment of Southwest and each partnership reasonably prepared on bases consistent with actual historical experience and reflect their best currently available estimates and good faith judgments;

• there are no estimates of costs included in the reserve analysis to remedy environmental conditions;

• any historical financial data, balance sheet data, Merger Value analyses, are accurate and complete in all material respects;

• all allocations included in the calculations of Merger Values, have been made in accordance with the partnership agreement of each partnership;

• no material changes have occurred in the information reviewed or in the value of the oil and gas reserves as of July 1, 2002 or balance sheets as of June 30, 2002, of each partnership between the date the information was provided to FBR and the date of FBR’s opinion;

• the relative ownership interests of (1) the limited partners of each partnership, (2) the general partner of each partnership and (3) Southwest, as the managing or sole general partner of each partnership, is accurately reflected in all analyses in accordance with the partnership agreement for each partnership provided to FBR by Southwest and each partnership and that H.H. Wommack, III will transfer his general partner interest to Southwest for no consideration prior to the consummation of the merger; and

• there is no information regarding Southwest or any of the partnerships that would materially impact the oil and gas properties, the reserve analysis or the balance sheets of Southwest or the partnerships or that would cause the information supplied to FBR to be incomplete or misleading in any material respect.

FBR’s opinion is based upon business, economic, oil and gas market and other conditions as of the date of its analysis and addresses the Merger Value for each partnership in the context of information available as of the date of FBR’s analysis. Events occurring after the date of FBR’s analysis could affect the value of the assets of each partnership or the assumptions used in the preparation of FBR’s fairness opinion.

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Conclusion

FBR concluded that, based upon and subject to its analysis, assumptions, limitations and qualifications cited in its opinion, and as of the date of the fairness opinion, the Merger Value for each partnership and the allocation of the shares of common stock and special stock, which are derived from the Merger Value of Southwest and each partnership, is fair from a financial point of view (1) to the limited partners of each partnership, including all possible combinations of the partnerships, and (2) to Southwest as the managing general partner of each partnership. FBR’s fairness opinion is dated             , 2002.

Compensation and Material Relationships

FBR was paid a $25,000 retainer to render a fairness opinion, which retainer will be used as a deposit against FBR’s expenses. Any amount in excess of FBR’s expenses will be credited to the $100,000 portion of the fee for the fairness opinion described below. FBR will be paid $150,000 upon the filing of the draft fairness opinion as an exhibit to Southwest’s registration statement and $100,000 upon delivery of the fairness opinion. In the event the merger is not consummated, Southwest is not required to make the final $100,000 payment. By the terms of FBR’s engagement agreement with Southwest, Southwest is required to reimburse FBR for all reasonable out-of-pocket expenses, including legal fees, and to indemnify FBR against some liabilities, including some liabilities under securities laws.

During the past two years, Southwest has engaged FBR to render financial advisory services in connection with various proposed transactions other than the merger, some of which closed and some of which were never consummated. By means of an engagement letter dated October 31, 2001, as amended December 31, 2001 and as further amended April 4, 2002 (the “Prior Engagement Letter”), Southwest engaged FBR to provide financial advisory services in connection with the Exchange Transaction. Pursuant to the terms of the Prior Engagement Letter, FBR was specifically not retained to provide financial advisory services for or provide any analysis or opinion concerning the merger. FBR was paid a total of $1,750,000 in connection with services provided pursuant to the Prior Engagement Letter and other services, all of which were provided prior to FBR’s engagement to provide a fairness opinion for the merger. The term of the Prior Engagement Letter is scheduled to expire on October 19, 2002; however, FBR may in the future seek to earn additional fees from Southwest by providing investment banking services.

Conflicts of Interest

A general partner is deemed to be a fiduciary of a partnership and must handle partnership affairs with trust, confidence and good faith. Because our directors and officers have fiduciary duties to manage Southwest in a manner beneficial to our stockholders, and we, as general partner of each of the partnerships, have a fiduciary duty to conduct the affairs of each partnership we manage in a manner beneficial to the limited partners, we and our Board face potential conflicts of interest. Delaware courts, however, in cases involving limited partnerships, have held that fully informed limited partner approval of a transaction may, in certain circumstances, eliminate certain related fiduciary claims against the general partner of the partnerships and the general partner’s Board of Directors.

We have conflicts of interest with the limited partners with respect to the merger arising from, among other things:

• We determined the structure of the proposed merger and the Merger Values without any independent third party representing the limited partners of any partnership. As a result, the determination of the Merger Values and the relative ownership of Southwest by limited partners may not reflect the allocation of relative value that would result if the merger were negotiated with an unaffiliated third party in an arms length transaction.

• H.H. Wommack, III is a 1% additional general partner in Oil & Gas Income Fund IX-A, Institutional Income Fund IX-B, Oil & Gas Income Fund X-A, Institutional Income Fund X-A, Oil & Gas Income

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Fund X-B, Institutional Income Fund X-B, Oil & Gas Income Fund X-C, Institutional Income Fund X-C and Combination Income/Drilling Program 1988. Mr. Wommack, however, will transfer his general partner interests to Southwest for no consideration prior to the consummation of the merger. He is also our Chairman, President and Chief Executive Officer and a significant stockholder.

• Legal counsel engaged by Southwest to assist with the preparation of the documentation for the merger, including this prospectus/proxy statement did not serve, or purport to serve, as legal counsel for the limited partners.

No Independent Representative

No independent representative of the limited partners was engaged for purposes of negotiating the terms of the merger. The absence of these protections was considered, but was not judged to be significant by us, in determining the fairness of the proposed merger to the limited partners. Because the Merger Value used in determining the shares of our common stock to be allocated to the limited partners in a partnership in exchange for their interests were primarily based on the reserve values determined by Ryder Scott Company, L.P. and updated by our engineers, with immaterial adjustment based on such variables as cash, short term investments, liabilities and cash flow, we determined that the likelihood that such an unaffiliated representative of the limited partners would add value to the process of structuring the merger was minimal and outweighed the costs of retaining such a representative. As a result, the Merger Value and other terms of the merger may not be as favorable as the terms that might have been obtained had an independent representative been retained.

FORWARD-LOOKING STATEMENTS

This document includes “forward-looking statements” as defined by the Securities and Exchange Commission. These statements concern Southwest’s, Southwest Managed Assets’ and each partnership’s plans, expectations and objectives for future operations. Other than statements of historical facts, all statements, included in this document that address activities, events or developments that Southwest, Southwest Managed Assets and each partnership expect, believe or anticipate will or may occur in the future are forward-looking statements and include the following:

• completion of the proposed merger of each partnership;

• reserve estimates;

• future production of oil and gas; and

• future financial performance.

These forward-looking statements are based on assumptions, which we believe are reasonable, but which are open to a wide range of uncertainties and business risks. Factors that could cause actual results to differ materially from those anticipated are discussed in (1) “RISK FACTORS”, (2) the financial statements for Southwest and each partnership included elsewhere in this prospectus/proxy statement, and (3) Management’s Discussion and Analysis of Financial Condition and Results of Operations for each of the partnerships included in the supplements and for Southwest included elsewhere in this prospectus/proxy statement.

“Safe Harbor” Statement under the Private Securities Litigation Reform Act of 1995: Statements in this document regarding each company’s business which are not historical facts are “forward-looking statements” that involve risks and uncertainties. For a discussion of these risks and uncertainties, which could cause actual results to differ from those contained in the forward looking statements, see “RISK FACTORS”.

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METHOD OF DETERMINING MERGER VALUE

FOR EACH PARTNERSHIP AND AMOUNT

OF SOUTHWEST COMMON STOCK TO BE ISSUED

Summary Reserve Report and Qualifications and Method of Selection

The Merger Value for each of the partnerships was determined primarily based on the proved oil and gas reserve values estimated by Ryder Scott Company, L.P. as set forth in its reports, dated December 31, 2001, for Southwest and each of the partnerships. Our internal engineering staff has updated these estimates to July 1, 2002.

Ryder Scott Company, L.P. is one of the largest, oldest, and most respected reservoir-evaluation consulting firms in the petroleum industry. Ryder Scott Company, L.P. performs more than 1,000 consulting studies a year for oil and gas producers, both major and independent, investors, banks, governmental agencies and accounting and law firms. Ryder Scott has issued reports on more than 200,000 wells or producing entities in North America. The firm has also evaluated hundreds of international oil and gas properties involving thousands of wells. Ryder Scott Company, L.P. evaluates projects in various stages of exploration, development and production. The firm’s studies range from basin evaluations of frontier plays to designing redevelopment programs for mature fields. Additionally, Ryder Scott Company, L.P. is the most widely used consulting firm for preparing year-end reserve estimates in accordance with SEC guidelines.

We selected Ryder Scott Company, L.P. to perform the reserve studies being used for purposes of the merger based on its reputation in the industry. Ryder Scott Company, L.P. has been retained by us to review the estimates of the remaining proved reserves for certain properties since 1997. For each calendar year-end, including certain interim periods, Ryder Scott has prepared the property review for the majority of Southwest’s properties for financial reporting and lender compliance. From 1997 through August 31, 2002, Southwest has paid Ryder Scott Company, L.P. $183,000 for its services. There are no other relationships between us and Ryder Scott in connection with the performance of its reserve analysis for the merger and its fees are not contingent in any respect on the approval or completion of the merger.

The reserve reports of Ryder Scott Company, L.P. for Southwest and for each partnership are included as Appendix B to this prospectus/proxy statement.

Other than FBR, we have not had any contacts with any other person concerning the preparation of reports concerning the estimated reserves of the partnerships, evaluation of any of the partnerships or their assets, or the fairness of the merger.

The reserve values are estimates only and are not intended to represent the fair market value of the underlying properties. The reserve values are being used solely for purposes of determining the relative value of each of the partnerships in the merger. See “RISK FACTORS” for additional information concerning risks associated with the estimation of oil and gas reserves.

Components and Method of Merger Value for each Partnership

The following method was used to determine the number of shares of our common stock to be issued in exchange for each limited partner interest in each participating partnership. The method of determining the Merger Value was determined by Southwest, and was, thus, not determined by arm’s-length negotiations. See “RISK FACTORS.”

The Merger Value for each unit of limited partner interest in each partnership participating in the merger has been determined by (1) calculating the Net Asset Value of each partnership and Southwest and (2) dividing each entity’s Net Asset Value by the total combined Net Asset Value of all the partnerships and Southwest to determine a percentage of ownership for each partnership and Southwest.

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Our financial statements have been prepared in accordance with GAAP. As a consequence, the proportionate share of our ownership in the partnerships is included in our balance sheet. These amounts have been adjusted for use in the Merger Value calculation and, as a result, the amounts shown will not coincide with our audited and unaudited financial statements of Southwest presented elsewhere in this prospectus/proxy statement. Southwest’s short-term and long-term debt excludes the additional company value representing future interest expense as imposed by SFAS No. 15, “Accounting for Debtors and Creditors for Troubled Debt Restructurings.”

We determined the Net Asset Value per limited partner interest for each partnership as follows:

1. We engaged Ryder Scott Company, L.P., an independent engineering and consulting firm, to audit the volumes of proved reserves of Southwest and of each partnership as of December 31, 2001, and our internal engineers updated the reports to July 1, 2002. The reserve value component for Southwest and for each partnership is set forth in Appendix B to this prospectus/proxy statement. Please refer to the Ryder Scott Reports located in Appendix B for more information, including all of the parameters used in the estimation process, including any adjustments made for risk, location, type of ownership interest, operational characteristics and other factors. If we have not consummated our merger by year-end, Ryder Scott Company, L.P. will prepare the volumes of proved reserves for Southwest and each partnership at year-end and we will then recalculate the Net Asset Value based upon the revised reports and as updated by our internal staff of engineers.

2. Using the aforementioned Ryder Scott Reports and estimates, our engineers calculated the present value of estimated future net revenues for Southwest and each partnership as of July 1, 2002 using $26.46, $24.74, $23.30, $22.44 and $21.84, the five-year NYMEX future prices for oil, and $3.42, $3.86, $3.96, $3.99 and $4.02, the NYMEX futures price for gas, with prices held constant after year five at the year five price, less standard industry price adjustments listed below. Historical operating costs were adjusted only for those items affected by commodity prices, such as production taxes and ad valorem taxes. An industry-standard discount rate of 10% was used in the calculation of the value of proved developed producing reserves (“PDP”). Ten-percent is the discount rate commonly used in the industry for property reserve acquisition evaluations and the rate required to be used by the SEC for calculating discounted future net cash flows of all reserve categories for comparative reporting in the year-end reports of publicly owned oil and gas companies. We used a discount rate of 15% to calculate the value of the proved non-producing reserves (“PNP”) and a discount rate of 20% to calculate the value of the proved undeveloped reserves (“PUD”). By using a higher discount rate to calculate the future net cash flows of the currently non-producing reserve categories, we effectively adjusted the value of these reserves for the inherent risks incurred in their development. We believe that the higher discount rate used in the valuation of the non-producing reserves results in a more fair “risk-adjusted” value and is a commonly accepted practice in the industry. We believe the discount rates used in the calculation of the non-producing reserves represent a fair discount percentage based on our familiarity with the properties, as well as the fact that we did not adjust the value of the non-producing properties of the partnerships for their inability to develop these reserves. Currently, the partnerships (except Southwest Partners, L.P.) are unable to invest the capital necessary to develop their nonproducing and nondeveloped reserves because of cash flow and partnership agreement restrictions. The partnerships must rely on third party interest and successful negotiations to farm-out the development of these reserves. The farm-out negotiations usually require the owners to relinquish a large portion of ownership in the development properties. Each partnership’s reserve estimates and present value of future net revenues were prepared assuming the partnerships had the ability to invest the necessary capital expenditures to directly develop their nondeveloped reserves and the development restrictions did not apply.

The standard industry adjustments include:

a. the effects of oil quality;

b. British thermal unit, or BTU, content of gas;

c. any bonus paid (by the purchaser);

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d. oil and gas gathering and transportation costs; and

e. gas processing costs and shrinkage.

No adjustments were made for gas imbalances, which were deemed immaterial.

For purposes of the Merger Value calculation Southwest’s reserve estimates and present value of future net revenues were prepared assuming no ownership in the partnerships by Southwest.

3. We then determined the Net Asset Value for Southwest and each partnership using the following formula:

a. the present value (as described above) of the future net revenues as of July 1, 2002 using the appropriate discount factor for each reserve category, plus

b. the net working capital (current assets minus current liabilities) as of June 30, 2002, less

c. long-term debt, as of June 30, 2002, plus

d. the book value of any Additional net assets as of June 30, 2002, less

e. estimated merger expenses and fees, which apply only to Southwest’s Net Asset Value.

The assets and liabilities of Southwest and each partnership are accounted for in accordance with GAAP, which uses accrual-based accounting methodology. Our short-term and long-term debt, however, excludes the additional carrying value representing future interest expense.

4. The percentage of general partner interest owned by Southwest in each partnership was then subtracted from each partnership’s respective Net Asset Value to determine the limited partners’ Net Asset Value and Southwest’s Net Asset Value for its general partner interests.

5. The percentage of limited partner interests owned by Southwest in each partnership was then calculated and deducted from the limited partners’ Net Asset Value in each partnership to determine (a) the Net Asset Value of the partnership interests owned by Southwest, and (b) the Net Asset Value of partnership interests owned by all other limited partners in each partnership.

6. The Net Asset Value of each partnership attributable to the general partner interests and limited partner interests owned by Southwest was added to the Net Asset Value of Southwest to determine the final and Adjusted Net Asset Value for Southwest.

7. The Net Asset Value of the limited partners in each partnership (excluding Southwest’s general partner and limited partner interests) and the Adjusted Net Asset Value of Southwest was divided by the total of the Net Asset Value of the partners in each partnership (excluding Southwest’s general and partner interests) plus the final and Adjusted Net Asset Value of Southwest to determine a percentage of ownership to the total Net Asset Value for each partnership and Southwest.

8. The total number of shares of Southwest common stock and Class A common stock currently issued and outstanding was divided by Southwest’s percentage of ownership to the total Net Asset Value to determine the total number of shares of the combined business (on a post-merger basis and assuming the conversion of Class A common stock into common stock).

9. Each partnership’s percentage of ownership to the total Net Asset Value was then multiplied by the total number of shares of common stock of the combined business (on a post-merger basis and assuming the conversion of Class A common stock into common stock) to determine the number of shares of common stock to be allocated to each partnership.

10. The number of shares of common stock to be allocated to each partnership was then divided by the number of partnership interests in each partnership (less the general and limited partner interests owned by Southwest) to determine the number of shares of common stock per partnership interest to be distributed.

Shares of our special stock will be issued into escrow by Southwest, to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock

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under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger.” The issuance of 137,669 shares of our special stock into escrow is intended to prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will have a right to a number of shares of special stock, calculated by (a) multiplying the total number of shares of special stock to be allocated to the partnerships by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock allocable per each limited partner interest in each partnership.

The Merger Value will be recalculated using an Adjusted Net Asset Value on the effective date of the merger. The Adjusted Net Asset Value will use the same formula as outlined above, except for the following adjustments:

1. The proved reserves and future net revenues for Southwest and each partnership will be recalculated by Southwest by adjusting the most current Ryder Scott Reports forward to the month ending immediately preceding the month in which the merger becomes effective and recognizing any material reserve changes such as additions and deletions.

2. The net working capital, long-term debt, and Additional Net Assets used to calculate the Net Asset Value for each partnership and Southwest will be determined from the financial statements (prepared by Southwest using GAAP) as of the month ending immediately preceding the month in which the merger becomes effective, subject to and adjusted for any material changes in any of the aforementioned components.

Other Methods of Determining Merger Value

We believe that the method used to determine the Merger Value for each partnership is a fair and reasonable method of valuing the partnerships’ properties. The selected method, however, might not accurately reflect the value of each partnership’s assets. See “RISK FACTORS—Risk Factors of Participating in the Merger.” We considered a number of alternative methods of determining the Merger Value for each partnership before selecting a method. The following alternative methods for determining the Merger Value for each partnership should be taken into account in assessing the adequacy of the method that we have selected.

Net Book Value of Oil & Gas Properties.    We did not base the calculation of the Merger Value on the net book value of each partnership’s oil and gas properties. Each partnership’s financial statements are prepared in accordance with generally accepted accounting principles and use the full-cost method for reporting oil and gas assets. Under this method, the net book value is recorded at cost and depleted based on the units-of-revenue method. Changes in the fair market value of the oil and gas assets are not made to the book value under this method except in certain situations where a decrease in value, called a write-down, is booked to reflect a large reduction in value usually related to large decreases in commodity pricing. GAAP does not allow subsequent increases, or a write-up, in the fair market value when prices rise, but continues to reflect the lower value in the book value of the asset. We believe that the book value may not adequately reflect the fair market value of each partnership’s reserves. The reserves, as determined by an outside engineering firm and updated by our engineers, is valued at more current pricing and is more indicative of the fair market value. In all cases, the Merger Value is greater than the book value of each partnership, except in the case of Southwest Royalties, Inc. Income Fund V.

Going Concern.    We did not base the calculation of the Merger Value on the value of each partnership as continuing partnership operations. A valuation based on continuing operations would be based upon a decline in operating results due to the partnerships’ inability to develop their reserves, as well as uncertainty of future cash flows, and thus, larger discounts would apply. See “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger—Continuation Alternatives.” In all cases, the Merger Value is greater than the going concern value of each partnership.

Liquidation.    We did not base the calculation of the Merger Value on liquidating the partnerships. Prices paid for partnership properties in liquidation would likely include a substantial discount for the risk and

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uncertainties of future cash flows. See “BACKGROUND AND REASONS FOR THE MERGER—Alternatives to the Merger—Liquidation Alternatives.” In all cases, the Merger Value is greater than the liquidation value of each partnership.

Repurchase Offers.    We did not base the calculation of the Merger Value on the price of recent repurchase offers, but we are using a formula that is relatively equal to the repurchase formula but does not include the “risk” discount and uses a higher discount rate for non-producing reserve categories. The repurchase formula adds a discounted present value of the proved oil and gas reserves to the net book value of all other tangible assets (other than oil and gas reserves), current assets (less reserves for accounts determined uncollectible), less an amount equal to all debts and obligations of any nature for which a partnership is liable. The repurchase amount also reduces the value by a “risk factor” which is not greater than one-third of the total value. The Merger Value formula uses this same calculation without the “risk factor” discount. In all cases, the Merger Value is greater than the final presentment value of each partnership. The right of presentment is not available to the limited partners of Southwest Partners under the terms of its partnership agreement.

Bid Process.    We did not base the Merger Value on an outside bid process. We believe that the Merger Value calculation being used gives more overall value to the partnerships than relying on a bid process. Because the Merger Value calculation is used equally among all participating entities, we believe that the exchange of our common stock for limited partner interests gives each limited partner a better opportunity to receive a more full value for the properties of each partnership than they would receive through a bid process where larger discounts for risks and other factors are usually placed on producing and non-producing reserves.

MERGER OF EACH PARTNERSHIP

General

At the effective time of the merger of each partnership participating in the merger, the partnership will be merged with and into Southwest’s subsidiary, Southwest Consolidated Partnerships, and, immediately thereafter, Southwest Consolidated Partnerships will merge with and into Southwest’s subsidiary, Southwest Managed Assets. Southwest Managed Assets will be the surviving entity. In addition, at the effective time of the merger of each partnership that participates in the merger, each of your limited partner interests in the partnership that participates in the merger will ultimately be converted into our common stock. See “BACKGROUND AND REASONS FOR THE MERGER” for diagrams and for a detailed description of the merger.

In connection with the merger and assuming all 21 partnerships participate in the merger, approximately 688,347 shares of our common stock will be distributed to the limited partners and 137,669 shares of our special stock will be issued into an escrow account. Under certain circumstances the special stock will convert into 137,669 shares of our common stock and, thereafter, the common stock will be distributed to the limited partners. These numbers, however, may change depending on the final calculation of the Adjusted Net Asset Value of each of the partnerships and Southwest. The limited partners of each of the partnerships will be allocated shares of our common stock in proportion to the Merger Value of their partnership relative to the total Merger Value of all the partnerships and Southwest.

No Continuing Interest in the Partnerships

Upon completion of the merger of each partnership participating in the merger, you, as a limited partner of a partnership, will have no continuing interest in, or rights of, the partnership. The transfer books of each participating partnership will be closed on the closing date of the merger of the partnership. All partnership interests in each participating partnership will cease to be outstanding, will automatically be canceled and retired, and will cease to exist. The transfer books entries, which previously represented partnership interests in each participating partnership held by record limited partners, will represent only the right to receive Southwest common stock.

We intend to mail certificates representing Southwest common stock to the limited partners of record of each partnership participating in the merger promptly following the effectiveness of the merger. Additionally, the

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escrow agent will hold records indicating the additional amount of common stock limited partners would be entitled to receive in the event the special stock converts into common stock and is thereafter distributed to the limited partners.

Fractional Shares

We will not issue fractional shares of common stock to any limited partner upon completion of the merger of any partnership. Instead, we will round any fractional shares of our common stock to the nearest whole share. We will not issue fractional shares of special stock to the escrow account in the merger.

Future of a Partnership that does not participate in the Merger

If your partnership does not participate in the merger for any reason, that partnership will remain in existence. Some reasons your partnership might not participate in the merger are that (1) the limited partners vote against the merger, (2) a condition in the merger agreements is not satisfied, or (3) we exercise a termination right with respect to the merger for that partnership.

We have not formulated an alternative business plan for any nonparticipating partnership. The business objectives of each nonparticipating partnership will continue as they are. We plan to continue to manage each nonparticipating partnership and operate it in accordance with the terms of its current partnership agreement. Each nonparticipating partnership will continue to operate as a separate legal entity with its own assets and liabilities. Distributions from any nonparticipating partnership are expected to continue to decline since its production revenues are expected to continue to decline more quickly than its product costs. Regardless of whether any nonparticipating partnership distributes cash, limited partners must continue to include their share of partnership income and loss in their individual tax returns.

Our Board of Directors will decide what, if any, actions we will take regarding any nonparticipating partnership. Potential actions might include a tender offer for limited partner interests or a proposal to acquire the assets of, or a merger of, one or more of the nonparticipating partnerships. The proposal may be on terms similar to or different from those of the merger described in this prospectus/proxy statement.

Termination of Registration and Reporting Requirements of Certain Partnerships

As a result of the merger of each partnership that participates in the merger, the partnership interests in the partnerships, as well as the partnership itself, will cease to exist. Sixteen of the partnerships described in this proxy statements/prospectus have registered their limited partner interests under, or are otherwise subject to the informational requirements of, the Exchange Act. See “WHERE YOU CAN FIND MORE INFORMATION” for a list of those partnerships. Upon the completion of the merger of each reporting partnership, we intend to terminate:

• registration of the limited partner interests of the partnerships under the Exchange Act; and

• the partnership’s obligations to file reports and other information under the Exchange Act.

We plan to cause each partnership that does not participate in the merger that is also a reporting partnership to continue to file reports and other information under the Exchange Act. However, our Board of Directors could determine in the future to cause each such partnership to terminate its reporting obligations as permitted by federal securities laws.

The advantages of remaining registered, or remaining obligated to file reports, under the Exchange Act include the informational and reporting requirements under the Exchange Act, including requirements related to tender offers, proxy solicitation and consents and insiders’ transactions in partnership interests. Those reporting requirements may provide limited partners with more detailed information on a more frequent basis than might otherwise be required under the partnership agreement for the partnership. In addition, a partnership’s filings under the Exchange Act are available to the public over the Internet at the SEC’s website at http://www.sec.gov

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and are also available at the SEC’s public reference rooms in Washington, D.C., New York, New York and Chicago, Illinois.

The disadvantages of remaining registered, or remaining obligated to file reports, include each reporting partnership’s cost to prepare and distribute the various reports and other information required under the Exchange Act. Terminating the registration of the limited partner interests of a nonparticipating partnership or otherwise terminating its filing and reporting obligations could reduce that partnership’s general and administrative expenses.

Conditions to Consummation of the Merger

We will complete the merger of each partnership only if the conditions of the merger agreements are satisfied or, if permitted, waived. These conditions include:

• the adoption and approval of the merger by the limited partners in either Southwest Partners, L.P. or Southwest Royalties Inc. Income Fund VI, L.P.;

• the consent and waiver of certain provisions of our Senior Credit Agreement and the Indenture governing our Senior Secured Notes due 2004;

• the approval of the merger by our stockholders;

• the absence of any law or court order that prohibits the merger; and

• the absence of any lawsuit challenging the legality or any aspect of the merger.

So long as the law allows us to do so, we may choose to complete a merger of any partnership even though a condition has not been satisfied if the limited partners have approved the merger. We may complete the merger of any one or some of the partnerships, even if limited partners in other partnerships do not approve the merger.

Accounting Treatment

Our acquisition of the assets and liabilities of the partnerships in connection with the merger will be accounted for as a combination of entities under common control (as if it were a pooling). Under the combination of entities under common control accounting method, both our assets and liabilities and the assets and liabilities of the partnerships will be carried forward to the combined business at their historical recorded bases. Results of operations of the combined business will include both our results and the results of the participating partnerships for the entire fiscal year in which the merger occurs. The reported balance sheet amounts and results of operations for the separate entities for the prior periods will be restated, as appropriate, to reflect the combined financial position and results of operations for the combined business.

Expenses and Fees and Source of Funds

We will pay for the costs of planning and developing the merger and presenting it to you without regard to whether the merger is consummated. The estimated amount of these costs is approximately $3.0 million. We are paying for costs of merger with existing cash flows from operations.

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The following is a list of the estimated expenses to be incurred by us in connection with the merger. All amounts shown are estimates (except the SEC registration fee). The merger will be conducted based on an exchange of securities; therefore, there will be no net cash distribution made.

Securities and Exchange Filing Fee	$	1,242
Accounting Fees	$	250,000
Legal Fees	$	1,150,000
Information Agent, Solicitation and Proxy Tabulation Fees	$	350,000
Independent Petroleum Consultant Fees	$	50,000
Printing and Postage Expenses	$	1,000,000
Fairness Opinion Provider Fees	$	250,000
Nasdaq (National Market) Filing Fees	$
Total Expenses	$

Regulatory Requirements

No federal or state regulatory requirements must be satisfied or approvals obtained in connection with the merger, except (1) filing a registration statement that includes this prospectus/proxy statement with the SEC and obtaining the SEC’s declaration that the registration statement is effective under the Securities Act, and (2) filing certificates of merger with the Secretary of State of Delaware and the Secretary of State of Tennessee.

Nasdaq Listing

We are in the process of applying to have our shares of common stock to be issued in the merger listed on Nasdaq (National Market) under the symbol “SWRI.” Our shares of special stock to be issued to the escrow account in the merger, however, will not be listed on any exchange or authorized for quotation on any inter-dealer quotation system. In the event, however, the special stock converts to common stock and the common stock is thereafter distributed to the limited partners, those shares of common stock would also be authorized for quotation on Nasdaq (National Market).

Appraisal Rights

Limited partners are not entitled to appraisal or dissenters’ rights under the laws of the State of Delaware or the State of Tennessee, which are the states of formation of the partnerships. If the merger of a partnership in which you hold a limited partner interest occurs, you will be bound by the merger even if you vote against the merger.

Access to Books and Records and Separate Counsel

Books and records relating to the operations of all of the partnerships are maintained at their respective principal place of business located at 407 North Big Spring, Suite 300, Midland, Texas 79701. All limited partners have access to the books and records of their respective partnership at all reasonable times, upon reasonable notice. No provision has been made to allow limited partners to obtain counsel or appraisal services at our expense.

Limited Partner Lists for each Partnership

Upon written request, we will deliver to you within five business days of receipt of your written request, a list of the names, addresses and interest holdings of the limited partners of the partnership(s) in which you hold interests, as of the record date. The list will be in the form you request to the extent that such form is available to us without undue burden or expense. You must reimburse us for the reasonable expenses we incur in delivering the list. At the time of a list request, the limited partner making the request must be able to comply with the requirements of paragraph (c) of SEC Rule 14a-7, a copy of which will be supplied to a limited partner, without charge, upon request. You should address your requests to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas, 79701, Attention: B.J. Parrish. You may also request a list of the names, addresses and interest holdings of the limited partners of the partnership(s) in which you hold interests, as of the record date at www.swrpartners.com.

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MERGER AGREEMENT

The following describes the material terms of the merger agreement by and among the partnerships and Southwest Consolidated Partnerships and the merger agreement by and between Southwest Consolidated Partnerships and Southwest Managed Assets. In this section, we refer to these agreements as the “first-step merger agreement” and the “second-step merger agreement,” respectively, and collectively as the “merger agreements.” Southwest, Southwest Managed Assets, each of the partnerships that participates in the merger and Southwest Consolidated Partnerships will sign the merger agreements as soon as the SEC declares effective under the Securities Act the registration statement that includes this prospectus/proxy statement. The full text of the form of the merger agreements is attached as Appendices C and D to this prospectus/proxy statement and is incorporated by reference into this prospectus/proxy statement. We encourage you to read the merger agreements in their entirety.

Structure; Effective Time

The first-step merger agreement provides for the merger of each partnership that participates in the merger with and into Southwest Consolidated Partnerships, with Southwest Consolidated Partnerships surviving each merger. The first-step merger will become effective at the time of the filing of the certificate of merger for those participating partnerships formed in Delaware, with the Secretary of State of Delaware, and, for each participating partnership formed in Tennessee, with the Secretary of the State of Tennessee. The second-step merger agreement provides for the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets, with Southwest Managed Assets surviving the merger. The second-step merger will become effective immediately after the first-step merger and upon the filing of the certificate of merger for the second-step merger with the State of Delaware. Each certificate of merger is expected to be filed as soon as practicable after the last condition precedent to the mergers set forth in the related merger agreements has been satisfied or waived. We estimate that the closing of the merger will be in the second quarter of 2003.

Effect of the Merger of each Partnership

As a result of the merger of each participating partnership with and into Southwest Consolidated Partnerships, the limited partners in the partnership will have no continuing interest in that partnership. Following the merger of each participating partnership, there will be no trading market for the limited partner interests in, and no further distributions paid to the former limited partners of, the participating partnerships. In addition, following the consummation of the merger of each participating partnership that is also a reporting partnership, the registration of any limited partner interests in the partnership under the Exchange Act will be terminated.

Conduct of Business Prior to the Merger of each Partnership

From the date of the execution of the first-step merger agreement until the effective time of the merger of each partnership, each partnership is required:

• to conduct its business only in the ordinary course consistent with past practice;

• to use its reasonable best efforts:

—    to preserve intact its business organization;

—    to keep available the services of its officers, employees and consultants; and

—    to preserve its relationships with customers, suppliers and other persons with which it has significant business dealings.

If distributions are so available, Southwest will continue to make quarterly cash distributions to the limited partners of each partnership until the SEC has declared the registration statement, of which this prospectus/proxy statement is a part, effective.

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Other Provisions

Special Meetings; Proxies.    We have agreed to cause the special meeting of the limited partners of each partnership to be duly called and held as soon as reasonably practicable for the purpose of voting on the approval and adoption of the merger proposals for each partnership and for the purpose of collecting the written consents of the stockholders of Southwest Consolidated Partnerships (effective immediately upon the merger of the partnerships with and into Southwest Consolidated Partnerships) to approve the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets. We have also agreed to use our reasonable best efforts to solicit from the limited partners of each partnership proxies in favor of the merger and to take all other action necessary or advisable to secure any vote or consent of the limited partners of the partnerships required by the partnership agreements of the partnership, in the case of the first-step merger, or bylaws, in the case of the second-step merger, and, in either case, the merger agreements, in connection with the merger of the partnerships with and into Southwest Consolidated Partnerships and with the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets.

Reasonable Commercial Efforts.    Each party to the merger agreements has agreed to use all reasonable commercial efforts:

• to obtain, in a timely manner, all necessary waivers, consents and approvals and to effect all necessary registrations and filings; and

• to take, or cause to be taken, all actions and to do, or cause to be done, all things necessary, proper or advisable under applicable laws and regulations to consummate as promptly as practicable the transactions contemplated by the merger agreements.

The merger agreements contain substantially reciprocal representations and warranties of Southwest Consolidated Partnerships, Southwest Managed Assets and each of the partnerships, including the following matters:

• due organization or formation, standing, corporate or partnership power and qualification;

• absence of any conflict, breach, notice requirement or default under organizational documents and material agreements as a result of each contemplated merger;

• authority to enter into and the validity and enforceability of the merger agreement;

• absence of any material adverse change since             ; and

• accuracy of information.

The first-step merger agreement contains representations and warranties by:

• each of the partnerships as to capitalization;

• Southwest Consolidated Partnerships and each reporting partnership, as to the absence in its reports filed with the SEC of any untrue statement of a material fact or any omission to state a material fact necessary to make the statements in such reports not misleading;

• Southwest Consolidated Partnerships and each partnership, that its financial statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and fairly present its financial condition and results of operations; and

• Southwest as to its capacity as the managing general partner of each partnership.

The second-step merger agreement contains representations and warranties by Southwest as to:

• due incorporation, standing, corporate power and qualification;

• capitalization; and

• due authorization and valid issuance of common stock and special stock.

Series B Special Shares.    Upon execution of the merger agreements, Southwest will issue into escrow shares of Series B special stock. The Series B special stock held in escrow will automatically convert into Southwest common stock upon the conversion of Southwest’s Series A special stock into common stock. Immediately after the conversion of such Series B special stock into common stock, such common stock will be issued into the escrow and thereafter distributed to the limited partners as provided in the second-step merger agreement.

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Conditions to the Merger of each Partnership into Southwest Consolidated Partnerships

Conditions to the Obligations of each Party.     The obligations of Southwest Consolidated Partnerships and each participating partnership to complete the merger of such partnership into Southwest Consolidated Partnerships are dependent on the satisfaction of the following conditions:

• the merger agreement shall have been approved by the requisite vote of the limited partners of each participating partnership entitled to vote at the partnerships’ special meeting;

• the merger agreement shall have been approved by the limited partners of either Southwest Royalties, Inc. Income Fund VI, L.P. or Southwest Partners, L.P.;

• the merger shall have been approved by our stockholders;

• the absence of any law, regulation, judgment, injunction, order or decree that would prohibit the consummation of any merger;

• the absence of any pending suit, action or proceeding challenging the legality or any aspect of the merger of any partnership or the transactions related to the merger;

• the authorization for listing on Nasdaq (National Market) upon official issuance of notice shall have been received for the shares of Southwest common stock to be issued upon the merger of Southwest Consolidated Partnerships into Southwest Managed Assets; and

• all material filings and registrations with, and notifications to, third parties shall have been made and all material approvals and consents of third parties shall have been received.

Conditions to the Obligations of Southwest Consolidated Partnerships.     The obligations of Southwest Consolidated Partnerships to complete the merger are further subject to the satisfaction of the following conditions:

• each participating partnership having performed in all material respects its agreements contained in the first-step merger agreement; and

• the representations and warranties of each participating partnership being true and correct in all material respects at the closing date of the merger of the participating partnership as if made at that time unless they relate to another specified time.

Conditions to the Obligations of each Partnership.     The obligations of each participating partnership to complete the first-step merger are further subject to the satisfaction of the following conditions:

• Southwest Consolidated Partnerships having performed in all material respects its agreements contained in the first-step merger agreement; and

• the representations and warranties of Southwest Consolidated Partnerships being true and correct in all material respects at the closing date of the merger of the partnership as if made at that time unless they relate to another specified time.

Conditions to the Merger of Southwest Consolidated Partnerships into Southwest Managed Assets

Conditions to the Obligations of each Party.     The obligations of Southwest Consolidated Partnerships and Southwest Managed Assets to complete the second-step merger are dependent on the satisfaction of the following conditions:

• the second-step merger agreement shall have been approved by the requisite vote of the stockholders of each party entitled to vote on the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets;

• the merger shall have been approved by our stockholders;

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• the absence of any law, regulation, judgment, injunction, order or decree that would prohibit the consummation of the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets;

• the absence of any pending suit, action or proceeding challenging the legality or any aspect of or the transactions related to the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets;

• the approval for for listing on Nasdaq (National Market) shall have been received for the shares of Southwest common stock to be issued upon the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets; and

• all material filings and registrations with, and notifications to, third parties shall have been made and all material approvals and consents of third parties shall have been received.

Conditions to the Obligations of Southwest Consolidated Partnerships.     The obligations of Southwest Consolidated Partnerships to complete the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets are further subject to the satisfaction of the following conditions:

• Southwest Managed Assets having performed in all material respects its agreements contained in the second-step merger agreement;

• Southwest’s common stock will have been approved for listing on Nasdaq (National Market); and

• the representations and warranties of Southwest Managed Assets being true and correct in all material respects at the closing date of the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets as if made at that time unless they relate to another specified time.

Conditions to the Obligations of Southwest Managed Assets.     The obligations of Southwest Managed Assets to complete the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets are further subject to the satisfaction of the following conditions:

• Southwest Consolidated Partnerships having performed in all material respects its agreements contained in the second-step merger agreement; and

• the representations and warranties of Southwest Consolidated Partnerships being true and correct in all material respects at the closing date of the merger of Southwest Consolidated Partnerships with and into Southwest Managed Assets as if made at that time unless they relate to another specified time.

Termination of the First-Step Merger Agreement and the Merger of Any Partnership into Southwest Consolidated Partnerships

The first-step merger agreement may be terminated and the merger of any partnership abandoned at any time prior to the effective time, whether before or after approval by the limited partners:

• by the mutual written consent of the parties;

• by any party, if:

— any applicable law, rule or regulation makes consummation of the merger illegal or otherwise prohibited or any final and non-appealable judgment, injunction, order or decree enjoining any party from consummating the merger is entered;

—    the requisite limited partner approval for a partnership is not obtained by a vote at the special meeting for the partnership or at any adjournment or postponement of the special meeting; or

—    any suit, action or proceeding is filed against Southwest, Southwest Consolidated Partnerships, any partnership or any officer, director or affiliate of Southwest or Southwest Consolidated

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Partnerships challenging the legality or any aspect of the merger of any partnership or the transactions related to the first-step merger;

• by Southwest in its sole discretion with regard to any partnership;

• by any partnership as to that partnership’s merger, if Southwest or Southwest Consolidated Partnerships is in material breach of the merger agreement;

If the first-step merger agreement is validly terminated or the merger of any partnership is abandoned, neither Southwest Consolidated Partnerships nor any partnership shall have any liabilities or obligations to the other parties based on the merger agreement or such merger, except:

• Southwest will pay all expenses and fees of each partnership in connection with the first-step merger of that partnership incurred before the termination of the first-step merger agreement or abandonment of the first-step merger of the partnership; and

• a party will be liable if that party is in breach of the first-step merger agreement.

Amendments and Waivers of First-Step Merger Agreement

Any provision of the first-step merger agreement may be amended prior to the effective time if the amendment is in writing and signed by Southwest, Southwest Consolidated Partnerships and each participating partnership.

Prior to the effective time, the parties may:

• extend the time for the performance of any of the obligations of the parties;

• waive any inaccuracies in the representations and warranties in the first-step merger agreement or in a document delivered pursuant to the first-step merger agreement; and

• waive compliance with any agreement or condition in the first-step merger agreement.

Any such extension or waiver will be valid only if it is in writing and signed by the party against whom the extension or waiver is to be effective.

Termination of the Second-Step Merger Agreement and the Merger of Southwest Consolidated Partnerships into Southwest Managed Assets

The second step merger agreement may be terminated and the second-step merger of Southwest Consolidated Partnerships and Southwest Managed Assets abandoned at any time prior to the effective time, whether before or after approval by the stockholders of the parties:

• by the mutual written consent of the parties;

• by any party, if:

—    any applicable law, rule or regulation makes consummation of the second-step merger illegal or otherwise prohibited or any final and non-appealable judgment, injunction, order or decree enjoining any party from consummating the second-step merger is entered;

—    the requisite written consent of the stockholders of either party is not obtained; or

—    any suit, action or proceeding is filed against Southwest, Southwest Consolidated Partnerships, Southwest Managed Assets or any officer, director or affiliate of any of such parties challenging the legality or any aspect of the second-step merger of or the transactions related to the second-step merger;

• by Southwest in its sole discretion;

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• by any party to the second-step merger agreement, if another party is in material breach of the second-step merger agreement;

If the second-step merger agreement is validly terminated or the second-step merger is abandoned, neither Southwest, Southwest Consolidated Partnerships nor Southwest Managed Assets shall have any liabilities or obligations to the other party based on the second-step merger agreement or such merger except that a party will be liable if that party is in breach of the second-step merger agreement.

Amendments and Waivers of Second-Step Merger Agreement

Any provision of the second-step merger agreement may be amended prior to the effective time if the amendment is in writing and signed by each party.

Prior to the effective time, the parties may:

• extend the time for the performance of any of the obligations of the parties;

• waive any inaccuracies in the representations and warranties in the second-step merger agreement or in a document delivered pursuant to the second-step merger agreement; and

• waive compliance with any agreement or condition in the second-step merger agreement.

Any such extension or waiver will be valid only if it is in writing and signed by the party against whom the extension or waiver is to be effective.

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MEETING, VOTING AND PROXY INFORMATION

General

This prospectus/proxy statement is being furnished to the limited partners of each partnership in connection with the solicitation of proxies on our behalf for use at the special meeting of limited partners.

Southwest, as the general partner of the partnerships, recommends that you vote in favor of the merger.

Meeting

The joint special meeting of the limited partners of all the partnerships that we propose to include in the merger will be held at The Midland Hilton, 117 West Wall Street, Midland, Texas 79701, at 10:00 a.m. Central Time, on                 ,                 , 2002 to consider and vote on the merger, the amendments to each of the partnership agreements and any other matters which may properly come before the special meeting. With respect to the special meeting, the presence, in person or by proxy, of limited partners holding a majority of the outstanding limited partner interests of each partnership will constitute a quorum with respect to each such partnership.

At the special meeting, the merger and the amendments to each of the partnership agreements will be presented for the vote of the limited partners. The vote of any limited partner who is represented at the meeting by proxy will be cast as specified in the proxy or, if no vote is specified in a duly executed and delivered proxy, such vote will be cast for the applicable proposal. Any limited partner who is present at the meeting in person will be entitled to vote at the meeting regardless of whether he has previously granted a proxy with respect thereto, although attendance at the meeting alone will not revoke a previously granted proxy.

Immediately following the special meeting of limited partners, the written consent of stockholders of Southwest Consolidated Partnerships to approve the subsequent merger of Southwest Consolidated Partnerships into Southwest Managed Partners will become effective.

Amendments to the Partnership Agreements

You are being asked to vote to amend the partnership agreement of each partnership in which you own limited partner interests. This amendment will permit the initial merger of your partnership with and into Southwest Consolidated Partnerships. Specifically, the amendments will authorize the merger of the partnerships with and into Southwest Consolidated Partnerships and will eliminate any restrictions on the merger otherwise contained in the partnership agreements. Furthermore, and as part of this process, if you own limited partner interests in Southwest Royalties Income Fund V, L.P. or Southwest Royalties Income Fund VI, L.P., the amendment authorizes the filing with the Tennessee Secretary of State of a new certificate of limited partnership through which the partnership elects to be governed by the provisions of the Tennessee Revised Uniform Limited Partnership Act, as enacted in 1989.

Record Date

Only limited partners of record at the close of business on             , 2002, as shown on our records, will be entitled to notice of and to vote or to grant proxies to vote at the special meeting.

There is no record date for the merger of Southwest Consolidated Partnerships into Southwest Managed Assets; instead, limited partners who vote in favor of the merger of their respective partnerships into Southwest Consolidated Partnerships will also execute a written consent, as a prospective stockholder of Southwest Consolidated Partnerships, to approve the subsequent merger of Southwest Consolidated Partners into Southwest Managed Assets. The written consent will become effective upon the merger of the participating partnerships into Southwest Consolidated Partners.

Vote Required for Approval

The purpose of the joint special meeting is to ask limited partners of each partnership to approve the merger and the amendments to each of the partnership agreements. The merger and the amendments to each partnership agreement must be approved by at least 75% of the outstanding limited partner interests of each partnership before that partnership will be able to participate in the merger. We are requiring 75% approval in order to satisfy our obligations to show that the merger is not unfair under the NASD Rules. Limited partners of each partnership are entitled to vote at the special meeting based upon the limited partners’ respective percentage of partnership interests in the partnership.

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Set forth below is the number of limited partner interests outstanding for each partnership as of June 30, 2002

Partnership	Number of Limited Partnership Interests Outstanding
Southwest Royalties, Inc. Income Fund V	7,499.1
Southwest Royalties, Inc. Income Fund VI	20,000
Southwest Oil and Gas Income Fund VII-A	15,000
Southwest Royalties Institutional Income Fund VII-B	15,000
Southwest Oil and Gas Income Fund VIII-A	13,596
Southwest Royalties Institutional Income Fund VIII-B	10,147
Southwest Oil and Gas Income Fund IX-A	10,453
Southwest Royalties Institutional Income Fund IX-B	9,782
Southwest Oil & Gas Income Fund X-A	10,484
Southwest Royalties Institutional Income Fund X-A	11,316
Southwest Oil & Gas Income Fund X-B	10,889
Southwest Royalties Institutional Income Fund X-B	11,181
Southwest Oil & Gas Income Fund X-C	6,246
Southwest Royalties Institutional Income Fund X-C	5,983
Southwest Developmental Drilling Fund 91-A	1,144.5
Southwest Developmental Drilling Fund 92-A	1,407
Southwest Combination Income/Drilling Program 1988	3,509
Southwest Developmental Drilling Fund 1990	173.5
Southwest Developmental Drilling Fund 1993	2,078
Southwest Developmental Drilling Fund 1994	2,235
Southwest Partners.	43.5

We hold a number of limited partner interests in the partnerships. To our knowledge, none of our executive officers, directors or their affiliates hold any limited partner interests in any of the partnerships. The following table gives the percent of outstanding limited partner interests which we held in each partnership as of June 30, 2002.

Partnership	Percent of Limited Partner Interests held by Southwest
Southwest Royalties, Inc. Income Fund V	34.18	%
Southwest Royalties, Inc. Income Fund VI	31.83	%
Southwest Oil and Gas Income Fund VII-A	28.12	%
Southwest Royalties Institutional Income Fund VII-B	26.21	%
Southwest Oil and Gas Income Fund VIII-A	21.81	%
Southwest Royalties Institutional Income Fund VIII-B	18.83	%
Southwest Oil and Gas Income Fund IX-A	3.90	%
Southwest Royalties Institutional Income Fund IX-B	2.93	%
Southwest Oil & Gas Income Fund X-A	1.47	%
Southwest Royalties Institutional Income Fund X-A	2.20	%
Southwest Oil & Gas Income Fund X-B	1.69	%
Southwest Royalties Institutional Income Fund X-B	3.99	%
Southwest Oil & Gas Income Fund X-C	3.05	%
Southwest Royalties Institutional Income Fund X-C	1.57	%
Southwest Developmental Drilling Fund 91-A	1.71	%
Southwest Developmental Drilling Fund 92-A	0.32	%
Southwest Combination Income/Drilling Program 1988	3.68	%
Southwest Developmental Drilling Fund 1990	0.00	%
Southwest Developmental Drilling Fund 1993	0.13	%
Southwest Developmental Drilling Fund 1994	0.00	%
Southwest Partners.	4.40	%

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We are generally entitled under the partnership agreements to vote the limited partner interests we hold at the joint special meeting for each partnership. We plan to vote all our limited partner interests for the merger and for the amendments to the partnership agreements.

Limited partners who vote in favor of the merger of the partnerships into Southwest Consolidated Partnership will also execute a written consent, as prospective stockholders of Southwest Consolidated Partnerships, to vote in favor the subsequent merger of Southwest Consolidated Partnership with and into Southwest Managed Assets.

Voting

Ways to Vote

You may vote your limited partner interests in any of four ways:

(1) Voting by Mail.    If you choose to vote by mail, simply mark your proxy, date and sign it, and return it in the postage-paid return envelope provided.

(2) Voting by Telephone.    You can vote your limited partner interests by telephone proxy by calling toll-free 1-800-            . Telephone voting is available 24 hours a day. You will be prompted to enter your              digit control number, which appears on the enclosed proxy card. Follow the simple instructions the voice provides you.

(3) Voting by Internet.    You can vote your proxy via the Internet at http:/www.swrpartners.com/            . The website for Internet voting is on your proxy card, and voting is also available 24 hours a day. You will be prompted to enter your              digit control number, which appears on the enclosed proxy card, to create an electronic ballot.

(4) Voting in Person.     You can vote by appearing and voting in person at the special meeting.

If you vote by telephone or via the Internet you should not return your proxy card. Your telephone or Internet vote authorizes the proxies to vote your limited partner interests in the same manner as if you had marked, signed and returned your proxy card. Instructions on how to vote by telephone or via the Internet are located on the proxy card attached to this prospectus/proxy statement and on the back cover of this prospectus/proxy statement. The accompanying proxy card is for your use if you are unable to attend the special meeting in person and if you do not wish to vote via telephone or the Internet. You may also vote by telephone, via the Internet or by proxy card if you are able to attend the meeting but do not wish to vote in person. If you choose to vote by proxy card, you should specify your choices with regard to the proposal on the enclosed proxy card. The proxy cards that the holders of limited partner interests properly complete, date, sign and return, as well as the votes they cast by telephone or via the Internet, will serve as voting instructions to the proxies to vote those limited partner interests at the special meeting as directed. Please vote by telephone, via the Internet or properly complete, sign and date the proxy card and return it in the enclosed postage-paid envelope.

Proxy Tabulator

We have retained D.F. King & Co., Inc. to serve as the independent proxy tabulator for the special meeting. Proxies should be returned to the proxy tabulator at the following address:

77 Water Street

New York, New York 10005

Attn: Tabulation

Voting of Proxies

A person who is a limited partner in more than one partnership may vote via telephone or the Internet, or may grant a proxy to vote for or against, or to abstain from voting on, on a partnership-by-partnership basis by so indicating on his proxy card.

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To be effective, a proxy card must be properly completed, executed, and delivered to the proxy tabulator prior to the special meeting at which the proxy granted therein is to be exercised. Any proxy granted in a proxy card that is properly completed, executed, and returned prior to the meeting at which it is to be exercised will be voted in accordance with the specification indicated on such proxy card. A properly executed and returned proxy card in which no specification is made will be deemed to have granted a proxy to vote for the plan of merger.

Revocation

Any limited partner who returns his proxy card or votes via telephone or the Internet may revoke the proxy and change his vote at any time prior to the meeting by:

• giving written notice to the proxy tabulator, at the address set forth above, of such revocation;

• using the telephone or Internet voting procedures after you have already voted;

• properly completing and executing a later-dated proxy card and delivering it to the proxy tabulator at the address set forth above (provided that such revocation will not be effective unless it is received by the proxy tabulator at or before the special meeting at which such proxy was to be exercised); or

• appearing and voting in person at the meeting at which such proxy was to be exercised, although simply attending the meeting by itself will not revoke your previously-granted proxy.

Validity

A proxy card will not be valid unless it has been properly completed, executed, and timely delivered to the proxy tabulator. All questions as to the validity, form, eligibility (including time of receipt), and acceptance of proxy cards will be determined by us. Our determination will be final and binding. We will have the right to waive any irregularities or conditions as to the manner of voting. Any irregularities in connection with proxies or votes must be cured within such time as we shall determine unless waived by us. We are under no duty to give notification of defects in a proxy card and will incur no liability for the failure to give such notification.

Delivery of a proxy card is at the risk of the limited partner. A proxy card will be effective for purposes of granting a proxy only when it is actually received by the proxy tabulator. We may accept proxies by any reasonable form of communication so long as they can be reasonably assured that the communication is authorized by the limited partner holding the related limited partner interests.

Abstentions and Broker Non-Votes

Because adoption of the merger requires the affirmative vote of at least 75% of each partnership’s limited partner interests outstanding as of the record date, abstentions and failures to vote will have the effect of a vote against the merger. Brokers, if any, who hold limited partner interests of a partnership in street name for customers have the authority to vote on “routine” proposals when they have not received instructions from beneficial owners. However, these brokers are precluded from exercising their voting discretion with respect to the approval and adoption of non-routine matters such as the merger and thus, absent specific instructions from the beneficial owner of the limited partner interests, brokers are not empowered to vote the limited partner interests with respect to the merger. These “broker non-votes” will have the effect of a vote against the merger.

Solicitation of Proxies

We will bear the cost of the solicitation of proxies, including the costs of preparing, filing, printing and distributing this prospectus/proxy statement. In addition to solicitation by mail, our directors, officers and employees may solicit proxies from you by telephone, the Internet or by any other means of communication.

Such directors, officers and employees will not be additionally compensated but may be reimbursed for reasonable out-of-pocket expenses in connection with such solicitation. Arrangements will also be made with

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brokerage houses and other custodians, nominees and fiduciaries for their reasonable out-of-pocket expenses in connection therewith.

In addition, we have retained D.F. King & Co. to assist in the solicitation of proxies for an estimated fee of $             plus reasonable out-of-pocket expenses.

The proposed merger is of great importance to you. Accordingly, we urge you to read and carefully consider the information presented in this prospectus/proxy statement, and to complete, date, sign and promptly return the enclosed proxy card in the enclosed postage pre-paid return envelope.

Approval of the Merger by Stockholders of Southwest

We have voluntarily submitted the merger proposal to our stockholders. Additionally, we are amending our Amended and Restated Certificate of Incorporation to increase the number of authorized shares of special stock and to designate such additional special stock as Series B special stock. The merger must be approved by a majority of the votes cast and the amendment must be approved by two-thirds of our shares of outstanding Class A common stock and common stock, voting together as a single class. As of September 30, 2002, there were 900,000 shares of our Class A common stock outstanding and 100,000 shares of our common stock outstanding. The holders of our common stock and Class A common stock are entitled to one vote per share. Only our stockholders of record at the close of business on             , 2002, as shown on our records, will be entitled to vote. Our stockholders are not entitled to appraisal or dissenters’ rights in connection with the merger.

MANAGEMENT OF SOUTHWEST

The management of the partnerships is provided by Southwest as the managing general partner. The following information sets forth the age and positions and offices with Southwest of our directors and executive officers:

Name	Age	Position and Office
H.H. Wommack, III	46	Chairman, President, Chief Executive Officer and Director
James N. Chapman(1)	40	Director
William P. Nicoletti(2)	57	Director
Joseph J. Radecki, Jr.(2)	44	Director
Richard D. Rinehart(1)	67	Director
John M. White(2)	46	Director
Herbert C. Williamson, III(1)	53	Director
Bill E. Coggin	48	Vice President and Chief Financial Officer
J. Steven Person	44	Vice President, Marketing

⁽¹⁾ Member of the Compensation Committee

⁽²⁾ Member of the Audit Committee

Set forth below is a description of the backgrounds, including business experience during the past five years, and the period of service with Southwest of our directors and executive officers:

H.H. Wommack, III has served as our Chairman of the Board, President, Chief Executive Officer and a director since our founding in 1983. Since 1997 Mr. Wommack has served as President, Chief Executive Officer and Chairman of SRH, our former parent and current holder of 10% of our voting share capital. Since 1997 Mr. Wommack has served as chairman of the board of directors of Midland Red Oak Realty, Inc. From 1997 until December 2000, Mr. Wommack served as chairman of the board of directors of Basic Energy Services, Inc. and since December 2000 has continued to serve on Basic’s board of directors. Prior to our formation, Mr. Wommack was a self-employed independent oil and gas producer engaged in the purchase and sale of royalty and working interests in oil and gas leases and the drilling of wells. Mr. Wommack graduated from the University of North Carolina at Chapel Hill and received his law degree from the University of Texas.

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James N. Chapman has served as a director since the closing of the Exchange Transaction. Mr. Chapman has been involved in the investment banking industry for 18 years, presently acting as a capital markets and strategic planning consultant with private and public companies across a range of industries, including metals, mining, manufacturing, aerospace, airline, service and healthcare. Prior to establishing an independent consulting practice, Mr. Chapman worked for The Renco Group, Inc., a multi-billion private corporation in New York, for which Mr. Chapman developed and implemented financing and merger and acquisition strategies for Renco’s diverse portfolio of companies. Prior to Renco, Mr. Chapman was a founding principal of Fieldstone Private Capital Group, a capital markets advisory firm that he joined upon its inception in August 1990. Prior to joining Fieldstone, Mr. Chapman worked for Bankers Trust Company for six years, most recently in the BT Securities Capital Markets area. Mr. Chapman received an MBA degree with distinction from the Amos Tuck School at Dartmouth College and was elected an Edward Tuck Scholar. He received his BA degree with distinction, magna cum laude, at Dartmouth College, was elected to Phi Beta Kappa and was a Rufus Choate Scholar.

William P. Nicoletti has served as a director since the closing of the Exchange Transaction. Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., an investment banking and financial advisory firm. He was formerly a senior officer and head of the Energy Investment Banking Groups of E. F. Hutton & Company Inc., PaineWebber, Incorporated and McDonald Investments Inc. Mr. Nicoletti is Chairman of the board of directors of Russell-Stanley Holdings, Inc., a manufacturer and marketer of steel and plastic industrial containers. He is a director of MarkWest Energy Partners, L.P., a business engaged in the gathering and processing of natural gas and the fractionation and storage of natural gas liquids. Mr. Nicoletti is also a Director and Chairman of the Audit Committee of Star Gas Partners, L.P., the nation’s largest retail distributor of home heating oil and a major retail distributor of propane gas. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA degree from Columbia University Graduate School of Business.

Joseph J. Radecki, Jr. has served as a director since the closing of the Exchange Transaction. Mr. Radecki is currently a Managing Director in the Leveraged Finance Group of CIBC World Markets where he is principally responsible for the firm’s financial restructuring and distressed situation advisory practice. Prior to joining CIBC World Markets, Mr. Radecki was an Executive Vice President and Director of the Financial Restructuring Group of Jefferies & Company, Inc. from 1990 to 1998. From 1983 until 1990, Mr. Radecki was First Vice President in the International Capital Markets Group at Drexel Burnham Lambert, Inc., where he specialized in financial restructurings and recapitalizations. Over the past fourteen years, Mr. Radecki has been integrally involved in over 120 transactions totaling nearly $50 billion in recapitalized securities. Mr. Radecki currently serves as a Director of Wherehouse Entertainment, Inc., a music and video specialty retailer, and RBX Corporation, a manufacturer of rubber and plastic foam and other polymer products. He has previously served as Chairman of the Board of American Rice, Inc., an international rice miller and marketer, as a member of the board of directors of Service America Corporation, a national food service management firm, Bucyrus International, Inc., a mining equipment manufacturer, and ECO-Net, a non-profit engineering related network firm. Mr. Radecki graduated magna cum laude in 1980 from Georgetown University with a B.A. in Government.

Richard D. Rinehart has served as a director since the closing of the Exchange Transaction. Mr. Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel Resources, Inc. PetroCap, Inc. provides investment and merchant banking services to a variety of clients active in the oil and gas industry. Kestrel Resources, Inc. is a privately owned oil and gas operating company. He served as Director of Coopers & Lybrand’s Energy Systems and Services Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to joining Coopers & Lybrand, he was chief executive officer/founder of Dawn Information Resources, Inc., formed in 1986 and acquired by Coopers & Lybrand in early 1991. Mr. Rinehart served as CEO of Terrapet Energy Corporation during the period 1982 through 1986. Prior to the formation of Terrapet in 1982, he was employed as President of the Terrapet Division of E.I. DuPont de Nemours and Company. Before its acquisition by DuPont, he served as CEO and President of Terrapet Corp., a privately owned E & P company. Before the formation of Terrapet Corp. in 1972, he was manager of supplementary recovery methods and senior evaluation engineer with H. J. Gruy and Associates, Inc., Dallas, Texas.

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John M. White has served as a director since the closing of the Exchange Transaction. Mr. White is currently an oil and gas analyst with BMO Nesbitt Burns, responsible for Fixed Income research on oil, gas and energy companies. Prior to joining BMO Nesbitt Burns in 1998, Mr. White was responsible for Fixed Income research on the oil and gas industry at John S. Herold, Inc., an independent oil and gas research and consulting firm. Mr. White’s experience also includes managing a portfolio of oil and gas loans for The Bank of Nova Scotia, which included independent exploration and production companies, oil service companies, gas pipelines, gas processors and refiners. Prior to entering banking, Mr. White was with BP Exploration, where he worked primarily in exploration and production.

Herbert C. Williamson, III has served as a director since the closing of the Exchange Transaction. At present, Mr. Williamson is self-employed as a consultant. From March 2001 to March 2002 Mr. Williamson served as an investment banker with Petrie Parkman & Co. From April 1999 to March 2001 Mr. Williamson served as chief financial officer and from August 1999 to March 2001 as a director of Merlon Petroleum Company, a private oil and gas company involved in exploration and production in Egypt. Mr. Williamson served as executive vice president, chief financial officer and director of Seven Seas Petroleum, Inc., a publicly traded oil and gas exploration company, from March 1998 to April 1999. From 1995 through April 1998, he served as director in the Investment Banking Department of Credit Suisse First Boston. Mr. Williamson served as vice chairman and executive vice president of Parker and Parsley Petroleum Company, a publicly traded oil and gas exploration company (now Pioneer Natural Resources Company) from 1985 through 1995.

Bill E. Coggin has served as our Vice President and Chief Financial Officer since joining Southwest in 1985. Previously, Mr. Coggin was Controller for Rod Ric Corporation, an oil and gas drilling company, and for C.F. Lawrence & Associates, a large independent oil and gas operator. Mr. Coggin received a B.S. in Education and a B.A. in Accounting from Angelo State University.

J. Steven Person has served as our Vice President, Marketing since joining Southwest in 1989. Mr. Person began in the investment industry with Dean Witter in 1983. Prior to joining Southwest, Mr. Person was a senior wholesaler with Capital Realty, Inc. While at Capital Realty, he was involved in the syndication of mortgage based securities through the major brokerage houses. Mr. Person receive a B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist University.

Other significant employees include:

Jon P. Tate, age 43, has served as our Vice President, Land and Assistant Secretary since 1989. From 1981 to 1989, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as land manager. Mr. Tate is a member of the Permian Basin Landman’s Association.

R. Douglas Keathley, age 46, has served as our Vice President, Operations since 1992. Before joining us, Mr. Keathley worked as a senior drilling engineer for ARCO Oil and Gas Company and in similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.

There are no family relationships between any of our directors and executive officers. Mr. Nicoletti serves on the boards of directors of MarkWest Energy Partners, L.P. and Star Gas Partners, L.P., both of which have securities registered pursuant to Section 12 of the Exchange Act. Mr. Williamson serves on the board of directors of Pure Resources, Inc., which has securities registered pursuant to Section 12 of the Exchange Act. Mr. Chapman serves on the board of directors of Davel Communications, Inc., which has securities registered pursuant to Section 12 of the Exchange Act. No other director serves on the board of directors of another company with a class of securities registered pursuant to Section 12 of the Exchange Act or subject to the requirements of Section 15(d) of the Exchange Act or any company registered as an investment company under the Investment Company Act of 1940, as amended.

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Executive Compensation

The following table sets forth certain information for fiscal years 2001, 2000 and 1999 with respect to the compensation paid to Mr. Wommack, our Chairman, Chief Executive Officer and President, and our four other most highly compensated executive officers.

		Annual Compensation
Name and Principal Position	Year	Salary($)			Bonus($)(1)		Profit Sharing/ 401(k) Contribution ($)		Insurance Premiums		Carried Interest in Limited Partnerships(2)
H.H. Wommack, III,	2001	$	636,607	(3)	$	178,290	$	2,100	$	11,910	$	367,295
Chairman, President and	2000	$	600,000	(3)	$	396,253	$	2,100	$	4,550	$	84,079
Chief Executive Officer	1999	$	600,000	(3)	$	166,303	$	2,000	$	4,550	$	45,384
Bill E. Coggin,	2001	$	225,000		$	66,546	$	2,100	$	6,622	$	—
Vice President and	2000	$	225,000		$	152,690	$	2,100	$	2,990		—
Chief Financial Officer	1999	$	175,000		$	67,667	$	2,000	$	2,750		—
J. Steven Person,	2001	$	90,000	(4)	$	44,558	$	2,100	$	11,910		—
Vice President, Marketing	2000	$	86,250	(4)	$	83,568	$	1,481	$	4,549		—
	1999	$	64,583	(4)	$	28,476	$	1,000	$	4,550		—
R. Douglas Keathley,	2001	$	135,000		$	6,365	$	1,350	$	11,832		—
Vice President, Operations	2000	$	114,000		$	16,540	$	1,201	$	4,550		—
	1999	$	106,800		$	7,257	$	961	$	4,550		—
Jon P. Tate,	2001	$	110,880		$	5,463	$	2,100	$	6,493		—
Vice President, Land and	2000	$	105,600		$	15,720	$	1,808	$	2,990		—
Assistant Secretary	1999	$	98,000		$	14,041	$	1,679	$	2,690		—

⁽¹⁾ Amount includes club dues and automobiles furnished by Southwest.

⁽²⁾ Mr. Wommack has acted as a general partner of 21 income funds, two combination income/drilling funds and one drilling fund which we have sponsored since 1983, holding a 1% additional general partner interest in these partnerships. Effective December 31, 2001, Mr. Wommack sold his general partner interest in six partnerships for approximately $296,000. Mr. Wommack currently serves as an additional general partner of nine of the limited partnerships we propose to include in the merger.

⁽³⁾ During these periods Mr. Wommack’s annual salary included compensation used to pay interest and principal on a loan from Southwest to Mr. Wommack, which proceeds from the loan were used by Mr. Wommack to purchase shares of SRH common stock. On April 19, 2002 we canceled Mr. Wommack’s loan in exchange for 123,710 shares of SRH common stock beneficially owned by Mr. Wommack and reduced his annual salary to $350,000.

⁽⁴⁾ Mr. Person’s salary does not include compensation received from his services rendered to Midland Red Oak Realty, Inc, a former affiliate of Southwest. Effective August 1, 2002, Mr. Person’s annual salary from Southwest is $180,000.

Agreements with Executive Officers

We have entered into an employment agreement with H.H. Wommack, III, retaining him as our Chairman, President and Chief Executive Office. The agreement, the term of which ends on September 30, 2005, provides for a base salary for Mr. Wommack of $350,000 per year. The Board intends to establish a bonus plan for Mr. Wommack based upon his annual performance, which bonus may be up to 50% of Mr. Wommack’s base salary. The Board also has discretion to pay Mr. Wommack an additional bonus based upon extraordinary performance. There is currently no stock incentive plan or stock option plan in place with respect to any of our executive officers. Mr. Wommack receives typical benefits provided to executive level employees of Southwest. Mr. Wommack’s employment may terminate without cause, for good reason, in the event of his death or disability, and for cause. Upon termination by Mr. Wommack for good reason or by Southwest without cause, Mr. Wommack is entitled to receive his base salary for three years, plus accrued vacation and other amounts required to be paid or provided to the executive under any Southwest policy or program, and all accrued compensation and unreimbursed expenses.

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We have entered into an employment agreement with Bill E. Coggin, retaining him as our Vice President and Chief Financial Officer. The agreement, the term of which ends on September 30, 2005, provides for a base salary for Mr. Coggin of $225,000 per year. The Board intends to establish a bonus plan for Mr. Coggin based upon his annual performance, which bonus may be up to 50% of Mr. Coggin’s base salary. The Board also has discretion to pay Mr. Coggin an additional bonus based upon extraordinary performance. There is currently no stock incentive plan or stock option plan in place with respect to any of our executive officers. Mr. Coggin receives typical benefits provided to executive level employees of Southwest. Mr. Coggin’s employment may terminate without cause, for good reason, in the event of his death or disability, and for cause. Upon a termination by Mr. Coggin for good reason or by Southwest without cause, Mr. Coggin is entitled to receive his base salary for three years plus accrued vacation and other amounts required to be paid or provided to the executive under any Southwest policy or program, and all accrued compensation and unreimbursed expenses.

We have entered into an employment agreement with J. Steven Person, retaining him as our Vice President, Marketing. The agreement, the term of which ends on September 30, 2005, provides for a base salary for Mr. Person of $180,000 per year. The Board intends to establish a bonus plan for Mr. Person based upon his annual performance, which bonus may be up to 50% of Mr. Person’s base salary. The Board also has discretion to pay Mr. Person an additional bonus based upon extraordinary performance. There is currently no stock incentive plan or stock option plan in place with respect to any of our executive officers. Mr. Person receives typical benefits provided to executive level employees of Southwest. Mr. Person’s employment may terminate without cause, for good reason, in the event of his death or disability, and for cause. Upon a termination by Mr. Person for good reason or by Southwest without cause, Mr. Person is entitled to receive his base salary for three years plus accrued vacation and other amounts required to be paid or provided to the executive under any Southwest policy or program, and all accrued compensation and unreimbursed expenses.

We have entered into severance compensation agreements with R. Douglas Keathley, our Vice President, Operations, and John P. Tate, our Vice President, Land. Under the terms of these agreements, we agreed to continue to employ these executives in their current positions. The initial terms of the agreements ended on December 7, 2000 but have been automatically extended for successive one year periods. In the event of a change-in-control (as defined below), the terms of the agreements are automatically extended until the earlier of (i) one year from the date of the change in control or (ii) termination by the executive, or their death, notice of termination due to a disability, or their retirement.

In the event of a change in control and a subsequent termination of Mr. Keathley or Mr. Tate, as the case may be (other than termination by Mr. Keathley or Mr. Tate other than for good reason, by us for good cause or because of a disability, death or retirement), we must pay to the executive the following severance, in a lump sum: (i) full base salary through the date of termination, (ii) one year’s base salary and (iii) a target bonus under any cash plan adopted under our management incentive compensation program. Additionally, we must (i) maintain all life insurance and health, death and disability programs in place at the time of termination; (ii) supply an executive car, if previously supplied, and financial counseling program for one year; (iii) pay all legal fees and expenses incurred by the executive as a result of such termination; and (iv) pay all excise and state and federal income taxes due in regards to any severance pay. Mr. Keathley and Mr. Tate are not required to mitigate amounts payable under the agreements by seeking other employment and the amounts payable to them under these agreements will not be reduced by any compensation they may earn from another employer after such termination.

“Change in control” is defined in the agreements as (i) the acquisition of 50% or more of the voting power of Southwest by any person or group of persons, (ii) the acquisition of 25% or more but less than 50% of the voting power of Southwest by any person or group of persons (excluding our officers and directors); (iii) a merger, consolidation, reorganization, recapitalization or similar transaction upon the consummation of which 50% or more of the voting power of the surviving corporation is held by persons other than our former stockholders; (iv) a sale of substantially all of our assets; or (v) a relocation of our principal office or of the executive, to a location more than 50 miles from our current principal office in Midland, Texas.

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These severance compensation agreements were triggered upon consummation of the Exchange Transaction. Accordingly, in the event of a termination of Messrs. Keathley or Tate for any reason described above prior to April 19, 2003, we must pay them their severance packages. Additionally, the terms of these agreements have been extended to April 19, 2003 from December 7, 2002 due to the change of control triggered by the Exchange Transaction.

Other than described above, none of our executive officers have employment contracts with us or compensatory plans or arrangements which would result from the resignation, retirement or any other termination of such executive officer’s employment with us or any of our subsidiaries or from a change in control or a change in such executive officer’s responsibilities following a change in control.

Board Compensation

Our directors are currently entitled to receive $25,000 per year for their services, payable in quarterly installments in advance of each quarter. The directors’ annual retainers are retroactive to April 1, 2002. In addition, our directors receive $500 per telephonic meeting and $1,500 per in-person meeting. The chairmen of the compensation and audit committees are entitled to additional retainers of $1,500 per year, also paid quarterly in advance. Committee members are entitled to $1,000 per committee meeting; provided, however, that no additional compensation is payable to committee members if committee meetings are held concurrently with Board meetings. There is no stock incentive plan or stock option plan in place with respect to our directors.

Compensation Decisions

Prior to the closing of the Exchange Transaction, our Chairman, President and Chief Executive Officer, H.H. Wommack, III, determined his compensation and the compensation of our executive officers. On May 24, 2002, our Board of Directors established a compensation committee consisting of Messrs. Williamson, Chapman and Rinehart.

Compensation Committee Interlocks and Insider Participation

Members of our compensation committee, which is comprised of Messrs. Williamson, Chapman and Rinehart, are not or ever have been officers or employees of Southwest. No executive officer of Southwest serves as a member of the board of directors or compensation committee of another entity that has one or more executive officers that serve as a member of our Board of Directors or our compensation committee.

MANAGEMENT OF SOUTHWEST CONSOLIDATED PARTNERSHIPS AND

SOUTHWEST MANAGED ASSETS

The directors of Southwest Consolidated Partnerships and Southwest Managed Assets are elected by Southwest, as the sole stockholder of each corporation. The executive officers of Southwest Consolidated Partnerships and Southwest Managed Assets are elected by the board of directors of each respective company. The following information sets forth the age, current position and office, and period of service of the directors and executive officers of Southwest Consolidated Partnerships and Southwest Managed Assets:

Name	Age	Position	Director/Officer Since
H.H. Wommack, III	46	Director, President	2002
Bill E. Coggin	48	Director, Treasurer and Secretary	2002

See “MANAGEMENT OF SOUTHWEST” for a complete description of the backgrounds, including business experience during the past five years, of Messrs. Wommack and Coggin.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On December 15, 1994, H.H. Wommack, III borrowed approximately $1.7 million on an unsecured basis from us for the purpose of purchasing a portion of our common stock held by a certain stockholder. In 1997, our common stock held by Mr. Wommack was exchanged for stock in our former parent SRH. The note held was amended on March 15, 1995 to include $35,225 of accrued but unpaid interest. The note carried a 6% interest rate and is being amortized over 30 years with payments of $5,500 semi-monthly. On April 19, 2002, we canceled Mr. Wommack’s note in exchange for 123,710 shares of SRH common stock beneficially owned by Mr. Wommack.

Mr. Wommack served as an additional general partner of substantially all of the limited partnerships sponsored by us since 1983. Effective December 31, 2001, Mr. Wommack sold his general partner interests in six partnerships for approximately $296,000. Mr. Wommack currently serves as an additional general partner in nine of the partnerships that we propose to include in the merger. Mr. Wommack, however, will assign to Southwest for no consideration these general partner interests prior to the consummation of the merger.

PRINCIPAL STOCKHOLDERS OF SOUTHWEST

The table below shows each person whom we know to own beneficially 5% or more of our common stock and Class A common stock, our only voting securities, and our non-voting special stock. As of September 30, 2002, we had outstanding 100,000 shares of common stock, 900,000 shares of Class A common stock, and 200,000 shares of special stock. Class A common stock and special stock are convertible into common stock as follows:

• Each issued and outstanding share of Class A common stock automatically will convert into one share of common stock (a) immediately prior to (i) the closing of a firm commitment underwritten initial public offering of our common stock, pursuant to an effective registration statement filed under the Securities Act of 1933, in which we receive at least $10.0 million in net proceeds or (ii) any other transaction in which our common stock becomes listed on a national securities exchange or authorized for quotation on an inter-dealer quotation system such as Nasdaq (National Market); or (b) immediately after H.H. Wommack, III (x) no longer directly or indirectly has beneficial ownership of 50% or more of our common stock and (y) resigns, is removed as or is otherwise no longer an executive officer of Southwest. For a more detailed discussion of the terms of the Class A common stock, see “DESCRIPTION OF OUR CAPITAL STOCK—Common Stock.”

• Each issued and outstanding share of special stock automatically will convert into one share of common stock if we pay in full the entire principal amount of our Senior Secured Notes due 2004, in cash, on or before October 19, 2003. For a more detailed discussion of the terms of the special stock, see “DESCRIPTION OF OUR CAPITAL STOCK—Series A Special Stock.”

SEC rules provide that the “beneficial ownership” of any stockholder includes shares currently owned as well as shares of capital stock which the named stockholder has the right to acquire beneficial ownership of within 60 days through the exercise of options, warrants or other rights. In the event the merger becomes effective and our shares of common stock become authorized to be quoted on Nasdaq (National Market), the shares of Class A common stock will automatically convert into shares of common stock. We do not expect that the shares of special stock will be converted into common stock within the 60 days following September 30, 2002. We have disclosed in the table, where appropriate, the effect that conversion of the Class A common stock or the special stock, or both, would have on the beneficial ownership of our common stock. Except as otherwise indicated, each stockholder listed in the table has sole voting and investment power as to the shares owned by that person.

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Title of Class	Name and Address of Beneficial Owner(1)	Beneficial Ownership(#)	Percent of Class(%)	Notes
Common stock(2)	Southwest Royalties Holdings, Inc.	100,000	100.0	(3	)
	H.H. Wommack, III	59,750	59.75	(4	)
Class A common stock	Franklin Mutual Advisers, LLC(5) 51 John F. Kennedy Parkway Short Hills, New Jersey 07078	322,248.7	35.81	(6	)
	Regiment Capital Advisors, LLC(7) 70 Federal Street 7th Floor Boston, Massachusetts 02110	121,501	13.50	(8	)
Special stock	Southwest Royalties Holdings, Inc.	200,000	100.0
	H.H. Wommack, III	119,500	59.75	(4	)

⁽¹⁾ If no address is given, the named individual’s business address is c/o Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701.

⁽²⁾ Beneficial ownership shown for our common stock assumes that neither the shares of Class A common stock nor the shares of special stock held by SRH have been converted into common stock.

⁽³⁾ The following table shows the number of shares of our common stock that would be beneficially owned by SRH, and the percentage of the shares of common stock that would be outstanding which SRH would own, (a) if the Class A common stock but not the special stock were converted into common stock, (b) if the special stock but not the Class A common stock were converted into common stock and (c) the Class A common stock and the special stock both were converted into common stock:

Class converted into common stock	Shares of common stock outstanding after conversion	Beneficial Ownership (#) (All directly held)	Percent of Class (%)
Class A common stock only	1,000,000	100,000	10.0
Special stock only	300,000	300,000	100.0
Class A common stock and special stock	1,200,000	300,000	25.0

If the Class A common stock but not the special stock were converted into common stock, SRH would own, directly, 100,000 shares of our common stock, or 10.0% of the shares of common stock that would be outstanding. If the special stock but not the Class A common stock were converted into common stock, SRH would own, directly, 300,000 shares of our common stock, or 100.0% of the shares of common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, SRH would own, directly, 300,000 shares of our common stock, or 25.0% of the shares of common stock that would be outstanding.

⁽⁴⁾ Mr. Wommack’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 642,587 shares of SRH common stock, or 60% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Class A common stock but not the special stock were converted into common stock, Mr. Wommack would own, indirectly, 59,750 shares of our common stock, or 6% of the shares of common stock that would be outstanding. If the special stock but not the Class A common stock were converted into common stock, Mr. Wommack would own, indirectly, 179,250 shares of our common stock, or 60% of the shares of common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, Mr. Wommack would own, indirectly, 179,250 shares of our common stock, or 15% of the shares of common stock that would be outstanding.

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⁽⁵⁾ Franklin Mutual Advisers, LLC (“FMA”), is an investment adviser registered under the Investment Advisers Act of 1940. One or more of FMA’s advisory clients collectively holds 322,248.7 shares of our Class A common stock. Pursuant to investment advisory agreements with its advisory clients, FMA has sole voting and investment power over the securities owned by its clients which FMA manages. FMA has no interest in dividends or proceeds from the sale of such securities and disclaims beneficial ownership of all the securities held by FMA’s advisory clients.

⁽⁶⁾ The following table shows the number of shares of our common stock that would be beneficially owned by FMA, and the percentage of the shares of common stock that would be outstanding which FMA would own, (a) if the Class A common stock but not the special stock were converted into common stock, and (b) if the Class A common stock and the special stock both were converted into common stock:

Class converted into common stock	Shares of common stock outstanding after conversion	Beneficial Ownership (#) (All directly held)	Percent of Class (%)
Class A common stock only	1,000,000	322,249	32
Class A common stock and special stock	1,200,000	322,249	27

If the Class A common stock but not the special stock were converted into common stock, FMA would beneficially own 322,249 shares of our common stock, or 32% of the shares of our common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, FMA would own 322,249 shares of our common stock, or 26% of the shares of our common stock that would be outstanding.

⁽⁷⁾ Regiment Capital Advisors, LLC (“RCA”) acts as investment manager for three institutional accounts which are the true beneficial owners of these securities. RCA disclaims beneficial ownership of all the securities held by its institutional accounts.

⁽⁸⁾ The following table shows the number of shares of our common stock that would be beneficially owned by RCA, and the percentage of the shares of common stock that would be outstanding which RCA would own, (a) if the Class A common stock but not the special stock were converted into common stock and (b) if the Class A common stock and the special stock both were converted into common stock:

Class converted into common stock	Shares of common stock outstanding after conversion	Beneficial Ownership (#) (All directly held)	Percent of Class (%)
Class A common stock only	1,000,000	121,501	12
Class A common stock and special stock	1,200,000	121,501	10

If the Class A common stock but not the special stock were converted into common stock, RCA would own 121,501 shares of our common stock, or 12% of the shares of our common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, RCA would own 121,501 shares of our common stock, or 10% of the shares of our common stock that would be outstanding.

The table below shows information regarding the pro forma ownership after completion of the merger by those known by us to be beneficial owners of more than 5% of our common stock and of our non-voting Series A special stock. Upon completion of the merger, all of our Series B special stock will be held in escrow; in the event such shares of Series B special stock convert into common stock, the common stock will thereafter be distributed to the limited partners. Upon consummation of the merger and in the event our shares of common stock are authorized for quotation on Nasdaq (National Market), all of our shares of Class A common stock will convert into common stock on a basis of one share of common stock for each share of Class A common stock issued and outstanding.

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Title of Class	Name and Address of Beneficial Owner(1)	Beneficial Ownership (#)	Percent of Class (%)
Common stock	Southwest Royalties Holdings, Inc.	100,000	5.92(2)
	H.H. Wommack, III	59,750	3.54(2)
	Franklin Mutual Advisers, LLC(3) 51 John F. Kennedy Parkway Short Hills, New Jersey 07078	322,248.7	19.09(2)
	Regiment Capital Advisors, LLC(4) 70 Federal Street 7th Floor Boston, Massachusetts 02110	121,501	7.20(2)
Series A special stock	Southwest Royalties Holdings, Inc.	200,000	100.00(5)
	H.H. Wommack, III	119,500	59.75(6)

⁽¹⁾ If no address is given, the named individual’s business address is c/o Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701.

⁽²⁾ Assumes 1,688,347 shares of common stock issued and outstanding upon consummation of the merger, including (a) 688,347 shares of common stock issued in the merger and (b) 900,000 shares of common stock that will be issued upon conversion of our shares of Class A common stock into common stock in the event our shares of common stock become authorized for quotation on Nasdaq (National Market). The number of shares of common stock does not include the shares of common stock issuable upon the conversion of our special stock held by SRH or upon conversion of our special stock to be issued into an escrow account in connection with the merger, which, upon such conversion, would be distributed to the former limited partners.

⁽³⁾ Franklin Mutual Advisers, LLC (“FMA”), is an investment adviser registered under the Investment Advisers Act of 1940. One or more of FMA’s advisory clients collectively holds 322,249 shares of our Class A common stock, which shares will convert on a one-for-one basis into our common stock upon consummation of the merger and in the event our common stock becomes authorized for quotation on Nasdaq (National Market). Pursuant to investment advisory agreements with its advisory clients, FMA has sole voting and investment power over the securities owned by its clients which FMA manages. FMA has no interest in dividends or proceeds from the sale of such securities and disclaims beneficial ownership of all the securities held by FMA’s advisory clients.

⁽⁴⁾ Regiment Capital Advisors, LLC acts as investment manager for three institutional accounts which are the true beneficial owners of the shares of Class A common stock, which shares will convert on a one-for-one basis into our common stock upon consummation of the merger and in the event our common stock becomes authorized for quotation on Nasdaq (National Market). Regiment Capital Advisors disclaims beneficial ownership of all the securities held by its institutional accounts.

⁽⁵⁾ Assumes 200,000 shares of Series A special stock are issued and outstanding. In the event our Series A and Series B special stock converted into common stock, SRH would own, indirectly, 300,000 shares of our common stock, or 15% of our shares of common stock that would be issued and outstanding.

⁽⁶⁾ Assumes 200,000 shares of Series A special stock are issued and outstanding. In the event our Series A and Series B special stock converted into common stock, Mr. Wommack would own, indirectly 179,250 shares of our common stock, or 9% of our shares of common stock that would be issued and outstanding.

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STOCK OWNERSHIP OF SOUTHWEST MANAGEMENT

The table below shows the amount of common stock and Class A common stock, our only voting securities, and our non-voting special stock, owned by each of our directors and executive officers, and by all executive officers and directors as a group. As of September 30, 2002, we had outstanding 100,000 shares of common stock, 900,000 shares of Class A common stock, and 200,000 shares of special stock. Class A common stock and special stock are convertible into common stock as follows:

• Each issued and outstanding share of Class A common stock automatically will convert into one share of common stock (a) immediately prior to (i) the closing of a firm commitment underwritten initial public offering of our common stock, pursuant to an effective registration statement filed under the Securities Act of 1933, in which we receive at least $10.0 million in net proceeds or (ii) any other transaction in which our common stock becomes listed on a national securities exchange or authorized for quotation on an inter-dealer quotation system such as Nasdaq (National Market); or (b) immediately after H.H. Wommack, III (x) no longer directly or indirectly has beneficial ownership of 50% or more of our common stock and (y) resigns, is removed as or is otherwise no longer an executive officer of our company. For a more detailed discussion of the terms of the Class A common stock, see “DESCRIPTION OF OUR CAPITAL STOCK—Class A Common Stock.”

• Each issued and outstanding share of special stock automatically will convert into one share of common stock if we pay in full the entire principal amount of our Senior Secured Notes due 2004, in cash, on or before October 19, 2003. For a more detailed discussion of the terms of the special stock, see “DESCRIPTION OF OUR CAPITAL STOCK—Series A Special Stock.”

SEC rules provide that the “beneficial ownership” of any stockholder includes shares currently owned as well as shares of capital stock which the named stockholder has the right to acquire beneficial ownership of within 60 days through the exercise of options, warrants or other rights. In the event the merger becomes effective and our shares of common stock become authorized to be quoted on Nasdaq (National Market), the shares of Class A common stock will automatically convert into shares of our common stock. We do not expect that the shares of special stock will be converted into common stock within the 60 days following September 30, 2002. We have disclosed in the table, where appropriate, the effect that conversion of the Class A common stock or the special stock, or both, would have on the beneficial ownership of our common stock. Except as otherwise indicated, each stockholder listed in the table has sole voting and investment power as to the shares owned by that person.

Name and Address of Beneficial Owner(1)	Title of Class	Beneficial Ownership (#)	Percent of Class (%)	Notes
James N. Chapman	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
Bill E. Coggin	Common stock	1,067	1.07	(2)(3)
	Class A common stock	—	—
	Special stock	2,135	1.07
R. Douglas Keathley	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
William P. Nicoletti	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
J. Steven Person	Common stock	47	*	(2)(4)
	Class A common stock	—	—
	Special stock	94	*

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Name and Address of Beneficial Owner(1)	Title of Class	Beneficial Ownership (#)	Percent of Class (%)	Notes
Joseph J. Radecki, Jr.	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
Richard D. Rinehart	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
Jon P. Tate	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
John M. White	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
Herbert C. Williamson	Common stock	—	—
	Class A common stock	—	—
	Special stock	—	—
H.H. Wommack, III	Common stock	59,750	59.75	(2)(5)
	Class A common stock	—	—
	Special stock	119,500	59.75
All directors and officers as a group (eleven persons)	Common stock	60,864	60.86	(2)(6)
	Class A common stock	—	—
	Special stock	121,728	60.86

* Less than 1%

⁽¹⁾ If no address is given, the named individual’s business address is c/o Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701.

⁽²⁾ Beneficial ownership shown for our common stock assumes that neither the shares of Class A common stock nor the shares of special stock have been converted into common stock.

⁽³⁾ Mr. Coggin’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 11,480 shares of SRH common stock, or 1% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Class A common stock but not the special stock were converted into common stock, Mr. Coggin would own, indirectly, 1,067 shares our common stock, or less than 1% of the shares of common stock that would be outstanding. If the special stock but not the Class A common stock were converted into common stock, Mr. Coggin would own, indirectly, 3,202 shares of our common stock, or 1% of the shares of common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, Mr. Coggin would own, indirectly, 3,202 shares of our common stock, or less than 1% of the shares of common stock that would be outstanding.

⁽⁴⁾ Mr. Person’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 500 shares of SRH common stock, or less than 1% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Class A common stock but not the special stock were converted into common stock, Mr. Person would own, indirectly, 47 shares of our common stock, or less than 1% of the shares of common stock that would be outstanding. If the special stock but not the Class A common stock were converted into common stock, Mr. Person would own, indirectly, 141 shares of our common stock, or less than 1% of the shares of common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, Mr. Person would own, indirectly, 141 shares of our common stock, or less than 1% of the shares of common stock that would be outstanding.

⁽⁵⁾ Mr. Wommack’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 642,587 shares of SRH common stock, or 59.75% of the

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1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Class A common stock but not the special stock were converted into common stock, Mr. Wommack would own, indirectly, 59,750 shares of our common stock, or 6% of the shares of common stock that would be outstanding. If the special stock but not the Class A common stock were converted into common stock, Mr. Wommack would own, indirectly, 179,250 shares of our common stock, or 60% of the shares of common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, Mr. Wommack would own, indirectly, 179,250 shares of our common stock, or 15% of the shares of common stock that would be outstanding.

⁽⁶⁾ Consists exclusively of indirect beneficial interest through ownership by all of our directors and officers of a total of 654,567 shares of SRH common stock, or 61% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Class A common stock but not the special stock were converted into common stock, our directors and officers would own, indirectly, 60,864 shares of our common stock, or 6% of the shares of common stock that would be outstanding. If the special stock but not the Class A common stock were converted into common stock, our directors and officers would own, indirectly, 182,592 shares of our common stock, or 61% of the shares of common stock that would be outstanding. If the Class A common stock and the special stock both were converted into common stock, our directors and officers would own, indirectly, 182,592 shares of our common stock, or 15% of the shares of common stock that would be outstanding.

The table below shows information regarding the pro forma ownership after completion of the merger by each of our directors and executive officers, and by all executive officers and directors as a group, of our common stock and our non-voting Series A special stock. In connection with the merger, we will issue 137,669 shares of Series B special stock to an escrow account, which shares are convertible into common stock on the basis of one share of common stock for each share of Series B special stock issued and outstanding. No officer or director, however, will own any shares of our Series B special stock upon completion of the merger. Upon consummation of the merger and in the event our shares of common stock are authorized for quotation on Nasdaq (National Market), all of our shares of Class A common stock will convert into common stock on a basis of one share of common stock for each share of Class A common stock issued and outstanding.

Name and Address of Beneficial Owner(1)	Title of Class	Beneficial Ownership (#)	Percent of Class (%)		Notes
James N. Chapman	Common stock	—	—
	Series A special stock	—	—
Bill E. Coggin	Common stock	1,067	*	(2)	(3)
	Series A special stock	2,135	1.07
R. Douglas Keathley	Common stock	—	—
	Series A special stock	—	—
William P. Nicoletti	Common stock	—	—
	Series A special stock	—	—
J. Steven Person	Common stock	47	*	(2)	(4)
	Series A special stock	94	*
Joseph J. Radecki, Jr.	Common stock	—	—
	Series A special stock	—	—
Richard D. Rinehart	Common stock	—	—
	Series A special stock	—	—
Jon P. Tate	Common stock	—	—
	Series A special stock	—	—
John M. White	Common stock	—	—
	Series A special stock	—	—
Herbert C. Williamson	Common stock	—	—
	Series A special stock	—	—
H.H. Wommack, III	Common stock	59,750	3.54	(2)	(5)
	Series A special stock	119,500	59.75
All directors and officers as a group	Common stock	60,864	3.60	(2)	(6)
(eleven persons)	Series A special stock	121,729	60.86

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* Less than 1%

⁽¹⁾ If no address is given, the named individual is an executive officer or director of Southwest, and his or her business address is c/o Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701.

⁽²⁾ Assumes 1,688,347 shares of common stock issued and outstanding upon consummation of the merger, including (a) 688,347 shares of common stock issued in the merger and (b) 900,000 shares of common stock that will be issued upon conversion of our shares of Class A common stock into common stock in the event our shares of common stock become authorized for quotation on Nasdaq (National Market). The number of shares of common stock does not include the shares of common stock issuable upon the conversion of special stock held by SRH or the conversion of special stock to be issued into an escrow account, which, upon such conversion, would be distributed to the former limited partners.

⁽³⁾ Mr. Coggin’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 11,480 shares of SRH common stock, or 1% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Series A and Series B special stock were converted into common stock, Mr. Coggin would own, indirectly, 3,202 shares of our common stock, or less than 1% of the shares of our common stock that would be outstanding.

⁽⁴⁾ Mr. Person’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 500 shares of SRH common stock, or less than 1% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Series A and Series B special stock were converted into common stock, Mr. Person would own, indirectly, 141 shares of our common stock, or less than 1% of the shares of our common stock that would be outstanding.

⁽⁵⁾ Mr. Wommack’s beneficial ownership of our common stock and of our special stock consists exclusively of indirect beneficial interest through ownership of 59,750 shares of SRH common stock, or 60% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Series A and Series B special stock were converted into common stock, Mr. Wommack would own, indirectly, 179,250 shares of our common stock, or 9% of the shares of our common stock that would be outstanding.

⁽⁶⁾ Consists exclusively of indirect beneficial interest through ownership by all of our directors and officers of a total of 654,567 shares of SRH common stock, or 61% of the 1,075,534 shares of the SRH common stock that were issued and outstanding as of September 30, 2002. If the Series A and Series B special stock were converted into common stock, our directors and officers would own, indirectly, 182,593 shares of our common stock, or 9% of the shares of our common stock that would be outstanding.

On March 5, 2002, we commenced an offer for $123.685 million aggregate principal amount of the 10½% Senior Notes, which represented all of the 10½% Senior Notes then outstanding, plus any interest accrued but not paid thereon, in exchange for $60.0 million of Senior Secured Notes due 2004 and 900,000 shares of our Class A common stock, which equals 90% of our outstanding voting capital stock. On April 19, 2002, our offer to exchange the 10½% Senior Notes expired, with holders of $114.815 million principal amount of the 10½% Senior Notes tendering their notes in exchange for our Senior Secured Notes due 2004 and Class A common stock. As of September 30, 2002, $8.87 million aggregate principal amount of the 10½% Senior Notes remained outstanding. Class A stockholders are currently entitled to elect six of the seven members of our Board of Directors.

There are no arrangements known to us, the operation of which may at a subsequent date result in a change in control of Southwest.

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DESCRIPTION OF OUR CAPITAL STOCK

The following description is a summary of the material terms of our shares of capital stock and certain applicable provisions of our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws and is subject to, and qualified in its entirety by reference to, our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws, which are attached to the registration statement of which this prospectus/proxy statement is a part.

General

Our authorized capital stock currently consists of (a) 10,000,000 shares of common stock, par value $0.01 per share, (b) 900,000 shares of Class A common stock, $.01 par value per share, (c) 200,000 shares of special stock, $.01 par value per share, and (d) 5,000,000 shares of preferred stock, $1.00 par value per share. As of September 30, 2002, there was (w) one holder of record of our common stock and 100,000 shares of our common stock issued and outstanding, (x) 36 holders of record of our Class A common stock and 900,000 shares of our Class A common stock issued and outstanding, (y) one holder of record of our shares of special stock and 200,000 shares of our special stock issued and outstanding, and (z) no shares of our preferred stock issued and outstanding. The 900,000 shares of Class A common stock and 200,000 shares of special stock are convertible into common stock on a basis of one share of common stock for each share of Class A common stock or special stock, as the case may be, outstanding.

In connection with the merger, we plan to amend our Amended and Restated Certificate of Incorporation to designate the existing special stock as Series A special stock and to authorize 200,000 shares of Series B special stock. We will issue 137,669 shares of Series B special stock into an escrow account. In the event the Series A special stock converts into common stock, the Series B special stock will likewise convert into common stock on the basis of one share of common stock for each share of Series B special stock outstanding.

Common Stock

The holders of our shares of common stock are entitled to one vote for each share of common stock held on all matters voted upon by stockholders, except for rights with respect to the election of directors. See “—Board Representation” below. Subject to the rights of any then outstanding shares of preferred stock, the holders of common stock are entitled to share ratably with holders of our shares of Class A common stock in dividends as may be declared in the discretion of our Board of Directors out of funds legally available for the payment of dividends. We do not, however, expect to declare or pay dividends to holders of our common stock or Class A common stock in the foreseeable future. The holders of common stock are entitled to share ratably with the holders of our Class A common stock in our net assets upon liquidation after we pay or provide for all liabilities and for any preferential liquidation rights of any preferred stock then outstanding. The common stockholders have no preemptive rights to purchase shares of our stock. Shares of common stock are not subject to any redemption provisions and are not convertible into any of our other securities. All of the shares of common stock which we will issue in the merger will be fully paid and non assessable.

Our shares of Class A common stock will automatically convert into shares of our common stock upon the consummation of the merger and the authorization of our shares of common stock for quotation on Nasdaq (National Market). See “—Class A Common Stock” below. Upon such conversion, holders of common stock will become entitled to elect all seven directors, and directors will be elected by a plurality of the votes cast.

Class A Common Stock

We issued an aggregate 900,000 shares of our Class A common stock, which equal 90% of our issued voting share capital, in connection with the Exchange Transaction. Each share of Class A common stock has one vote on all matters on which stockholders are entitled or permitted to vote and has equivalent rights to the holders

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of common stock, except for rights with respect to the election of directors. Subject to preferences that may be applicable to any outstanding shares of preferred stock, the holders of Class A common stock are entitled to share ratably in dividends declared by our Board of Directors out of legally available funds with holders of shares of common stock. We do not, however, expect to declare or pay dividends to holders of our Class A common stock or common stock in the foreseeable future. Upon liquidation or dissolution, subject to preferences that may be applicable to an outstanding share of preferred stock, the holders of Class A common stock are entitled to share ratably in all assets available for distribution to holders of the shares of Class A common stock and holders of common stock. All of the outstanding shares of Class A common stock are fully paid and non assessable.

We issued the Class A common stock without registering them under the Securities Act in reliance on an exemption thereto under Section 3(a)(9) of the Securities Act. Pursuant to SEC interpretations, the Class A common stock retained the status of the 10½% Senior Notes as being freely tradable under the Securities Act, except by persons who are considered our affiliates or persons who hold Class A common stock that were previously held by our affiliates.

The shares of Class A common stock will automatically convert into shares of common stock on the basis of one share of common stock for each Class A common stock issued and outstanding (a) immediately prior to (i) the closing of a firm commitment underwritten initial public offering of at least $10.0 million in net proceeds of our common stock, pursuant to an effective registration statement filed under the Securities Act, or (ii) any other transaction pursuant to which our common stock becomes listed on a national securities exchange or authorized for quotation on an inter-dealer quotation system or (b) immediately after H.H. Wommack, III (a) no longer directly or indirectly has beneficial ownership of 50% or more of our common stock, and (b) resigns, is removed as or is otherwise no longer an executive officer of our company.

The shares of Class A common stock are not be listed on any national securities exchange or authorized to be quoted on any inter-dealer quotation system of any national securities association, and we do not currently intend to apply for such listing or quotation with respect to the Class A common stock; however, in connection with the merger, we have applied for quotation with respect to our common stock, and, in connection with such listing or quotation, all shares of Class A common stock will automatically convert into common stock.

Series A Special Stock held by SRH

In connection with the Exchange Transaction, we issued to our then sole stockholder SRH 200,000 shares of special stock. Combined with the 100,000 shares of common stock held by SRH upon consummation of the Exchange Transaction, SRH owns 25% of our issued and outstanding share capital but only 10% of our voting share capital.

The shares of special stock have no voting rights, no rights to receive dividends from us and no rights to participate in any liquidation or dissolution of Southwest.

If, prior to or on October 19, 2003, we pay in cash in full the Senior Secured Notes, the shares of special stock will automatically on the date of such payment be converted into shares of common stock, on the basis of one share of common stock per share of special stock issued and outstanding. In the event the shares of special stock convert into common stock, SRH would own 25% of our issued and outstanding voting share capital. If, prior to or on October 19, 2003, we either (i) fail to pay in cash in full the Senior Secured Notes or (ii) there is a voluntary or involuntary bankruptcy filing by or against Southwest, then, upon the earlier of such event, the shares of special stock shall be deemed canceled, shall be null and void and of no further effect. Upon the cancellation of the shares of special stock, SRH would own only 10% of our issued and outstanding voting share capital.

In connection with the merger, we will file an amendment to our Amended and Restated Certificate of Incorporation designating the special stock held by SRH as Series A special stock.

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Series B Special Stock to be issued in the Merger

In connection with the merger, we will issue, in addition to our common stock, shares of Series B special stock, which will be held in escrow and, in the event the Series B special stock converts into common stock, such common stock will be distributed to the former limited partners. The shares of Series B special stock will have no voting rights, no rights to receive dividends from us and no rights to participate in any liquidation or dissolution of Southwest.

If, prior to or on October 19, 2003, we pay in cash in full the Senior Secured Notes and the 200,000 shares of Series A special stock convert into shares of common stock, then the 137,669 shares of Series B special stock will likewise convert into common stock on a basis of one share of common stock per share of Series B special stock issued and outstanding. If, however, prior to or on October 19, 2003, we either (i) fail to pay in cash in full the Senior Secured Notes or (ii) there is a voluntary or involuntary bankruptcy filing by or against Southwest, and therefore the shares of Series A special stock are deemed canceled, are null and void and of no further effect in accordance with their terms, then, likewise, the Series B special stock shall be deemed canceled, shall be null and void and of no further effect.

The purpose of issuing the shares of Series B special stock into escrow and distributing the common stock to the limited partners upon conversion of the Series B special stock into common stock is to protect the limited partners from share dilution in the event our shares of Series A special stock convert into common stock. There are 200,000 shares of Series A special stock currently outstanding, which, on an as-converted basis, represent 15% of our issued and outstanding share capital. See “—Series A Special Stock Held by SRH” above for a description of the Series A special stock, including the circumstances under which the Series A special stock will convert into common stock. In the event the Series A special stock were to convert into common stock, without the simultaneous conversion of the Series B special stock, the shares of common stock to be received by the limited partners in the merger would be diluted. The issuance and conversion of the Series B special stock will allow the limited partners to maintain their equity ownership percentage in Southwest upon conversion of Series A special stock.

Preferred Stock

Our Board of Directors has the authority, without further action by our stockholders, to issue shares of undesignated preferred stock from time to time in one or more series and to fix the related number of shares and the designations, voting powers, preferences, and other rights, and restrictions or qualifications of that preferred stock. The rights, preferences, privileges and restrictions or qualifications of different series of preferred stock may differ with respect to dividend rates, amounts payable on liquidation, voting rights, conversion rights, redemption provisions, sinking fund provisions and other matters. The issuance of preferred stock could:

• decrease the amount of earnings and assets available for distribution to holders of common stock and Class A common stock;

• adversely affect the rights and powers, including voting rights, of holders of common stock and Class A common stock; and

• have the effect of delaying, deferring or preventing a change in control of Southwest.

Board Representation

The Board of Directors is composed of seven members. While any shares of Class A common stock remain outstanding, the beneficial owners of the shares of Class A common stock are entitled to elect six of seven total members to our Board of Directors in accordance with the terms of our Amended and Restated Certificate of Incorporation. The remaining director is appointed by our common stockholders.

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Any vacancy occurring in the Board of Directors by reason of the death, resignation, retirement, disqualification or removal from office of any director elected by the holders of the Class A common stock must be filled by those remaining directors that were elected by the holders of Class A common stock. Any vacancy occurring in our Board of Directors by reason of the death, resignation, retirement, disqualification or removal from office of any director elected by the holder of common stock must be filled by the holder of our shares of common stock. Each director elected to fill a vacancy shall serve until the expiration of the term of his predecessor or, if there is no predecessor, until the next succeeding annual meeting and thereafter until his successor shall be duly elected and qualified, unless sooner displaced from office by resignation, removal or otherwise.

Any director or the entire Board of Directors may be removed at any time, but only by the affirmative vote of the holders of two-thirds of the outstanding shares of our capital stock entitled to elect such director cast at a meeting of the stockholders called for that purpose; provided, however, that within 120 days after H.H. Wommack, III (a) no longer directly or indirectly has beneficial ownership of 50% or more of our common stock and (b) resigns, is removed or otherwise no longer serves as an executive officer, then the shares of Class A common stock will automatically convert to common stock and any director or the entire Board of Directors may be removed with or without cause by a majority of the outstanding shares of our capital stock entitled to vote generally in the election of directors (considered for this purpose as a single class).

In connection with the consummation of the merger and in the event our shares of common stock are authorized for quotation on Nasdaq (National Market), the shares of Class A common stock will automatically convert into common stock and the provisions in our Amended and Restated Certificate of Incorporation relating to Board representation will cease to be effective. Upon the conversion of the shares of Class A common stock into common stock, directors will be elected by a plurality of the votes cast and may be removed with or without cause by a majority of the shares of our common stock.

Stockholders Agreement

In connection with the Exchange Transaction, we entered into a Stockholders Agreement with SRH, H.H. Wommack, III and the holders of our shares of Class A common stock. The Stockholders Agreement (i) provides the holders of shares of Class A common stock a right of first refusal for shares of common stock or special stock held by SRH, (ii) grants tag-along rights to SRH which permit SRH to sell a pro rata percentage of its common stock and/or special stock if the holders of shares of Class A common stock collectively transfer a majority of their shares of Class A common stock, and (iii) grants co-sale rights to the holders of shares of Class A common stock whereby holders of shares of Class A common stock desiring to sell collectively a majority of their Class A common stock may require SRH to sell a pro rata percentage of its common stock and/or special stock in connection with such sale. The Stockholders Agreement is attached hereto as an exhibit to the registration statement of which this prospectus/proxy statement is a part.

Upon the consummation of the merger and in the event our shares of common stock become authorized for quotation on Nasdaq (National Market), the shares of Class A common stock will convert into common stock and the Stockholders Agreement will terminate and cease to be in force and effect.

Limitation on Director’s Liability and Indemnification of Directors

Our Amended and Restated Certificate of Incorporation provides that no director of Southwest shall be personally liable to Southwest or any of its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director’s duty of loyalty to Southwest or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the General Corporation Law of the State of Delaware, or (iv) for any transaction from which the director derived an improper personal benefit.

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Our Amended and Restated Certificate of Incorporation contain provisions that allow for the indemnification of directors, officers and controlling persons of Southwest to the fullest extent permitted under Delaware law.

Transfer Agent and Registrar

Upon consummation of the merger, the transfer agent and registrar for our common stock will be American Stock Transfer & Trust Company. The transfer agent and registrar for our Class A common stock is currently American Stock Transfer & Trust Company.

Anti-Takeover Effect of Delaware Law and our Amended and Restated Certificate of Incorporation and By-Law Provisions

Provisions in our Amended and Restated Certificate of Incorporation and Bylaws and Delaware law could make it more difficult for someone to acquire Southwest through a tender offer, proxy contest or otherwise. Upon consummation of the merger and in the event our shares of common stock become authorized for quotation on Nasdaq (National Market), Southwest will be governed by the provisions of Section 203 of the DGCL, which provides that a person who owns (or within 3 years, did own) 15% or more of a company’s voting stock is an “interested stockholder.” Section 203 prohibits a public Delaware corporation from engaging in a business combination with an interested stockholder for a period commencing 3 years from the date in which the person became an interested stockholder unless:

• the Board of Directors approved the transaction that resulted in the stockholder becoming an interested stockholder;

• upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation (excluding shares owned by officers, directors, or certain employee stock purchase plans); or

• at or subsequent to the time the transaction is approved by the Board of Directors, there is an affirmative vote of at least two-thirds of the outstanding voting stock.

Section 203 could prohibit or delay mergers or other takeover attempt against Southwest and, accordingly, may discourage attempts to acquire it through tender offer, proxy contest or otherwise.

Our Amended and Restated Certificate of Incorporation and Bylaws include certain provisions that could delay, deter or prevent a future takeover or acquisition of Southwest unless such takeover or acquisition is approved by the Board of Directors.

Our Amended and Restated Certificate of Incorporation provides for 5,000,000 authorized shares of preferred stock. The existence of authorized but unissued shares of preferred stock may enable our Board of Directors to render more difficult or to discourage an attempt to obtain control of Southwest by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, our Board of Directors were to determine that a takeover proposal is not in the best interests of Southwest, the Board of Directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquiror or insurgent stockholder or stockholder group. In this regard, the Amended and Restated Certificate of Incorporation grants our Board of Directors broad power to establish the rights and preferences of authorized and unissued shares of preferred stock. The issuance of shares of preferred stock could decrease the amount of earnings and assets available for distribution to holders of shares of common stock. The issuance may also adversely affect the rights and powers, including voting rights, of those holders and may have the effect of delaying, deterring or preventing a change in control of Southwest.

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Our Amended and Restated Bylaws establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of stockholders of Southwest. These procedures provide that notice of stockholder proposals of these kinds must be timely given in writing to the Secretary of Southwest before the meeting at which the action is to be taken. Generally, to be timely, notice must be received at the principal executive officers of Southwest not less than 45 days nor more than 90 days before the first anniversary date of the annual meeting for the preceding year. The notice must contain certain information specified in the Amended and Restated Bylaws.

DESCRIPTION OF CAPITAL STOCK OF SOUTHWEST CONSOLIDATED PARTNERSHIPS

The following description is a summary of the material terms of the Southwest Consolidated Partnerships’ common stock and certain applicable provisions of its Certificate of Incorporation and Bylaws and is subject to, and qualified in its entirety by reference to, the Certificate of Incorporation and Bylaws, each of which are attached to the registration statement of which this prospectus/proxy statement is a part.

General

Southwest Consolidated Partnerships’ authorized capital stock includes 1,000 shares of common stock, par value $0.01 per share. As of September 30, 2002, there was one stockholder of record of Southwest Consolidated Partnerships’ common stock, Southwest, and 100 shares of Southwest Consolidated Partnerships common stock outstanding. Upon the consummation of the merger of the partnerships with and into Southwest Consolidated Partnerships, the 1,000 shares of Southwest Consolidated Partnerships common stock held by Southwest will be cancelled. The limited partners who participate in the merger will collectively own 100% of Southwest Consolidated Partnerships’ common stock.

The holders of common stock are entitled to one vote for each share of common stock held on all matters voted upon by stockholders, including the election of directors. Subject to the rights of any then outstanding shares of preferred stock, the holders of common stock are entitled to dividends as may be declared in the discretion of the Board of Directors out of funds legally available for the payment of dividends. The holders of common stock are entitled to share ratably in the net assets upon liquidation after Southwest Consolidated Partnerships pays or provides for all liabilities and for any preferential liquidation rights of any preferred stock then outstanding. The common stockholders have no preemptive rights to purchase shares of Southwest Consolidated Partnerships’ stock. Shares of Southwest Consolidated Partnerships’ common stock are not subject to any redemption provisions and are not convertible into any other securities. All of the shares of common stock which Southwest Consolidated Partnerships will issue to the limited partners in the merger will be fully paid and nonassessable.

Limitation on Director’s Liability

Southwest Consolidated Partnerships’ Certificate of Incorporation provides that no director of Southwest Consolidated Partnerships shall be personally liable to Southwest Consolidated Partnerships or any of its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director’s duty of loyalty to Southwest Consolidated Partnerships or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the General Corporation Law of the State of Delaware, or (iv) for any transaction from which the director derived an improper personal benefit.

Southwest Consolidated Partnerships’ Certificate of Incorporation contain provisions that allow for the indemnification of directors, officers and controlling persons of Southwest Consolidated Partnerships to the fullest extent permitted under Delaware law.

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COMPARISON OF RIGHTS OF SOUTHWEST STOCKHOLDERS AND

THE PARTNERSHIPS’ LIMITED PARTNERS

General

The rights of our stockholders are currently governed by the Delaware General Corporation Law and our Amended and Restated Certificate of Incorporation and Bylaws. The rights of the limited partners of each partnership are currently governed by either the Delaware Revised Uniform Limited Partnership Act or the Tennessee Uniform Limited Partnership Act and, in either case, the partnership agreement of each partnership. Accordingly, upon completion of the merger of each partnership, the rights of our stockholders and of limited partners who become our stockholders in the merger of their partnerships will be governed by the Delaware General Corporation Law and our Amended and Restated Certificate of Incorporation and Bylaws. Copies of our Amended and Restated Certificate of Incorporation and Bylaws are included as exhibits to the registration statement of which this prospectus/proxy statement is a part. The partnership agreement for each partnership in which you own an interest will be sent to you upon request. For information on how these documents may be obtained, see “WHERE YOU CAN FIND MORE INFORMATION.”

The following is a summary of the material differences between the current rights of our stockholders and those of the limited partners in each partnership. The rights and duties of the limited partners in the partnerships summarized below are the same for each of the partnerships, except as otherwise noted.

Distributions and Dividends

Southwest Royalties, Inc.	Southwest Royalties, Inc. Income Fund V, L.P.; Southwest Royalties, Inc. Income Fund VI, L.P.; Southwest Oil & Gas Income Fund VII-A, L.P.; Southwest Royalties Institutional Income Fund VII-B, L.P.; Southwest Oil & Gas Income Fund VIII- A, L.P.; Southwest Royalties Institutional Income Fund VIII-B, L.P.; Southwest Oil & Gas Income Fund IX-A, L.P.; Southwest Royalties Institutional Income Fund IX- B, L.P.; Southwest Oil & Gas Income Fund X-A, L.P.; Southwest Royalties Institutional Income Fund X- B, L.P.; Southwest Oil & Gas Income Fund X-C, L.P.; Southwest Royalties Institutional Income Fund X-C, L.P.	Southwest Developmental Drilling Fund 91-A, L.P.; Southwest Developmental Drilling Fund 92-A, L.P.; Southwest Developmental Drilling Fund, 1993, L.P.; Southwest Developmental Drilling Fund, 1994, L.P.	Southwest Partners, L.P.; Southwest Combination Income/Drilling Program 1988, L.P.; Southwest Developmental Drilling Fund 1990, L.P.
Subject to covenants in our debt instruments, our Board of Directors may declare dividends or distributions upon or in respect to our Class A common stock, if outstanding, and common stock, to be payable in cash, in other property or in securities, as the Board of Directors may at any time deem advisable. Our current policy is to retain our future earnings to finance the expansion and continuing development of our	Net profits and losses of these partnerships are allocated 10% to us in our capacity as general partner (except that for Southwest Royalties Institutional Income Fund IX-A, L.P., Southwest Royalties Institutional Income Fund IX-B, L.P., Southwest Oil & Gas Income Fund X-A, L.P., Southwest Royalties Institutional Income Fund X-A, L.P., Southwest Oil & Gas Income Fund X-B, L.P., Southwest Royalties	Net profits and losses of these partnerships are allocated 11% to us in our capacity as general partner and 89% to the limited partners, in proportion to respective capital contributions. We, in our sole and absolute discretion, review the revenues received, the costs and expenses incurred and the partnerships’ future cash requirements on a quarterly basis and determine	Net profits and losses of these partnerships are allocated 15% to us in our capacity as general partner (except that for Southwest Combination Income/Drilling Program 1988, allocations to general partners are 14% to us and 1% to H.H. Wommack, III, as an additional general partner) and 85% to the limited partners, in proportion to their respective capital contributions.

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Southwest Royalties, Inc.	Southwest Royalties, Inc. Income Fund V, L.P.; Southwest Royalties, Inc. Income Fund VI, L.P.; Southwest Oil & Gas Income Fund VII-A, L.P.; Southwest Royalties Institutional Income Fund VII-B, L.P.; Southwest Oil & Gas Income Fund VIII- A, L.P.; Southwest Royalties Institutional Income Fund VIII-B, L.P.; Southwest Oil & Gas Income Fund IX-A, L.P.; Southwest Royalties Institutional Income Fund IX- B, L.P.; Southwest Oil & Gas Income Fund X-A, L.P.; Southwest Royalties Institutional Income Fund X- B, L.P.; Southwest Oil & Gas Income Fund X-C, L.P.; Southwest Royalties Institutional Income Fund X-C, L.P.	Southwest Developmental Drilling Fund 91-A, L.P.; Southwest Developmental Drilling Fund 92-A, L.P.; Southwest Developmental Drilling Fund, 1993, L.P.; Southwest Developmental Drilling Fund, 1994, L.P.	Southwest Partners, L.P.; Southwest Combination Income/Drilling Program 1988, L.P.; Southwest Developmental Drilling Fund 1990, L.P.
business. We have never paid cash dividends on our common stock or Class A common stock and do not anticipate paying cash dividends in the foreseeable future. See “RISK FACTORS.” The future payment of dividends will depend upon our earnings, capital requirements, and financial position, future loan covenants, general economic conditions and other relevant factors. In addition, there are several restrictions on our ability to pay dividends, including certain restrictive provisions in the Indenture with respect to our Senior Secured Notes due 2004 and a restrictive covenant in our Credit Agreement with Union Bank, as administrative agent for our senior lenders. These requirements work together to effectively prohibit the payment of cash dividends on our common stock. This means that as a holder of our common stock, you will no longer receive quarterly cash distributions.	Institutional Income Fund X-B, L.P., Southwest Oil & Gas Income Fund X-C, L.P., and Southwest Royalties Institutional Income Fund X-C, L.P., general partner allocations are 9% to us and 1% to H.H. Wommack, III in his capacity as an additional general partner) and 90% to the limited partners, in proportion to respective capital contributions. We, in our sole and absolute discretion, review the revenues received, the costs and expenses incurred and the partnerships’ future cash requirements on a quarterly basis and determine whether any funds are available for distribution. Distributions, if any, are allocated to limited partners in proportion to their respective share of the partnership’s net revenues for such month based on capital contributions.	whether any funds are available for distribution. Distributions, if any, are allocated to limited partners in proportion to their respective share of the partnership’s net revenues for such month based on capital contributions.	We, in our sole and absolute discretion, review the revenues received, the costs and expenses incurred and the partnerships’ future cash requirements on a quarterly basis and determine whether any funds are available for distribution. Distributions, if any, are allocated to limited partners in proportion to their respective share of the partnership’s net revenues for such month based on capital contributions.

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Terms of Conversion and Redemption

Neither the limited partner interests nor our common stock is convertible or redeemable.

Voting Rights

Southwest Royalties, Inc.	Southwest Royalties Income Fund V, L.P.; Southwest Royalties, Inc. Income Fund VI, L.P.	Southwest Partners, L.P.	All other Partnerships
Each share of our common stock entitles its holder to cast one vote for each share he holds on any matter voting upon by stockholders, except for rights with respect to the election of directors. Currently, so long as any shares of Class A common stock remain outstanding, the holders of our Class A common stock are entitled to elect six of seven total members to our Board of Directors. The remaining director is elected by our common stockholders. Upon consummation of the merger and in the event our shares of common stock become authorized for quotation on Nasdaq (National Market), however, the Class A common stock will automatically convert into common stock. All directors will then be elected by a plurality of the votes cast, with common stock being the only class of outstanding securities entitled to vote in the election of directors. Our Amended and Restated Bylaws establish advance notice procedures with regard to stockholder proposals. See “DESCRIPTION OF OUR CAPITAL STOCK—Anti-takeover Effects of Delaware Laws and for Amended and Restated Certificate of Incorporation and Bylaw Provisions.”	Each holder of limited partner interests is entitled to vote on the following matters: • any matter required by the Tennessee Uniform Limited Partnership Act; • calling a meeting of the limited partners; • removing a general partner and electing a new general partner; • amending the partnership agreement and the partnership’s certificate of limited partnership; • dissolving and winding up the partnership; • approving or disapproving any sale of all or substantially all of the assets of the partnership; and • terminating, upon thirty (30) days written notice to the general partner, any contract entered into between the partnership and the general partner or its affiliates. The rights described above may be exercised by a majority in interest of limited partners, except that 10% in interest of the limited partners shall have the right to call a meeting and the unanimous consent of the limited partners is required to amend the partnership agreement or certificate of partnership if the amendment would increase the liability of the	Each limited partner interest entitles its holder to cast one vote on the following matters: • any matter as to which voting is required by the Delaware Revised Uniform Limited Partnership Act, including the right to vote on a merger; • limited partners holding in the aggregate 20% of the limited partner interests may propose an amendment to the partnership agreement; • limited partners may vote on any proposed amendment, and a proposed amendment is considered adopted if it receives the affirmative vote of the general partner and a majority in interest of the general partner and limited partners; and • any group of limited partners which owns 20% of the limited partner interests may call a meeting. The limited partners do not have the right to participate in the management or control of the partnership or its business affairs or to act or bind the partnership in any way.	Each holder of limited partner interests is entitled to vote on the following matters: • any matter required by the Delaware Revised Uniform Limited Partnership Act; • calling a meeting of the limited partners; • removing a general partner and electing a new general partner; • amending the partnership agreement and the partnership’s certificate of limited partnership; • dissolving and winding up the partnership; • approving or disapproving any sale of all or substantially all of the assets of the partnership; and • terminating, upon thirty (30) days written notice to the general partner, any contract entered into between the partnership and the general partner or its affiliates. The rights just described above may be exercised by a majority in interest of limited partners, except that 10% in interest of the limited partners shall have the right to call a meeting and the unanimous consent of the partners is required to amend the partnership agreement or certificate of limited partnership if the amendment would

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Southwest Royalties, Inc.	Southwest Royalties Income Fund V, L.P.; Southwest Royalties, Inc. Income Fund VI, L.P.	Southwest Partners, L.P.	All other Partnerships
	partners, or change the contributions required of the limited partners, their rights and interests in profits and losses or their rights upon liquidation. The limited partners do not have the right to do the following: 1.     participate in the control of the business; 2.     have any voice in the management or operation of the partnership property; and 3.     have the authority to act as agent on behalf of the partnership, do any act which is binding on the partnership or incur expenditures on behalf of the partnership.		increase the liability of the partners, or change the contributions required of the limited partners, their rights and interests in profits and losses or their rights upon liquidation. The limited partners do not have the right to do the following: 1.     participate in the control of the business; 2.     have any voice in the management or operation of the partnership property; 3.     have the authority to act as agent on behalf of the partnership, do any act which is binding on the partnership or incur expenditures on behalf of the partnership.

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Liquidation Rights

Southwest Royalties, Inc.	Southwest Royalties, Inc. Income Fund V, L.P.; Southwest Royalties, Inc. Income Fund VI, L.P.; Southwest Oil & Gas Income Fund VII-A, L.P.; Southwest Royalties Institutional Income Fund VII-B, L.P.; Southwest Oil & Gas Income Fund VIII-A, L.P.; and Southwest Royalties Institutional Income Fund VIII-B, L.P.	Southwest Partners, L.P.	All other Partnerships
In the event of liquidation, dissolution or winding up of Southwest, the holders of our common stock are entitled to share ratably with the holders of our Class A common stock in the net assets of Southwest remaining after creditors have been paid or provided for, and after provision for any liquidation preferences on any outstanding class or series of preferred stock. Upon consummation of the merger and in the event our common stock becomes authorized for quotation on Nasdaq (National Market), our Class A common stock will automatically convert into common stock and will, thus, no longer be outstanding.	Upon liquidation of these partnerships, limited partners are entitled to share in any assets available for distribution after paying off liabilities and providing cash reserves.	Upon liquidation, partnership property shall be liquidated and distributed in the following order: First, to the payment and discharge of all of the partnership’s debts and liabilities to creditors, including creditors who are also limited partners, other than the general partner; Second, to the payment and discharge of all of the partnership’s debts and liabilities to the general partner; and The balance, if any, to the general partner and limited partners in accordance with their capital accounts, after giving effect to all contributions, distributions, and allocations for all periods.	The net proceeds available for distribution upon liquidation of the partnerships shall be distributed by the managing general partner or the liquidating trustee in the following order of priority: • to third party creditors in payment of any indebtedness owning to them; • to the creation of any reserves deemed necessary or prudent by the general partners, to cover contingent liabilities of the partnership; • to the managing general partner or other general or limited partners in payment of any claims or indebtedness owed to the managing general partner or such other general or limited partners; • to the general and limited partners in proportion to their positive balances in their capital accounts; and • any remaining proceeds shall be distributed 90% to the limited partners and 10% to the general partners.

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Assessments and Limited Liability

Southwest Royalties, Inc.

All Partnerships

Shares of our common stock issued in the merger will be fully paid and nonassessable. Our stockholders generally will not have personal liability for obligations of Southwest.

Under the terms of the partnership agreements, the holders of limited partner interests are not subject to additional assessments. The liability of holders of limited partner interests with respect to the activities of the partnerships is generally limited to their original capital contribution and additional capital contributions, and their share of assets and undistributed profits. In certain circumstances, they may be liable for the amount of any capital distributed or returned to them.

Right of Presentment; Right of First Refusal

Southwest Royalties, Inc.	Southwest Royalties, Inc. Income Fund V, L.P.; Southwest Royalties, Inc. Income Fund VI, L.P.; Southwest Oil & Gas Income Fund VII-A, L.P.; Southwest Royalties Institutional Income Fund VII- B, L.P.; Southwest Oil & Gas Income Fund VIII-A, L.P.; and Southwest Royalties Institutional Income Fund VIII-B, L.P.	All other Partnerships
There is no right of presentment or right of first refusal applicable to the shares of our common stock that will be issued in the merger.	In the event that a limited partner requests that we, as general partner, purchase his interests, we are obligated to offer to purchase the interests for cash. The partnership agreements provide that the purchase price will be based primarily on the present worth of the limited partners’ oil and gas interests based on reports of engineering consultants. Our obligation to purchase interests in any one year is limited to an expenditure of 10% of the initial partnership capital, in addition to a balance sheet requirement that there be sufficient property in the partnership to cover liabilities. We are entitled to a first right of refusal in the event that a limited partner receives a bona fide offer to purchase his interests.	A limited partner who receives a bona fide offer to purchase all or any portion of his interests which he desires to accept is required to offer his interests to us for repurchase. We are not required to purchase the interests offered to us. If we fail to exercise our right of first refusal in the allotted time, the limited partner may sell the interests to the original offeror on the same terms as the proposed sale.

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Transferability

Southwest Royalties, Inc.	All Partnerships
Other than as required by applicable federal or state securities laws, our common stock will be freely transferable.	The limited partners interests are not freely transferable. The rights of the limited partners to transfer their partnership interests are limited as follows: • Notice must be given to the general partner or general partners of the nature and terms of any intended transfer; and • The general partner has a right of first refusal with regard to the transfer of any of the partnership interests.

Statutory Anti-Takeover Provisions

Southwest Royalties, Inc.

All Partnerships

Upon consummation of the merger, we will be subject to the provisions of Section 203 of the Delaware General Corporation Law, which restricts “business combinations” involving a corporation and an “interested stockholder” for 3 years following the date on which the stockholder acquired 15% or more of the outstanding voting stock of the corporation unless certain statutory exceptions are satisfied. See “DESCRIPTION OF CAPITAL STOCK—Anti-Takeover Effect of Delaware Law and our Amended and Restated Certificate of Incorporation and Bylaws.”

There is no provision in the Delaware Revised Uniform Limited Partnership Act or the Tennessee Uniform Limited Partnership Act to which the partnerships are subject that is comparable to the provisions contained in Section 203 of the Delaware General Corporation Law.

Management

The business and affairs of Southwest and of all the partnerships are managed by or under the direction of our Board of Directors. The information provided in the section entitled “MANAGEMENT OF SOUTHWEST” section of this prospectus/proxy statement is applicable not only to Southwest but also to each of the partnerships.

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Continuity of Existence

Southwest Royalties, Inc.	Southwest Royalties, Inc. Oil & Gas Income Fund V, L.P.; Southwest Royalties, Inc.; Income Fund VI, L.P.	Southwest Oil & Gas Income Fund VII- A, L.P.; and Southwest Royalties Institutional Income Fund VII-B, L.P.
Subject to the provisions of the Delaware General Corporation Law providing for the dissolution of a Delaware corporation, our Amended and Restated Certificate of Incorporation and Bylaws provide for perpetual existence.	These partnerships must terminate their business and dissolve on December 31, 2036, unless dissolved earlier pursuant to the terms of their partnership agreements or the Tennessee Uniform Limited Partnership Act.	These partnerships must terminate their business and dissolve on December 31, 2037, unless dissolved earlier pursuant to the terms of their partnership agreements or the Delaware Revised Uniform Limited Partnership Act.

Southwest Oil & Gas Income Fund VIII- A, L.P.; Southwest Royalties Institutional Income Fund VIII-B, L.P.; Southwest Combination Income/Drilling Program 1988-I, L.P.	Southwest Oil & Gas Income Fund IX-A, L.P.; Southwest Royalties Institutional Income Fund IX-B, L.P.	Southwest Oil & Gas Income Fund X-A, L.P.; Southwest Oil & Gas Income Fund X-B, L.P.; Southwest Oil & Gas Income Fund X-C, L.P.; Southwest Royalties Institutional Income Fund X-A, L.P.; Southwest Royalties Institutional Income Fund X-B, L.P.; Southwest Royalties Institutional Income Fund X-C, L.P.; Southwest Developmental Drilling Fund, 1990, L.P.
These partnerships must terminate their business and dissolve on December 31, 2038, unless dissolved earlier pursuant to the terms of their partnership agreements or the Delaware Revised Uniform Limited Partnership Act.	These partnerships must terminate their business and dissolve on December 31, 2039, unless dissolved earlier pursuant to the terms of their partnership agreements or the Delaware Revised Uniform Limited Partnership Act.	These partnerships must terminate their business and dissolve on December 31, 2040, unless dissolved earlier pursuant to the terms of their partnership agreements or the Delaware Revised Uniform Limited Partnership Act.

Southwest Developmental Drilling Fund 91-A, L.P.; Southwest Developmental Drilling Fund 92-A, L.P.	Southwest Developmental Drilling Fund 1993, L.P.	Southwest Developmental Drilling Fund 1994, L.P.
These partnerships must terminate their business and dissolve on December 31, 2041, unless dissolved earlier pursuant to the terms of their partnership agreements or the Delaware Revised Uniform Limited Partnership Act.	This partnership will have perpetual existence unless dissolved earlier pursuant to the terms of its partnership agreement or the Delaware Revised Uniform Limited Partnership Act.	This partnership will terminate its business and dissolve on December 31, 2044, unless dissolved earlier pursuant to the terms of its partnership agreement or the Delaware Revised Uniform Limited Partnership Act.

Southwest Partners, L.P.

This partnership will have perpetual existence unless dissolved earlier pursuant to the terms of its partnership agreement or the Delaware Revised Uniform Limited Partnership Act.

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Taxation

Southwest Royalties, Inc.

All Partnerships

We are a taxable entity. A holder of our common stock will not be taxed with respect to our income, but will realize taxable income to the extent we make actual distributions that are out of current earnings or that are in excess of the basis in our common stock. As stated above under the heading “—Distributions and Dividends,” we have never paid cash dividends and do not anticipate paying them in the foreseeable future.

The partnerships are not tax paying entities. Rather, each holder of partnership interests includes his share of the income, gains, losses, deductions, and credits attributable to the partnership operations in computing his taxable income without regard to the cash distributed to him. Cash distributions to a limited partner are generally not taxable unless they exceed the basis in his limited partner interests.

Financial Reporting

Southwest Royalties, Inc.	Southwest Combination Income/Drilling Program 1988, L.P.; Southwest Developmental Drilling Fund 1990, L.P.; Southwest Partners, L.P.; Southwest Developmental Drilling Fund 1993, L.P.; Southwest Developmental Drilling Fund 1994, L.P.	All other Partnerships
We are currently not subject to reporting requirements under federal securities laws. Upon consummation of the merger, however, we will become subject to the reporting requirements of the Exchange Act and file annual and quarterly reports with the SEC.	These partnerships are not subject to the reporting requirements of the Exchange Act and are not required to file annual or quarterly reports with the SEC.	These partnerships are subject to the reporting requirements of the Exchange Act and file annual and quarterly reports with the SEC.

Meetings and Proposals

Southwest Royalties, Inc.	Southwest Partners, L.P.	All other Partnerships
We hold annual meetings for the purpose of electing directors and transacting other business. Special meetings may be held for any purpose at any time upon the request of our Chairman, President, or a majority of the Board of Directors. Our secretary must call a special meeting upon the written request of the holders of shares entitled to cast not less than a majority of all votes entitled to be cast at such meeting. The secretary must inform such stockholders of the reasonably estimated costs of preparing and mailing notice of the meeting, and upon payment to Southwest by the stockholders of such costs, the secretary must give notice to each stockholder entitled to notice of the meeting. The business to be conducted at a special meeting is limited to the purpose or purposes specified by such order. Our Amended and Restated Bylaws establish advance notice procedures with regard to stockholder proposals.	Meetings may be called and business proposed by limited partners owning a 20% interest in the partnership.	With the exception of Southwest Partners, L.P., meetings may be called and business proposed by limited partners holding a 10% interest in these partnerships.

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Indemnification

Southwest Royalties, Inc.	Southwest Partners, L.P.	All other Partnerships
Section 145 of the Delaware General Corporation Law permits a corporation to indemnify any person who is, or is threatened to be made, a party to any suit owing to the fact that the person is a director, officer, employee or agent acting on behalf of the corporation, subject to a determination by the Board of Directors that the person has met certain standards of conduct. Our Amended and Restated Certificate of Incorporation requires indemnification of our officers, directors and controlling persons to the fullest extent permitted or allowed by Delaware law. Expenses, including attorneys’ fees incurred by an officer, director or controlling person, in defending a proceeding, must be paid by Southwest, in advance of the final disposition of such proceeding, without requiring a preliminary determination of the ultimate entitlement to indemnification, upon receipt of an undertaking by or on behalf of such indemnified party to repay such amount if it shall ultimately be determined that he or she is not entitled to be indemnified by Southwest.	The partnership agreement provides that the partnership shall indemnify, hold harmless and pay all claims and judgments against the general partner relating to any liability or damage incurred by reason of any act performed or omitted in connection with the business of the partnership, including attorneys’ fees and all liabilities under federal and state securities laws as permitted by law. In the event of an action by a limited partner against a general partner, including a derivative suit, the partnership will indemnify the general partner if the general partner is successful in the action. The partnership will also indemnify, hold harmless, pay all expenses, costs or liabilities of any general partner who suffers any financial loss as a result of acquiring any option, or making any other similar payment or assuming any other obligation in connection with any property proposed to be acquired by and for the benefit of the partnership. The general partner shall not be indemnified from any liability for willful misconduct, fraud or gross negligence.	With the exception of Southwest Partners, L.P., the partnership agreements provide that the partnerships will indemnify their general partners and affiliates from and against any loss or damage incurred by reason of any act or omission performed or omitted by them, provided that: • the general partners determine, in good faith, that the course of conduct which caused the loss or liability is in the best interests of the partnership; • the general partners or affiliates are acting on behalf of or performing services for the partnership; • the liability or loss incurred is not the result of negligence or misconduct of the general partners or affiliates; • payments arising from indemnification shall be from and limited to partnership assets; and • the partnerships shall not indemnify the general partners or affiliates for claims under state and federal securities laws unless there has been a successful adjudication on the merits of the claim or the claim has been dismissed, with prejudice, on the merits by a court of competent jurisdiction.

Fiduciary Duty

Southwest Royalties, Inc.

All Partnerships

Our Board of Directors stands in a fiduciary relationship to the corporation and its stockholders. Delaware law requires that our Board of Directors act in good faith, with care and with undivided loyalty to the corporation.

Delaware and Tennessee law provide that, except as provided in the partnership agreements, general partners owe the fiduciary duties of loyalty and care to the limited partners of a partnership. The partnership agreements of the partnerships managed by Southwest provide that the general partners should act “in good faith on behalf of the Partnership and in a manner reasonably believed by them to be within the scope of this Agreement and in the best interests of the Partnership.”

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Mergers

Southwest Royalties, Inc.	Southwest Royalties, Inc. Income Fund V, L.P. and Southwest Royalties, Inc. Income Fund VI, L.P.	All other Partnerships
Except with respect to certain business combinations with interested stockholders governed by Section 203 of the Delaware General Corporation Law and restrictions contained in the Indenture governing our Senior Secured Notes due 2004 and our Senior Credit Agreement, the Delaware General Corporation Law, as well as our Amended and Restated Certificate of Incorporation and Bylaws, permit us to merge with another corporation or partnership and generally require that the merger be approved by the holders of a majority of the outstanding shares of our stock entitled to vote thereon.	These partnerships are governed by the Tennessee Uniform Limited Partnership Act (“ULPA”). ULPA does not specifically address mergers. The partnership agreements also do not specifically address mergers but provide that the partnership may sell all or substantially all of its assets upon a majority vote of limited partner interests; however, we will amend the partnership agreements to allow the merger of the partnerships and to provide that the partnerships are to be governed by the Tennessee Revised Uniform Partnership Act, as enacted January 1,1989.	The provisions of the Delaware Revised Uniform Limited Partnership Act, to which these partnerships are subject, permit the partnerships to merge or consolidate with domestic or foreign partnerships or corporations, subject to the vote specified in the Delaware General Corporation Law, which is the approval of the general partner and limited partners holding more than 50% interest in the profits of the partnership.

Appraisal Rights

Southwest Royalties, Inc.

All Partnerships

Under the Delaware General Corporation Law, a holder of our common stock who does not vote in favor of a merger or consolidation may, upon compliance with certain procedures, be entitled to receive the fair value of his shares in cash in lieu of the consideration he would otherwise have received in the merger or consolidation. Appraisal right are not available in certain mergers, including (a) mergers of which we are the surviving corporation where no vote of our stockholders is required and (b) any merger in which our stock is listed, at the time of such merger, on a national securities exchange or held of record by more than 2,000 holders, and the holders of our common stock are not required to accept in exchange for their shares anything other than shares of stock of the surviving corporation that, on the effective date of the merger, would be listed on a national securities exchange or held of record by more than 2000 holders, cash in lieu of fractional shares, or any combination thereof.

None of the partnership agreements provide for appraisal rights. Neither the Tennessee Uniform Limited Partnership Act, the Tennessee Revised Uniform Partnership Act nor the Delaware Revised Uniform Limited Partnership Act provides for rights similar to the appraisal right of our common stock under the Delaware General Corporation Act.

Books and Records

Southwest Royalties, Inc.	All Partnerships
Books and records relating to our operations are maintained at our principal place of business. As a holder of our common stock, you will have access to our books and records at all reasonable times, upon reasonable notice.	Books and records relating to the operations of all of the partnerships are maintained at their respective principal places of business. All limited partners have access to the books and records of their respective partnership at all reasonable times, upon reasonable notice.

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Compensation

Southwest Royalties, Inc.	All Partnerships
Organizational Costs You are not required to reimburse us for any of the organizational costs incurred in organizing Southwest and conducting its pre-formation business and affairs.	Organizational Costs All partnerships were required to reimburse us, to some extent, for the organizational costs we incurred in organizing the partnerships and conducting their pre-formation business and affairs. Depending on your individual partnership, you were required to reimburse us for costs in an amount between 2% and 4% of the aggregate amount of all contributions made by the limited partners in your partnership. All organizational costs in excess of the amounts referenced above were borne by us.
General and Administrative Costs You will not be required to reimburse us for annual general and administrative costs.	General and Administrative Costs All partnerships are required to reimburse us for annual general and administrative costs in an amount not exceeding 2% of the aggregate amount of all contributions made by the limited partners. All general and administrative costs incurred in excess of 2% are borne by us.
Non-recurring Management Fee You will not be required to pay to us a non-recurring management fee. However, we are required to reimburse our directors for expenses incurred in attending any Board meetings.	Non-recurring Management Fee In addition to the above described amounts, if you are a limited partner in either Southwest Royalties, Inc. Income Funds V or VI, you paid to us, as compensation for our services as general partner in organizing and managing those partnerships, a non-recurring management fee equal to 2% of the aggregate amount of all contributions made by the limited partners in your partnership.
Annual Management Fee Our directors receive fees for their service on our Board. See “MANAGEMENT OF SOUTHWEST—Board Compensation.”	Annual Fee In addition to the above described amounts, if you are a limited partner in Southwest Partners, L.P., you are required to pay to us an annual fee for managing the affairs of the partnership equal to 2% of the total capital contributions. This fee is payable quarterly.

Investment Policy

Southwest Royalties, Inc.	Southwest Partners, L.P.	All other Partnerships
As of September 30, 2002, we have a total principal indebtedness of approximately $125.0 million. Covenants in our debt instruments limit our ability to borrow additional funds and to dispose of assets.	Southwest Partners, L.P. is authorized to borrow funds not in excess of 400% of its capital contributions at any given time. These borrowings must be non-recourse to the limited partners but may be fully collateralized by Southwest Partners’ assets.	Other than Southwest Partners, L.P., the partnerships are currently prohibited from borrowing or incurring any indebtedness other than trade payables in the normal course of business. Most of the partnerships are limited in this respect by their governing partnership agreements.

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Compensation and Distribution History

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from all 21 partnerships, in the aggregate, for the 3 most recent fiscal years and the 6 months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	1,311,000	$	1,311,000	$	1,311,200	$	655,500
Administrative Overhead per Operating Agreements	$	1,841,858	$	1,806,581	$	1,841,516	$	930,687
Cash Distributions Paid to General Partner as General Partner(1)	$	772,716	$	742,010	$	257,245	$	106,740
Cash Distributions Paid to General Partner as Limited Partner	$	892,896	$	756,860	$	212,605	$	152,098

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, President and Chief Executive Officer of Southwest Royalties, Inc. as general partner

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

The following section contains a discussion of the material federal income tax aspects of the ultimate conversion of limited partner interests into Southwest common stock. The federal tax consequences of each merger will vary for each limited partner because of the different circumstances of each participating partnership and the individual federal income tax position of each limited partner.

The following discussion is based on existing law, including the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Department regulations promulgated thereunder (the “Regulations”), current published rulings and procedures of the IRS and existing court decisions. However, legislative, judicial, or administrative changes or interpretations may be forthcoming that could repeal, overrule, or modify any of these authorities. Any such change could be retroactive and, accordingly, could alter or modify the statements and conclusions set forth in this document. No rulings have been requested from the IRS with respect to any aspect of the proposed merger. Furthermore, there can be no assurance that the IRS or the courts would agree with the conclusions set forth in the discussion below.

This discussion is not exhaustive of all possible tax consequences. It does not address any state, local or foreign tax consequences nor does it discuss all of the aspects of federal income taxation that may be relevant to specific partners in light of their particular circumstances. This discussion is directed primarily to individual limited partners who are citizens of the United States. It does not discuss federal income tax consequences of persons who are not United States citizens or persons to which special rules apply because of their specific activities, such as tax-exempt entities, regulated investment companies and insurance companies. This discussion is not intended as a substitute for careful tax planning, and no limited partner, and in particular no tax-exempt limited partner, should vote on the merger without first consulting a qualified tax advisor.

THE FOLLOWING ANALYSIS OF THE FEDERAL INCOME TAX CONSIDERATIONS IS NOT INTENDED AS A SUBSTITUTE FOR CAREFUL TAX PLANNING. ACCORDINGLY, IF A LIMITED PARTNER CONTEMPLATES APPROVING THE MERGER, HE IS URGED TO CONSULT HIS TAX ADVISORS REGARDING HIS OWN TAX SITUATION.

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As more fully described below, if you own limited partner interests in a partnership participating in the merger, you should generally not recognize any gain or loss on the merger. We will not request a ruling from the IRS. In the absence of a ruling, the IRS may challenge all or some of the tax consequences resulting from a merger. If any such challenge were successful, the federal income tax consequences resulting from a merger could be different from those described below.

General Treatment.    We believe that the merger of the partnerships into Southwest’s subsidiary, Southwest Consolidated Partnerships, should be treated for federal income tax purposes as a non-taxable contribution of assets and liabilities by the partnerships to Southwest Consolidated Partnerships. Likewise, we believe that the merger of Southwest Consolidated Partnerships into Southwest Managed Assets should be treated for federal income tax purposes as a non-taxable contribution of assets and liabilities to Southwest Managed Assets in exchange for the common stock of Southwest held by Southwest Managed Assets, followed by a distribution of the Southwest common stock to the former limited partners.

Treatment to Participating Partnerships.    If the merger is treated as a contribution and liquidation as described above, the participating partnerships should not recognize gain or loss upon the transfer of properties to Southwest Consolidated Partnerships in exchange for common stock of Southwest Consolidated Partnerships. A participating partnership should take an adjusted basis in the common stock received equal to the aggregate adjusted basis in the assets transferred to Southwest Consolidated Partnerships. Each participating partnership will terminate upon the effective date of the merger and, accordingly, will close its tax year and distribute its assets to the limited partners. The closing of the tax year requires the partnerships to file a final tax return, which may, in turn, create a one-time tax consequence to the partnerships.

Treatment to Southwest and to its Subsidiary Southwest Managed Assets.    Neither Southwest nor its subsidiary, Southwest Managed Assets, should recognize gain or loss as a result of the receipt of a participating partnership’s assets and liabilities in the transfers. Southwest’s subsidiary, Southwest Managed Assets, should take an adjusted basis in the assets ultimately received from a participating partnership equal to the adjusted basis that each participating partnership had in its contributed assets. Under the applicable provisions of the Internal Revenue Code and Regulations, the holding period for some assets transferred (for the purpose of determining whether the assets will be treated as capital gains or capital losses—see explanation below) will include the period for which the participating partnerships held the assets. For other assets, a new holding period will begin upon transfer.

Treatment to Limited Partners.    As a limited partner ultimately receiving Southwest common stock, you should be treated as receiving such common stock in liquidation of your limited partner interest in the participating partnership. If the merger is treated as a contribution and liquidation, no gain or loss should be recognized by you as a limited partner of any participating partnership as a result of your receipt of Southwest common stock. Additionally, the shares of special stock to be issued into the escrow account for the benefit of the limited partners and the additional common stock to be distributed to the limited partners in the event the special stock converts into common stock will likewise be tax-neutral to the limited partners. There is a possibility, however, that the IRS may disagree with our characterization of the merger as a tax-deferred transaction.

Your adjusted basis in the Southwest common stock that you receive in the merger should be the same as your adjusted basis in the liquidated limited partner interest. Your holding period for the stock should be determined by the holding period that each such participating partnership had in its assets. Because the holding period for each asset held by a participating partnership varies, each share of Southwest stock received in the merger may have a split holding period. Under the applicable provisions of the Internal Revenue Code and Regulations, a capital asset held for more than one year results generally in long-term gain or loss on the disposition of the asset. In the event you dispose of Southwest common stock within a year of the merger, it may be necessary to determine if a portion of your stock has a holding period of less than one year in order to

158

determine the appropriate tax treatment to you. In the event you sell your Southwest common stock at any time after holding it for one year, all gain or loss should be considered gain or loss from an asset held for more than one year.

You must also include your allocable share of a participating partnership’s items of income, gain, loss, deduction and credit for the final partnership tax year, including your allocable share through the merger closing date, on your federal income tax return. That information will be provided on a Schedule K-1 as required by law. The results of the partnership operations for such period will impact your tax basis in your limited partner interest and the computation of your adjusted basis in the Southwest common stock.

The Code contains certain “at risk” rules under Section 465, which generally prevent a taxpayer from deducting losses from the partnership which exceed the amount the taxpayer has “at risk” in the partnership. If there are any losses of a participating partnership allocable to you which have been suspended under Section 465 or because of a lack of sufficient outside basis, those losses will continue to be suspended and will be effectively lost. However, if there is any gain recognized in the merger by you as a limited partner, that gain can be offset by any losses suspended by Section 465.

The Code contains certain passive loss rules under Section 469, which generally prevent a taxpayer from deducting losses from “passive activities” in an amount greater than the taxpayer’s income derived from such activities. Similarly, credits from passive activities are limited to the tax allocable to the passive activities. Losses suspended under Section 469 can be used to offset any partner level gain recognized in the mergers. Any excess passive losses and credits from a participating partnership suspended under Section 469 are generally considered to be a passive activity loss from the same activity in the next succeeding year which can be used to offset passive income from other activities. Should you dispose of the our common stock in a taxable transaction, any passive activity losses associated with the our common stock cease to be considered passive and can be deducted as an ordinary loss, subject to any other applicable loss restrictions.

After the completion of the merger, we will continue to operate in a corporate form and will be treated as an entity separate from its stockholders for tax purposes. All income, losses, gain, deduction and credits will be taxed to Southwest and reported on its tax returns. Any distributions to the stockholders generally will constitute dividends. Dividends are generally characterized as ordinary income to the recipients and must be reported on the income tax return of the recipient. A sale, exchange, or redemption of the shares of Southwest common stock will generally constitute a sale or exchange of a capital asset, thus qualifying for capital gains rates in the case of an individual. However, due to the split holding period discussed above, any taxable sales or exchanges occurring within one year of the merger could result in a portion of the gain being short-term capital gain.

We have received an opinion from legal counsel as to the material United States federal income tax consequences of the merger, which we have included as an exhibit to our registration statement of which this prospectus/proxy statement is a part but not as an appendix to this prospectus/proxy statement. Upon receipt of a written request by a limited partner or his representative who has been so designated in writing, a copy of this tax opinion will be transmitted promptly, without charge, by us. Written requests should be directed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attn: B.J. Parrish. You may also request a copy of this tax opinion by logging on to www. swrpartners.com and clicking on             .

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ERISA CONSIDERATIONS

General Fiduciary Obligations

Fiduciaries of pension, profit sharing, or stock bonus plans or other employee benefit plans (“ERISA Plans”) subject to the Employee Retirement Income Security Act of 1974, as amended, and all regulations thereunder (“ERISA”) (other than IRAs and other governmental plans as defined in section 3(32) of ERISA) also must consider whether (1) the investment in our common stock satisfies the diversification requirements of ERISA,

(2) the investment is prudent, (3) such fiduciaries have authority to acquire our common stock under the appropriate governing instruments and Title 1 of ERISA, (4) the investment will provide sufficient liquidity to the ERISA Plan to allow any benefit payments when due, and (5) the investment is made solely in the interest of the ERISA Plan and its participants and beneficiaries. A fiduciary of an IRA should consider that an IRA may only make investments that are authorized by an appropriate governing instrument. A fiduciary of an ERISA Plan also should consider ERISA’s prohibition on improper delegation of control over or responsibility for plan assets.

Under ERISA, a fiduciary may be liable for any loss resulting from a breach of his fiduciary duty and, under certain circumstances, he may be held liable for breaches of fiduciary duty by co-fiduciaries. However, in the case of individual account plans where a participant is permitted to and, in fact, does exercise independent control over the assets in his individual account, under certain circumstances, fiduciaries with respect to such a plan are not liable for any loss that results from such exercise and control by the participant. Penalties also are imposed on any fiduciary who has, himself, engaged in a prohibited transaction within the meaning of ERISA. Trustees and other fiduciaries should carefully consider whether ownership of our common stock is consistent with their fiduciary responsibilities.

Plan Asset Rules

Fiduciaries of ERISA Plans covered by ERISA who are considering an investment in our common stock on behalf of an ERISA Plan also should be aware that the assets of ERISA Plans generally are required to be held in trust and that certain persons who exercise authority or control over plan assets ordinarily will be treated as fiduciaries under ERISA and will be subject to the fiduciary obligations and prohibited transaction rules of ERISA. Prohibited transactions generally prevent an ERISA fiduciary from dealing with ERISA Plan assets for its own benefit or interest. ERISA does not define the term “plan assets.” However, the Department of Labor has issued regulations, effective March 13, 1987, relating to the definition of “plan assets” (the “Plan Asset Regulations”). The Plan Asset Regulations generally provide that acquisition by an ERISA Plan of a security that is an equity interest in an entity which is neither a publicly-offered security nor a security issued by an investment company registered under the Investment Company Act of 1940 will result in treatment of the equity interest and an undivided interest in each of the underlying assets of the entity as assets of the plan, unless the entity is an operating company or equity participation in the entity by ERISA Plan investors is not significant.

An undivided interest in each of our underlying assets will not be treated as plan assets if shares of our common stock are “publicly-offered securities.” A security is a publicly-offered security if it is (a) freely transferable, (b) part of a class of securities that is widely held, and (c) sold to an ERISA Plan as part of an offering of such securities to the public pursuant to an effective registration statement under the Securities Act and the securities sold are thereafter registered with the SEC pursuant to a registration statement under Section 12 of the Exchange Act. Generally, a class of securities is “widely held” only if it is a class of securities that is owned by 100 or more investors independent of the issuer and of one another. Whether a security is “freely transferable” is to be determined based on all relevant facts and circumstances. Based on the facts that our common stock (a) will be offered pursuant to an effective registration statement under the Securities Act, (b) is approved for listing on a national securities exchange, subject to official notice of issuance, and (c) is expected to be held by 100 or more investors independent of the issuer, an investment in our common stock by an ERISA Plan should be treated as an investment in publicly-offered securities under the Plan Asset Regulations and should not result in all or a portion of our assets being treated as plan assets.

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If for any reason our assets should be deemed to be plan assets of an ERISA Plan holding our common stock, (1) the prudence standards and other provisions of Part 4 of Title 1 of ERISA, which are applicable to investments by ERISA Plans and impose liability on fiduciaries, would extend as to all plan fiduciaries to investments we have made, (2) the person or persons who possess the discretionary responsibility for the investment of the assets of ERISA Plans in our common stock would be liable under the Part 4 of Title 1 of ERISA for investments we have made that do not conform to such ERISA standards, and (3) certain transactions that we might enter into in the ordinary course of our business and operation might constitute “prohibited transactions” under ERISA. A prohibited transaction, in addition to imposing potential personal liability upon fiduciaries of ERISA Plans, also may result in the imposition of an excise tax under the Code upon the party in interest or disqualified person with respect to the ERISA Plan.

LEGAL OPINIONS

Certain legal matters in connection with shares of our common stock to be issued in the merger have been passed upon for Southwest, and the opinion referred to in “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” has been rendered by, Baker, Donelson, Bearman, & Caldwell, P.C.

EXPERTS

Accountants

The consolidated financial statements of Southwest Royalties, Inc. and subsidiaries and the financial statements of the affiliated partnerships as of December 31, 2001 and 2000, and for each of the years in the three-year period ended December 31, 2001, have been included herein in reliance upon the reports of KPMG LLP, independent accountants, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing. The Southwest Royalties, Inc. and subsidiaries audit report covering the December 31, 2001 financial statements refers to a change to the method of accounting for derivative instruments and hedging activities.

Reserve Engineers

Information relating to the estimated provided reserves of oil and natural gas and the related estimates of future net revenues and present values thereof as of December 31, 1999, 2000 and 2001 included in this prospectus/proxy statement and in the notes to our financial statements and those of the partnerships have been audited by Ryder Scott Company, L.P.

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FUTURE SHAREHOLDER PROPOSALS

Under the rules of the SEC, if a stockholder wants Southwest to include a proposal in our proxy statement and form of proxy for presentation in the event we hold an annual meeting of stockholders in 2003, the proposal must be received by us within a reasonable time before we begin to print and mail our proxy materials at Southwest Royalties, Inc., 407 North Big Spring, Midland, Texas 79701, Attention: Secretary.

Under our Amended and Restated Bylaws, and as permitted by the rules of the SEC, certain procedures are provided which a stockholder must follow to nominate persons for election as directors or to introduce an item of business at an annual meeting of stockholders. These procedures provide that nominations for director nominee and/or an item of business to be introduced at an annual meeting of stockholders must be submitted in writing to our Secretary at the address noted above. We must receive the notice of the intention to introduce a nomination or proposed item of business at our 2003 annual meeting no later than ten days following the day on which we publicly announce the date of our 2003 annual meeting.

For any other annual or special meeting, the nomination or item of business must be received not more than 90 days prior to such meeting and not less than 45 days before such annual meting or the tenth day following the date on which public announcement of the date of such meeting is first made by Southwest.

If we do not receive timely notice, or if we meet other requirements of the SEC rules, the persons named as proxies in the proxy materials relating to that meeting will use their discretion in voting the proxies when these matters are raised at the meeting.

Our Board of Directors is not aware of any matters that are expected to come before the joint special meeting of limited partners other than those referred to in this prospectus/proxy statement. If any other matter should come before the joint special meeting, the persons named in the accompanying proxy intend to vote the proxies in accordance with their best judgment.

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SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

Southwest Royalties, Inc. and Subsidiaries
Independent Auditors’ Report	F-6
Consolidated Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-7
Consolidated Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-9
Consolidated Statements of Stockholders’ Deficit and Other Comprehensive Income, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-10
Consolidated Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-11
Notes to Consolidated Financial Statements	F-13
Southwest Royalties, Inc. Income Fund V, L.P.
Independent Auditors’ Report	F-36
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-37
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-38
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-39
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-40
Notes to Financial Statements	F-41
Southwest Royalties, Inc. Income Fund VI, L.P.
Independent Auditors’ Report	F-49
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-50
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-51
Statements of Changes in Partners’s Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-52
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-53
Notes to Financial Statements	F-54
Southwest Oil & Gas Income Fund VII-A, L.P.
Independent Auditors’ Report	F-62
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-63
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-64
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-65
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-66
Notes to Financial Statements	F-67
Southwest Royalties Institutional Income Fund VII-B, L.P.
Independent Auditors’ Report	F-75
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-76
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-77

F-1

Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-78
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-79
Notes to Financial Statements	F-80
Southwest Oil & Gas Income Fund VIII-A, L.P.
Independent Auditors’ Report	F-88
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-89
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-90
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-91
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-92
Notes to Financial Statements	F-93
Southwest Royalties Institutional Income Fund VIII-B, L.P.
Independent Auditors’ Report	F-101
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-102
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-103
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-104
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-105
Notes to Financial Statements	F-106
Southwest Combination Income/Drilling Program 1988, L.P.
Independent Auditors’ Report	F-114
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-115
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-116
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-117
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-118
Notes to Financial Statements	F-119
Southwest Oil & Gas Income Fund IX-A, L.P.
Independent Auditors’ Report	F-125
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-126
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-127
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-128
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-129
Notes to Financial Statements	F-130
Southwest Royalties Institutional Income Fund IX-B, L.P.
Independent Auditors’ Report	F-138
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-139
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-140

F-2

Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-141
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-142
Notes to Financial Statements	F-143
Southwest Oil & Gas Income Fund X-A, L.P.
Independent Auditors’ Report	F-151
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-152
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-153
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-154
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-155
Notes to Financial Statements	F-156
Southwest Royalties Institutional Income Fund X-A, L.P.
Independent Auditors’ Report	F-164
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-165
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-166
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-167
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-168
Notes to Financial Statements	F-169
Southwest Oil & Gas Income Fund X-B, L.P.
Independent Auditors’ Report	F-177
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-178
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-179
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-180
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-181
Notes to Financial Statements	F-182
Southwest Royalties Institutional Income Fund X-B, L.P.
Independent Auditors’ Report	F-190
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-191
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-192
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-193
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-194
Notes to Financial Statements	F-195
Southwest Oil & Gas Income Fund X-C, L.P.
Independent Auditors’ Report	F-203
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-204
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-205

F-3

Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-206
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-207
Notes to Financial Statements	F-208
Southwest Royalties Institutional Income Fund X-C, L.P.
Independent Auditors’ Report	F-216
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-217
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-218
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-219
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-220
Notes to Financial Statements	F-221
Southwest Developmental Drilling Fund 1990, L.P.
Independent Auditors’ Report	F-229
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-230
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-231
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-232
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-233
Notes to Financial Statements	F-234
Southwest Developmental Drilling Fund 91-A, L.P.
Independent Auditors’ Report	F-240
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-241
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-242
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-243
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-244
Notes to Financial Statements	F-245
Southwest Developmental Drilling Fund 92-A, L.P.
Independent Auditors’ Report	F-253
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-254
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-255
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-256
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-257
Notes to Financial Statements	F-258
Southwest Partners, L.P. and Subsidiary
Independent Auditors’ Report	F-266
Consolidated Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-267
Consolidated Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-268

F- 4

Consolidated Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-269
Consolidated Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-270
Notes to Consolidated Financial Statements	F-271
Southwest Developmental Drilling Fund 1993, L.P.
Independent Auditors’ Report	F-279
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-280
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-281
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-282
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-283
Notes to Financial Statements	F-284
Southwest Developmental Drilling Fund 1994, L.P.
Independent Auditors’ Report	F-290
Balance Sheets, December 31, 2001 and 2000 and June 30, 2002	F-291
Statements of Operations, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-292
Statements of Changes in Partners’ Equity, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002	F-293
Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 and Six Months ended June 30, 2002 and 2001	F-294
Notes to Financial Statements	F-295

F-5

INDEPENDENT AUDITORS’ REPORT

The Board of Directors and Stockholders

Southwest Royalties, Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of Southwest Royalties, Inc. and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders’ deficit and other comprehensive income and cash flows for each of the years in the three-year period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities in 2001.

KPMG LLP

April 19, 2002

F-6

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30, 2002		December 31,
			2001		2000
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	6,901	$	6,469	$	15,595
Restricted cash		598		640		759
Accounts receivable, net of allowance of $208, $344 and $175, respectively		6,091		5,143		8,110
Receivables from related parties		643		1,966		2,083
Other current assets		671		356		3,512
Total current assets		14,904		14,574		30,059
Oil and gas properties, using the full cost method of accounting
Proved		230,172		228,277		204,751
Unproved		913		952		625
		231,085		229,229		205,376
Less accumulated depletion, depreciation and amortization		144,621		141,415		131,734
Oil and gas properties, net		86,464		87,814		73,642
Other property and equipment, net		4,124		4,361		4,612
Other assets
Deferred tax asset		—		—		6,000
Deferred debt costs, net of accumulated amortization of $469, $3,865 and $2,416, respectively		1,883		3,421		4,654
Other, net		2,679		944		390
Total other assets		4,562		4,365		11,044
Total assets	$	110,054	$	111,114	$	119,357

The accompanying notes are an integral part of these consolidated financial statements.

F-7

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

	June 30, 2002			December 31,
				2001			2000
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current liabilities
Current maturities of long-term debt	$	18,204		$	145		$	92
Accounts payable		2,581			3,041			4,644
Accounts payable to related parties		1,030			734			1,599
Accrued expenses		3,138			3,637			3,123
Accrued interest payable		559			3,105			3,187
Total current liabilities		25,512			10,662			12,645
Long-term debt		121,900			173,954			173,771
Other long-term liabilities		521			527			1,249
Deferred income taxes payable		2,501			—			—
Stockholders’ Deficit
Preferred stock—$1 par value, 5,000,000 shares authorized; none issued and outstanding at June 30, 2002, December 31, 2001 and 2000		—			—			—
Common stock—$.01 par value, 10,000,000 shares authorized; 100,000 shares issued and outstanding at June 30, 2002 and December 31, 2001 and 2000		1			1			1
Class A common stock—$.01 par value, 900,000 shares authorized; 900,000 shares issued and outstanding at June 30, 2002, none issued and outstanding at December 31, 2001 and 2000		9			—			—
Additional paid-in capital		38,917			10,601			10,601
Accumulated deficit		(79,307	)		(83,128	)		(77,294	)
Accumulated other comprehensive income:
Transition adjustment on implementation of SFAS 133 net of reclassification to earnings of $949 in 2001		—			81			—
Note receivable from an officer and stockholder		—			(1,584	)		(1,616	)
Total stockholders’ deficit		(40,380	)		(74,029	)		(68,308	)
Total liabilities and stockholders’ deficit	$	110,054		$	111,114		$	119,357

The accompanying notes are an integral part of these consolidated financial statements.

F-8

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	For the six months ended June 30						For the years ended December 31,
	2002			2001			2001			2000			1999
	(unaudited)
Operating revenues
Oil and gas	$	18,775		$	31,503		$	50,991		$	54,263		$	31,425
Other		165			133			249			377			1,212
Total operating revenues		18,940			31,636			51,240			54,640			32,637
Operating expenses
Oil and gas production		7,054			8,541			17,798			15,153			10,833
General and administrative, net of related party management and administrative fees of $1,391, $1,411, $2,798, $3,254 and $3,515, respectively		2,001			1,412			3,133			2,973			1,430
Depreciation, depletion and amortization		3,478			5,380			10,249			5,597			5,502
Other		119			126			238			848			798
Total operating expenses		12,652			15,459			31,418			24,571			18,563
Operating income		6,288			16,177			19,822			30,069			14,074
Other income (expense)
Interest and dividend income		117			427			813			993			993
Interest expense		(6,918	)		(9,846	)		(19,579	)		(21,945	)		(22,382	)
Other		(522	)		(136	)		(890	)		305			(308	)
		(7,323	)		(9,555	)		(19,656	)		(20,647	)		(21,697	)
Income (loss) before income taxes, minority interest, equity loss and extraordinary items		(1,035	)		6,622			166			9,422			(7,623	)
Income tax benefit (expense)		—			(2,251	)		(6,000	)		6,000			—
Income (loss) before minority interest, equity loss and extraordinary items		(1,035	)		4,371			(5,834	)		15,422			(7,623	)
Minority interest in subsidiaries, net of tax		—			—			—			—			(1	)
Equity loss in partnerships, net of tax		—			—			—			—			(931	)
Income (loss) before extraordinary items		(1,035	)		4,371			(5,834	)		15,422			(8,555	)
Extraordinary item, gain on restructuring, net of tax of $3,226		6,263			—			—			—			—
Extraordinary items,(loss) gain on early extinguishment of debt, net of tax		(1,407	)		—			—			12,690			14,541
Net income (loss)	$	3,821		$	4,371		$	(5,834	)	$	28,112		$	5,986
Income (loss) per common share
Income (loss) per common share before extraordinary items	$	(2.26	)	$	43.71		$	(58.34	)	$	154.22		$	(85.55	)
Extraordinary items		10.60			—			—			126.90			145.41
Income (loss) per common share	$	8.34		$	43.71		$	(58.34	)	$	281.12		$	59.86
Weighted average shares outstanding		458,011			100,000			100,000			100,000			100,000

The accompanying notes are an integral part of these consolidated financial statements

F-9

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ DEFICIT

AND OTHER COMPREHENSIVE INCOME

For the years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

(in thousands, except share data)

	Common Stock			Additional Paid-In Capital			Accumulated Deficit			Accumulated Other Comprehensive Income			Note Receivable from Stockholder			Total
	Shares	Amount
Balance—January 1, 1999	100,000	$	1	$	10,601		$	(111,372	)	$	—		$	(1,679	)	$	(102,449	)
Payments received on note receivable	—		—		—			—			—			31			31
Net income	—		—		—			5,986			—			—			5,986
Balance—December 31, 1999	100,000		1		10,601			(105,386	)		—			(1,648	)		(96,432	)
Payments received on note receivable	—		—		—			—			—			32			32
Other	—		—		—			(20	)		—			—			(20	)
Net income	—		—		—			28,112			—			—			28,112
Balance—December 31, 2000	100,000		1		10,601			(77,294	)		—			(1,616	)		(68,308	)
Payments received on note receivable	—		—		—			—			—			32			32
Transition adjustment on implementation of SFAS 133 —January 1, 2001	—		—		—			—			1,030			—			1,030
Reclassification of transition adjustment	—		—		—			—			(949	)		—			(949	)
Net loss	—		—		—			(5,834	)		—			—			(5,834	)
Balance—December 31, 2001	100,000		1		10,601			(83,128	)		81			(1,584	)		(74,029	)
Issuance of Common Stock on debt exchange	900,000		9		29,577			—			—			—			29,586
Costs related to issuance of common stock	—		—		(1,261	)		—			—			—			(1,261	)
Cancellation of note receivable in exchange for collateral	—		—		—			—			—			1,584			1,584
Reclassification of transition adjustment	—		—		—			—			(81	)		—			(81	)
Net income	—		—		—			3,821			—			—			3,821
Balance June 30, 2002 (unaudited)	1,000,000	$	10	$	38,917		$	(79,307	)	$	—		$	—		$	(40,380	)

The accompanying notes are an integral part of these consolidated financial statements.

F-10

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	For the six months ended June 30,						For the years ended December 31,
	2002			2001			2001			2000			1999
	(unaudited)
Cash flows from operating activities
Net income (loss)	$	3,821		$	4,371		$	(5,834	)	$	28,112		$	5,986
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		3,478			5,380			10,249			5,597			5,502
Noncash interest expense		676			829			1,662			3,783			1,455
Noncash portion of loss (gain) from early extinguishment of debt		2,132			—			—			(12,690	)		(14,541	)
Noncash reclassification of unrealized gain		(81	)		(434	)		(949	)		—			—
Noncash interest income		(36	)		—			—			—			—
Noncash unrealized loss on oil and gas hedges		415			297			1,003			—			—
Noncash hedge amortization		—			—			—			638			223
Noncash unrealized loss on investments		1,222			—			-—			—			—
Extraordinary gain from exchange transaction		(9,489	)		—			—			—			—
Other noncash items		—			—			—			50			35
(Gain) loss on sale of assets		(2	)		(147	)		(15	)		(326	)		302
Equity in loss of partnerships		—			—			—			—			744
Impairment of equity investment in partnerships		—			—			—			—			187
Minority interest in loss of subsidiary		—			—			—			—			1
Bad debt expense		51			14			566			4			122
Deferred income taxes		2,501			2,251			6,000			(6,000	)		—
Changes in operating assets and liabilities-
Accounts receivable		(962	)		(2,292	)		2,915			(4,268	)		(902	)
Other current assets		(315	)		658			2,817			(876	)		91
Accounts payable and accrued expenses		(1,078	)		(147	)		(2,454	)		923			(1,293	)
Accrued interest payable		332			(62	)		(82	)		(348	)		(1,040	)
Change in restricted cash		42			(3	)		119			5,119			(5,284	)
Net cash provided by (used in) operating activities		2,707			10,715			15,997			19,718			(8,412	)
Cash flows from investing activities
Proceeds from sale of oil and gas properties		294			47			65			566			5,575
Investment in oil and gas properties		(2,150	)		(15,863	)		(23,918	)		(10,564	)		(3,688	)
Proceeds from sale of other property and equipment		2			5			18			425			1,248
Purchase of other property and equipment		(35	)		(194	)		(320	)		(475	)		(538	)
Proceeds from sale of other assets		—			18			20			56			1,812
Purchase of other assets		(51	)		(549	)		(605	)		(1,731	)		(1,418	)
Other		—			18			32			32			31
Net cash provided by (used in) investing activities		(1,940	)		(16,518	)		(24,708	)		(11,691	)		3,022

(continued)

F-11

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

(in thousands)

	For the six months ended June 30,						For the years ended December 31,
	2002			2001			2001			2000			1999
	(unaudited)
Cash flows from financing activities
Proceeds from borrowings		55,113			151			178			65,196			35,029
Payments on debt		(50,068	)		(85	)		(155	)		(73,154	)		(21,934	)
Change in other long-term liabilities		(6	)		(12	)		(222	)		(92	)		(52	)
Additions of deferred issue costs		(1,790	)		—			(216	)		(1,402	)		(4,500	)
Refund of debt issue costs		—			—			—			1,500			—
Purchase of minority interest in subsidiary		—			—			—			(8	)		—
Prepayment penalty on early extinguishment of debt		(1,000	)		—			—			—			—
Offering costs associated with exchange		(2,584	)		—			—			—			—
Net cash provided by (used in) financing activities		(335	)		54			(415	)		(7,960	)		8,543
Net (decrease) increase in unrestricted cash and cash equivalents		432			(5,749	)		(9,126	)		67			3,153
Unrestricted cash and cash equivalents—beginning of period		6,469			15,595			15,595			15,528			12,375
Unrestricted cash and cash equivalents—end of period	$	6,901		$	9,846		$	6,469		$	15,595		$	15,528
Non-cash investing and financing activities
Unrealized gain on oil and gas commodity option contracts-taken to other comprehensive income	$	—		$	1,030		$	1,030		$	—		$	—
Extinguishment of $114.2 million of debt, net of a $0.6 million unamortized discount as part of the exchange transaction	$	(114,187	)	$	—		$	—		$	—		$	—
Issuance of $60.0 million face value variable interest senior notes as part of the exchange transaction plus $15.1 million of future interest costs in accordance with SFAS No. 15	$	75,088		$	—		$	—		$	—		$	—
Issuance of 900,000 shares of Southwest stock with a fair market value of $29.6 million as part of the exchange transaction	$	29,586		$	—		$	—		$	—		$	—
Exchange of note receivable from stockholder for stock in privately held company, which collateralized the note	$	1,584		$	—		$	—		$	—		$	—
Deferred debt cost incurred	$	—		$	—		$	—		$	1,000		$	—
(Decrease) increase in other long-term liabilities associated with deferred debt costs	$	—		$	—		$	(500	)	$	500		$	—
Increase in accrued expenses associated with deferred debt costs	$	—		$	—		$	500		$	500		$	—
Supplemental disclosures of cash flow information
Interest paid	$	5,909		$	9,079		$	17,999		$	18,510		$	21,967
Income taxes paid	$	—		$	—		$	—		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-12

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization and Summary of Significant Accounting Policies

Organization

Southwest Royalties, Inc. (“Southwest”), a Delaware corporation was formed in August 1983. Southwest, prior to April 19, 2002, was a wholly-owned subsidiary of Southwest Royalties Holdings, Inc. (“SRH”). SRH, a Delaware corporation, was formed in June 1997 to serve as a holding company for Southwest, Midland Red Oak Realty, Inc. (“Red Oak”) and an equity investment in Basic Energy Service, Inc. (“Basic”). Each shareholder of Southwest was issued one share in SRH for each share of Southwest stock held. Prior to the formation of SRH, Red Oak and Basic were subsidiaries of Southwest. Southwest paid a dividend of the shares it owned in Red Oak and Basic to SRH. After the formation of SRH, Southwest and Red Oak became subsidiaries of SRH and, as of July 1, 1997, Basic was deconsolidated from SRH.

On April 19, 2002 Southwest entered into an Offer to Exchange and Consent Solicitation with respect to its 10.5% Senior Notes due 2004. As part of the Exchange Offer, approximately $114.8 million face amount of the 10.5% Senior Notes were exchanged for approximately $60.0 million face value of new Senior Secured Notes and 900,000 shares of Southwest’s Class A common stock which represents approximately 90% of the voting stock of Southwest after the exchange. As part of this transaction, Southwest issued a 1,000 for 1 stock split to SRH, which prior to the transaction held 100% or 100 shares of the issued and outstanding common stock. A total of 99,900 new shares of common stock was issued to SRH and the par value of the common stock was changed from $.10 par value to $.01 par value. All share and per share amounts have been restated to retroactively reflect the stock split. (See note 4 for further discussion)

The results of operations for the periods presented comprise those of Southwest, its consolidated subsidiaries and its proportionate interest in the oil and gas partnerships for which it serves as managing general partner (see further discussion below), and excludes the operations of Red Oak and Basic. Transactions with previously consolidated subsidiaries (Red Oak and Basic) have been appropriately reflected as related party transactions.

Business

Southwest is principally involved in the business of oil and gas development and production, as well as organizing and serving as managing general partner for various public and private limited partnerships engaged in oil and gas development and production. Southwest is also the general partner of Southwest Partners II and III, which own common stock in Basic. Southwest sells its oil and gas production to a variety of purchasers, with the prices it receives being dependent upon the oil and gas commodity prices.

Principles of Consolidation

The consolidated financial statements include the accounts of Southwest and its subsidiaries. As of June 30, 2002, Southwest owned 100% of Blue Heel Company (“Blue Heel”). Effective August 2000, Midland Southwest Software (“MSS”), a 100% wholly owned software subsidiary, was merged into Southwest. Effective November 1999, Threading Products International (“TPI”), a 100% wholly owned manufacturing subsidiary, was liquidated. The consolidated financial statements include Southwest’s proportionate share of the assets, liabilities, income and expenses of the oil and gas limited partnerships for which it serves as managing general partner. Southwest accounts for its investments in Southwest Partners II and III, which hold an equity investment in Basic, using the equity method, as Southwest exercises significant influence over the operations of these partnerships. All significant intercompany transactions have been eliminated.

F-13

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Estimates and Uncertainties

Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Southwest’s depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserves estimates, which are inherently imprecise. Actual results could differ from those estimates.

Cash and Cash Equivalents

Southwest considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. In addition, Southwest maintains its excess cash in several interest bearing accounts in various financial institutions.

Restricted Cash

Restricted cash represents amounts due to the original stockholders of Espero Energy pursuant to Southwest acquisition of Espero Energy in August 1995. (In thousands):

	June 30, 2002		December 31,
			2001		2000
Escrow fund	$	598	$	640	$	759

Concentrations of Credit Risk

Southwest is subject to credit risk through oil and gas trade. Although a substantial portion of its customers’ ability to pay is dependent upon conditions in the oil and gas industry as well as general economic conditions, credit risk is reduced due to a large customer base.

Commodity Hedging and Derivative Financial Instruments

Southwest has only limited involvement with derivative financial instruments and does not use them for trading purposes. They are used to manage commodity price risks. Southwest is exposed to credit losses in the event of nonperformance by the counter-parties to its commodity hedges. Southwest does not obtain collateral or other security to support financial instruments subject to credit risk but monitors the credit standing of the counter-parties.

Through December 31, 2000, premiums paid for commodity option contracts which qualified as hedges under Statement of Accounting Standards (“SFAS”) No. 80 “Accounting for Futures Contracts”, were amortized to oil and gas sales over the term of the agreements. Unamortized premiums were included in other assets in the consolidated balance sheet. Amounts receivable or payable under the commodity option contracts were accrued as an increase or decrease in oil and gas sales for the applicable periods. Effective January 1, 2001, derivative financial instruments are accounted for in accordance with SFAS 133 as amended by SFAS 138.

As of January 1, 2001, Southwest adopted Statement of Financial Accounting Standards SFAS No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative

F-14

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to changes in the fair value of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign currency denominated forecasted transaction. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in Southwest’s statement of operations. Southwest recorded a net transition adjustment gain of $1,030,000 in accumulated other comprehensive income on January 1, 2001. As of June 30, 2002, the transition adjustment has been fully amortized.

Inventories

Inventories consist of lease and well equipment not currently being used in production and are accounted for at the lower of cost (first-in, first out) or market.

Oil and Gas Properties

All of Southwest’s oil and gas properties are located in the United States and are accounted for at cost under the full cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. No gain or loss is recognized on the sale of oil and gas properties unless nonrecognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of sales proceeds.

Net capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized using the units of revenue method, whereby the provision is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves. Should the net capitalized costs net of related deferred income taxes exceed the estimated present value of oil and gas reserves discounted at 10% and adjusted for related income taxes, such excess costs would be charged to expense in the consolidated statements of operations. There was no impairment required at June 30, 2002.

It is reasonably possible that the estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could change significantly in the near term due to the potential fluctuation of oil and gas prices or production. Depletion estimates would also be affected by such changes.

Management and service fees received for contractual arrangements, if any, are treated as reimbursement of costs, offsetting the costs incurred to provide those services, with any excess of fees over costs credited to the full cost pool and recognized through lower cost amortization only as production occurs.

Property and Equipment

Other property and equipment is stated at cost. Repairs and maintenance are charged to expense as incurred, with additions and improvements being capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation are removed from the related accounts and any gain or loss is reflected in the consolidated statements of operations.

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SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Depreciation is provided on the straight-line method based on the estimated useful lives of the depreciable assets as follows:

Building and improvements	20 to 30 years
Leasehold improvements	2 to 10 years
Machinery and equipment	3 to 5 years
Furniture and fixtures	3 to 5 years

Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of

In accordance with the provisions of SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, Southwest reviews its long-lived assets, excluding oil and gas properties accounted for using the full cost method of accounting, and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In this circumstance, Southwest recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.

In October 2001, the FASB issued SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of SFAS No. 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. Southwest adopted the SFAS No. 144 on January 1, 2002. Southwest believes that the impact from SFAS No 144 on Southwest’s financial position and results of operation should not be significantly different from that of SFAS No. 121.

Deferred Debt Costs

Southwest capitalizes certain costs incurred in connection with issuing debt. These costs are being amortized to interest expense on the straight-line method over the term of the related debt.

Gas Balancing

Southwest utilizes the sales method of accounting for over or under deliveries of natural gas. Under this method, Southwest recognizes sales revenue on all natural gas sold. As of December 31, 2001, 2000 and 1999, Southwest was underproduced by approximately 527 MMcf, 557 MMcf and 587 MMcf, respectively.

Income Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced, if necessary, by a valuation allowance for the amount of tax benefits that may not be realized.

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SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income (loss) per share

Southwest has only common stock issued and outstanding. Basic net income (loss) per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Southwest has no potentially dilutive securities, which would require calculation of diluted earnings per share.

Interim Financial Statements

In the opinion of management, the unaudited consolidated financial statements of Southwest as of June 30, 2002 and 2001 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this report pursuant to the rules and regulations of the Securities and Exchange Commission.

Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (“FASB”) issued Statements of Financial Accounting Standards SFAS No. 141 “Business Combinations” and SFAS No. 142 “Goodwill and Other Intangible Assets”. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method and SFAS No. 142 requires that goodwill no longer be amortized to earnings, but instead be reviewed for impairment. There is no impact to Southwest’s financial statements as we have not entered into any business combinations subsequent to June 30, 2001 that required the recording of goodwill or other intangible assets.

In October 2001, FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. Southwest is currently assessing the impact on its financial statements.

In October 2001, the FASB issued SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS No. 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of SFAS No. 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. Southwest adopted the SFAS No. 144 on January 1, 2002. Southwest believes that the impact from SFAS No. 144 on Southwest’s financial position and results of operation should not be significantly different from that of SFAS No. 121.

SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” was issued in April 2002. SFAS No. 145 provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 is effective for Southwest in January 2003. Southwest does not expect the implementation of this standard to affect the presentation of the extraordinary gain associated with the restructuring which was completed in April 2002. Southwest does anticipate however, that the implementation of this standard will require the extraordinary loss associated with

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SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

the Early Extinguishment of debt, which occurred in April 2002, to be presented as an ordinary loss. Southwest is currently evaluating the current and future impacts of SFAS No. 145.

In July 2002, the FASB issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities” which establishes requirements for financial accounting and reporting for costs associated with exit or disposal activities. This standard is effective for exit or disposal activities initiated after December 31, 2002. Southwest is assessing the impacts this could have on its future financial statements.

Reclassifications

Certain reclassifications have been made to the 2001, 2000 and 1999 amounts to conform to the 2002 presentation.

2.    Equity Investment in Partnerships

The investment in partnerships held by Southwest consists of a 15% general partner ownership interest in Southwest Partners II and Southwest Partners III. Southwest Partners II and Southwest Partners III consist entirely of an investment in Basic’s common stock. Southwest, as General Partner in Southwest Partners II and Southwest Partners III, no longer holds an indirect 20% or more interest in Basic and exerts no significant influence over Basic’s operations. Based on a restructuring of Basic’s debt in December 2000, and the subsequent dilution of Southwest’s indirect ownership, the investment in Basic is no longer considered a material investment.

3.    Other Property and Equipment

Other property and equipment, consists of the following (in thousands):

	Years Ended December 31,
	2001		2000
Land	$	2,352	$	2,352
Building and improvements		1,057		1,054
Machinery and equipment		3,362		3,127
Furniture and fixtures		1,553		1,555
		8,324		8,088
Less accumulated depreciation		3,963		3,476
	$	4,361	$	4,612

4.    Exchange Transaction

On March 5, 2002 Southwest entered into an Offer to Exchange and Consent Solicitation with respect to its 10.5% Senior Notes due 2004. The Offer to Exchange and Consent Solicitation closed on April 19, 2002. As part of the Exchange Offer, approximately $114.8 million face amount of the 10.5% Senior Notes plus approximately $2.9 million in accrued but unpaid interest was exchanged for approximately $60.0 million face value of new Variable Interest Senior Notes and 900,000 shares of Southwest’s Class A Common Stock. The value of the 900,000 shares of Class A Common Stock issued was approximately $29.6 million and represents 90% of the voting stock of Southwest after the exchange. The common stock valuation was performed by Friedman, Billings, Ramsey & Co., Inc. (“FBR”) (NYSE:FBR). FBR is a financial holding company for businesses that

F-18

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

provide investment, banking, institutional brokerage, specialized asset management, and banking products and services.

In connection with the exchange Southwest issued 200,000 shares of Special Stock to SRH. The Special shares have no voting rights, no rights to receive dividends or other distributions from Southwest and no rights to participate in any liquidation or dissolution of Southwest. Southwest also issued 100,000 shares of Common Stock to SRH, which represents 10% of Southwest’s issued and outstanding voting share capital. If prior to or on October 19, 2003, Southwest pays in cash in full the New Notes, the Special shares held by SRH will automatically convert on the date of such payment into shares of Common Stock per each share of Special Stock issued and outstanding. Upon conversion of the Special Shares into shares of Common Stock, combined with the 100,000 shares of Common Stock which is currently held by SRH, SRH would then own 25% of Southwest’s issued and outstanding voting share capital. If the New Notes are not paid in cash in full by October 19, 2003, the Special Shares will be deemed canceled, shall be null and void and no further effect. Upon cancellation of the Special Shares, SRH would continue to own only 10% of Southwest’s issued and outstanding voting share capital.

The $60.0 million face value of Variable Interest Senior Notes have a maturity date of June 30, 2004 and are secured by all of Southwest’s assets and is guaranteed by Southwest’s subsidiaries and are junior only in right to payment to the Revolving Credit Agreement due April 30, 2004. Interest on the new notes will begin to accrue on October 15, 2001 (as if the New Notes were issued on such date) at a rate of 10.5% per annum through December 31, 2002, 11.5% from January 1, 2003 through December 31, 2003 and 12.5% thereafter. The $60.0 million Senior Secured Notes impose the same type of restrictive covenants as the old 10.5% Senior Notes due 2004. (See Note 5).

The Exchange qualified as a troubled debt restructuring under SFAS No. 15 “Accounting for Debtors and Creditors for Troubled Debt Restructurings”. As a result, of the application of this accounting standard, the total indebtedness due to the participating 10.5% bondholders, inclusive of accrued and unpaid interest was reduced by the fair market value of 900,000 shares of Class A Common Stock issued by Southwest to the participating bondholders, and the residual balance of the indebtedness was recorded as the new carrying value of the $60 million face value Variable Interest Senior Notes issued as part of the Exchange. Consequently, the $60.0 million face value of the Variable Interest Senior Notes is recorded on Southwest’s balance sheet at $75.1 million. The additional carrying value of the debt in excess of the face value represents the accrual of future interest expense due on the face value of the Variable Interest Senior Notes. Therefore all cash payments under the terms of the new Variable Interest Senior Notes will be accounted for as a reduction of the carrying amount of the new Variable Interest Senior Notes, and no interest expense shall be recognized on the new Variable Interest Senior Notes for any period between the restructuring and maturity of the new Variable Interest Senior Notes. The extraordinary gain net of fees and taxes is calculated as follows (in millions):

Carrying value of 10.5% Senior Notes prior to Restructuring	$	114.8
Net accrued and unpaid interest on total debt forgiven		2.9
Less
Unamortized discount on the 10.5% Senior Notes		0.6
Total carrying value of New Variable Interest Notes		75.1
Fair Value of 900,000 shares of common stock issued to 10.5% holders		29.6
Fees paid to consummate the restructuring		1.3
Noncash writeoff of unamortized original issue costs of the 10.5% Senior Notes		1.6
Income tax provision		3.2
Total extraordinary gain net of fees and taxes	$	6.3

F-19

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The extraordinary gain, net of tax, per share is approximately $13.67.

As part of the April 19, 2002 exchange transaction, Southwest exchanged the 6% note receivable from an officer of Southwest and stockholder of SRH plus all accrued and unpaid interest on the note since December 1, 2001, for 123,710 shares of SRH common stock, which collateralized the Note. The total principal and accrued and unpaid interest on the Note at the time of the exchange was approximately $1.6 million. The value assigned to the SRH stock was approximately $0.6 million. The difference between the carrying value of the Note and the value of the stock, or approximately $1.0 million, was expensed as general and administrative expense in the current period.

5.    Long-term Debt

Long-term debt consists of the following (in thousands):

	June 30, 2002		December 31,
			2001		2000
10.5% Senior Notes, interest payable semi-annually, due October 15, 2004, net of discount of $45 and $732, respectively	$	8,825	$	122,953	$	122,740
Variable Interest Senior Notes, interest payable semi-annually, due June 30, 2004		75,069		—		—
Revolving Loan Facility with variable rate interest, due August 2003. Collateralized by oil and gas properties		—		49,970		50,000
Revolving Credit Agreement with variable rate interest, due April 30, 2004. Collateralized by oil and gas properties		55,000		—		—
Other		1,210		1,176		1,123
		140,104		174,099		173,863
Less current maturities		18,204		145		92
	$	121,900	$	173,954	$	173,771

10.5% Senior Notes

In October 1997, Southwest issued $200 million aggregate principal amount of 10.5% Senior Notes due October 15, 2004 (the “Notes”). The Notes were sold at a discount and interest is payable April 15 and October 15 of each year, commencing April 15, 1998. The Notes are general unsecured senior obligations of Southwest and rank equally in right of payment with all other senior indebtedness of Southwest and senior in right of payment of all existing future subordinated indebtedness of the issuer. Net proceeds from the issuance of the Notes were used primarily to repay existing debt of approximately $84.0 million, purchase oil and gas properties for approximately $72.3 million, dividend SRH approximately $10.0 million, invest $1.7 million in an affiliate, with the remaining balance used for working capital.

The Indenture imposes certain limitations on the ability of Southwest and its restricted subsidiaries to, among other things, incur additional indebtedness or issue disqualified capital stock, make payments in respect to capital stock, enter into transactions with affiliates, incur liens, sell assets, change the nature of its business, merge or consolidate with any other person and sell, lease, transfer or otherwise dispose of substantially all of its properties or assets. The indenture requires Southwest to repurchase notes under certain circumstances with the excess cash of certain asset sales. The limitations are subject to a number of important qualifications and exceptions. Southwest must report to the Trustee on compliance with such limitations on a quarterly basis.

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SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Variable Interest Senior Notes

On March 5, 2002 Southwest entered into an Offer to Exchange and Consent Solicitation with respect to its 10.5% Senior Notes due 2004. The Offer to Exchange and Consent Solicitation closed on April 19, 2002. As part of the Exchange Offer, approximately $114.8 million face amount of the 10.5% Senior Notes plus all net accrued and unpaid interest since October 15, 2001, of approximately $2.9 million, was exchanged for approximately $60.0 million face value of new Variable Interest Senior Notes described below, and 900,000 shares of Southwest’s Class A Common Stock which represents approximately 90% of the voting stock of Southwest after the exchange. The Indenture continues to impose certain limitations on Southwest and its restricted subsidiary.

The $60.0 million face value Variable Interest Senior Notes have a maturity date of June 30, 2004 and are secured by all of Southwest’s assets and is guaranteed by Southwest’s subsidiaries and are junior only in right to payment to the Revolving Credit Agreement due April 30, 2004. Interest on the new notes will begin to accrue on October 15, 2001 (as if the New Notes were issued on such date) at a rate of 10.5% per annum through December 31, 2002, 11.5% from January 1, 2003 through December 31, 2003 and 12.5% thereafter. In accordance with SFAS No. 15 “Accounting for Debtor and Creditors for Troubled Debt Restructurings” all the future interest costs associated with the $60.0 million face of Variable Interest Senior Notes, of approximately $15.1 million, were added to the carrying value of the Notes and therefore all cash payments on the Notes shall be accounted for as reductions to the carrying amount of the Notes, and no interest expense shall be recognized on the Notes for any period between the restructuring and the maturity of the Notes. The new Variable Interest Senior Notes impose the same type of restrictive covenants as the old 10.5% Senior Notes due 2004. As of June 30, 2002, approximately $7.9 million is classified as short-term debt with the remaining $67.2 million being classified as long-term debt. (See Note 4 above for a more detailed discussion of the Exchange Transaction.)

Revolving Loan Facility

On August 17, 2000, Southwest completed a refinancing of its Revolving Loan Facility in the amount of $50.0 million with a new lender. The Amended and Restated Loan and Security Agreement allowed for a prime rate of interest (5.5% at December 31, 2001) plus one and one-half percent (1.5%), with a minimum rate of interest of 9.0%, which was in effect for Southwest as of December 31, 2001. The Revolving Loan Facility imposed certain limitations on the ability of Southwest to, among other things, incur additional indebtedness or issue disqualified capital stock, make payments in respect to capital stock, enter into transactions with affiliates, incur liens, sell assets, change the nature of its business, merge or consolidate with any other person and sell, lease, transfer or otherwise dispose of substantially all of its properties or assets. Southwest, in recording the refinancing of the Revolving Loan Facility, recorded an extraordinary loss from early extinguishment of debt in the amount of approximately $1.4 million.

Southwest was in violation of certain covenants and compliance requirements as of December 31, 2001. Subsequent to December 31, 2001, the Bank waived such violations.

Southwest entered into a Revolving Credit Agreement as discussed below which provided for the refinancing of the Revolving Loan Facility.

Revolving Credit Agreement

On April 19, 2002 Southwest entered into a Revolving Credit Agreement with a syndicate of Banks (the “Lenders”). The Credit Agreement provides for an aggregate $80 million senior secured revolving line of credit. The Agreement is secured with the assets of Southwest and is guaranteed by Southwest’s subsidiaries. The Credit Agreement has a maturity date of April 30, 2004.

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SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The initial borrowing base on April 19, 2002 was $59.0 million and the monthly commitment reduction commences on October 1, 2002, at which date the monthly commitment reduction will be $1.125 million per month. Subsequent redeterminations of the borrowing base and the monthly commitment reduction shall be made by the Lenders semi-annually on April 30 and October 31 of each year beginning October 1, 2002, or as unscheduled redeterminations at the sole discretion of the Lenders. Southwest has the right to request an unscheduled redetermination between each borrowing base redetermination.

In order to determine the borrowing base, Southwest shall provide to the Lenders an engineering report in form and substance reasonably satisfactory to the Agent, said engineering report to utilize economic and pricing parameters used by the Agent as established from time to time, together with such other information, reports and data concerning the value of Southwest’s and Guarantors’ oil and gas properties. Lenders shall have the right to request at any time, and from time to time an engineering report covering all of Southwest’s and Guarantors’ oil and gas properties and said report to be prepared by an independent petroleum engineering firm acceptable to Agent. Each Lender shall determine the amount of the borrowing base and the monthly commitment reduction based upon the loan collateral value which such Lender in its sole discretion (using such methodology, assumptions and discount rates as such Lender customarily uses in assigning collateral value to oil and gas properties, oil and gas gathering systems, gas processing and plant operations) assigns to such oil and gas properties of Southwest at the time in question and based upon such credit factors consistently applied (including without limitation, the assets, liabilities, cash flow, business, properties, prospects, management and ownership of Southwest and its affiliates) as such Lender customarily considers in evaluating similar oil and gas credits.

All outstanding balances under the Credit Agreement may be designated, at Southwest’s option, as either Prime Rate or LIBOR Rate options, provided that no more than four LIBOR rate options may be outstanding at any given time. The Prime rate option is the greater of (i) the rate publicly announced from time to time by the Agent as its Prime Rate or (ii) the Federal Funds rate plus .50% per annum. The LIBOR Rate option is equal to LIBOR plus 225 to 275 basis points depending on the borrowing base usage percentage. Both options will accrue on the basis of a 360-day year.

The purpose of the Credit Agreement is to provide funds for (i) the refinancing of the Revolving Loan Facility due August 2003 (The refinance of the Revolving Loan Facility funded on April 22, 2002) (ii) to purchase oil and gas properties and (iii) working capital, and letters of credit. Letters of Credit may be issued subject to availability under the Credit Agreement and the total of all outstanding letters of credit may not exceed $5.0 million in aggregate and the term shall not exceed 12 months or the maturity date, whichever comes first. As of June 30, 2002, Southwest had drawn approximately $55.0 million, issued letters of credit for approximately $2.9 million and had approximately $1.1 million remaining available.

Southwest paid the Lenders fees and expenses in connection with the Credit Agreement of approximately $1.8 million and paid approximately $1.0 million in prepayment penalties on the early exit of the Revolving Loan Facility due August 2003. Southwest wrote off approximately $1.1 million of unamortized original issue costs associated with the old Revolving Loan Facility.

The Credit Agreement imposes certain limitations on the ability of Southwest and its Subsidiary Guarantors to, among other things, incur additional indebtedness or issue disqualified capital stock, make payments in respect to capital stock, enter into transactions with affiliates, incur liens, sell assets, change the nature of its business, merge or consolidate with an other person or renew, extend, modify or amend the indentures.

Southwest’s new credit agreement also includes restrictive covenants related to the maintenance of quarterly cash flow and interest coverage. Southwest believes it will be able to meet these quarterly covenants over the next twelve months based on its current financial projections. However, if circumstances were to change and an

F-22

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

event of default were to occur, Southwest would be required to renegotiate with its current lender or secure other suitable secured financing. No assurance can be given that Southwest would be able to accomplish such refinancing.

Southwest was in violation of the Funded Debt Coverage Ratio at June 30, 2002. Funded Debt is defined in the Revolving Credit Agreement, as the face amount owed on the 10.5% Senior Notes, the Variable Interest Senior Notes and the Revolving Credit Agreement. On September 10, 2002, this violation was waived by the Banks and the credit agreement was amended to delete the Funded Debt Coverage Ratio covenant in its entirety. Also, as part of the amendment, the borrowing base was reviewed and it was determined that, effective September 1, 2002, the borrowing base shall be $60.0 million and the monthly commitment reduction shall be $0 until such time as it may change based on future redeterminations. The next redetermination is scheduled for April 30, 2003, however, an unscheduled redetermination can take place prior to this date at the sole discretion of the lenders.

Extinguishment of Debt

On April 22, 2002, Southwest refinanced its Revolving Loan Facility and recorded an extraordinary loss from early extinguishment of debt in the amount of approximately $2.1 million. Southwest recognized an income tax benefit on the extraordinary loss of $0.7 million. The extraordinary loss per share is approximately $3.07.

Aggregate maturities of all long-term debt as of June 30, 2002, are as follows (in thousands):

2003	$	18,204
2004		112,159
2005		8,915
2006		17
2007		19
Thereafter		835
		140,149
Less unamortized discount		45
	$	140,104

Aggregate maturities of all long-term debt as of December 31, 2001, are as follows (in thousands):

2002	$	145
2003		50,092
2004		123,723
2005		17
2006		19
Thereafter		835
		174,831
Less unamortized discount		732
	$	174,099

6.    Liquidity

Southwest has a highly leveraged capital structure with approximately $124.1 million of principal due between June 30, 2002 and December 31, 2004. (See Note 5 above for a more detailed discussion of debt

F-23

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

maturities) Southwest is constantly monitoring its cash position and its ability to meet its financial obligations as they become due, and in this effort, is continually exploring various strategies for addressing its current and future liquidity needs. Southwest regularly pursues and evaluates recapitalization strategies and acquisition opportunities (including opportunities to engage in mergers, consolidations or other business combinations) and at any given time may be in various stages of evaluating such opportunities.

Based on current production, commodity prices and cash flow from operations, Southwest has adequate cash flow to fund debt service, developmental projects and day to day operations, but it is not sufficient to build a cash balance which would allow Southwest to meet its debt principal maturities scheduled for 2004. Therefore, Southwest must renegotiate the terms of its various obligations or seek new lenders or equity investors in order to meet its financial obligations, specifically those maturing in 2004. Southwest would also consider disposing of certain assets in order to meet its obligations.

There can be no assurance that Southwest’s debt restructuring efforts will be successful or that the debt holders will agree to a course of action consistent with Southwest’s requirements in restructuring the obligations. Furthermore, there can be no assurance that the sale of assets can be successfully accomplished on terms acceptable to Southwest.

7.    Income Taxes

The U.S. Federal tax provision (benefit) attributable to income (loss) before income taxes, minority interest and extraordinary item consists of the following (in thousands):

	December 31,
	2001			2000			1999
Current	$	—		$	—		$	—
Deferred
Benefit of net operating loss carryforward		(2,936	)		(1,281	)		(8,020	)
Other deferred items		3,103			8,161			9,845
Change in valuation allowance		5,833			(12,880	)		(1,825	)
	$	6,000		$	(6,000	)	$	—

Reconciliation’s between the amount determined by applying the U.S. federal statutory rate to income (loss) before income taxes, minority interest and extraordinary item with the income tax provision (benefit) is as follows (in thousands):

	December 31,
	2001		2000			1999
Computed “expected” tax expense using the U.S. federal statutory rate	$	58	$	3,297		$	(2,592	)
Meals and entertainment		10		20			7
Change in valuation allowance		5,833		(12,880	)		(1,825	)
Effect of extraordinary item		—		4,441			4,944
Other		99		(878	)		(534	)
Provision (benefit) for income taxes	$	6,000	$	(6,000	)	$	—

The income tax provision for the six months ended June 30, 2002 was $2,501,000.

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SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands):

	December 31,
	2001			2000
Deferred tax assets:
Net operating loss carryforwards	$	21,964		$	19,182
Alternative minimum tax credit carryforwards		132			170
Charitable contributions carryforward		29			—
Depletion carryforward		369			—
General business credit		289			—
Receivables		145			—
Other		126			335
Other long term assets		3,357			2,624
Other long term liabilities		151			262
Total deferred tax assets		26,562			22,573
Less valuation allowance		(19,458	)		(13,625	)
Total gross deferred tax assets		7,104			8,948
Deferred tax liabilities:
Oil and gas properties		(6,275	)		(1,740	)
Other property and equipment		(829	)		(1,096	)
Receivables		—			(112	)
Total gross deferred tax liabilities		(7,104	)		(2,948	)
Net deferred tax asset (liability)	$	—		$	6,000

A valuation allowance is provided when it is more likely than not that some portion of the deferred tax assets will not be realized. The valuation allowance relates primarily to the uncertainty of the realizability of Southwest’s carryforwards, the amount of the valuation allowance could be reduced if estimates of future taxable income during the carryforward period are increased. During 2001, based on management’s estimates of likely future taxable income, Southwest increased the valuation allowance resulting in no net deferred tax asset at December 31, 2001.

As of December 31, 2001, Southwest had net operating loss carryforwards for U.S. federal income tax purposes of approximately $62,750,000, which were available to offset future regular taxable income, if any. The net operating loss carryforwards expire in various periods from 2018 through 2021. Southwest has alternative minimum tax credit carryforwards totaling $132,000 to offset regular income tax, which have no scheduled expiration date. Due to the Exchange Transaction in 2002 (See Note 4) there was a change in control, which resulted in a Section 382 limitation of 100% of the amount of available loss carryforwards Southwest previously had available for future use. As of June 30, 2002, Southwest does not anticipate having any of its previously reported net operating loss carryforwards available to offset future taxable income.

8.    Profit Sharing Plan

On January 1, 1991, Southwest adopted an employee profit sharing plan that is intended to provide participating employees with additional income upon retirement. Employees may contribute between 1% and 15% of their base salary up to a maximum of $10,500 for the years 2001 and 2000 and $10,000 for the year 1999.

F-25

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the years ended December 31, 2001, 2000 and 1999, Southwest matched 20% of the employees’ contributions. For the year ended December 31, 2002, Southwest will match 20% of the employees’ contributions. For subsequent years, Southwest will make contributions to the plan on a discretionary basis.

Employee contributions are fully vested at all times. Employer contributions are fully vested upon retirement or after five years of service. For the years ended December 31, 2001, 2000 and 1999, Southwest contributed approximately $53,000, $56,000 and $55,000, respectively, to the plan.

9.    Stockholders’ Equity

The Company, on April 19, 2002, closed The Offer to Exchange and Consent Solicitation. As part of the Exchange Offer, approximately $114.8 million face amount of the 10.5% Senior Notes plus all accrued and unpaid interest since October 15, 2001, was exchanged for approximately $60.0 million face of new Variable Interest Senior Notes and 900,000 shares of Southwest’s Class A Common Stock, valued at $28.4 million, net of $1.2 million in offering cost, which represents approximately 90% of the voting stock of Southwest after the exchange. The common stock valuation was performed by Friedman, Billings, Ramsey & Co., Inc., (“FBR”) (NYSE:FBR). FBR is a financial holding company for businesses that provide investment, banking, institutional brokerage, specialized asset management, and banking products and services.

In connection with the exchange Southwest issued 200,000 shares of Special Stock to SRH. The Special shares have no voting rights, no rights to receive dividends or other distributions from Southwest and no rights to participate in any liquidation or dissolution of Southwest. Southwest also issued to SRH, in exchange for its 100 shares of $.10 par value common stock, 100,000 shares of $.01 par value Common Stock, which represents 10% of Southwest’s issued and outstanding voting share capital. If prior to or on October 19, 2003, Southwest pays in cash in full the New Notes, the Special shares held by SRH will automatically convert on the date of such payment into shares of Common Stock per each share of Special Stock issued and outstanding. Upon conversion of the Special Shares into shares of Common Stock, combined with the 100,000 shares of Common Stock which is currently held by SRH, SRH would then own 25% of Southwest’s issued and outstanding voting share capital. If the New Notes are not paid in cash in full by October 19, 2003, the Special Shares will be deemed canceled, shall be null and void and no further effect. Upon cancellation of the Special Shares, SRH would continue to own only 10% of Southwest’s issued and outstanding voting share capital. The special shares were assigned no value upon issuance. If, prior to October 19, 2003, Southwest pays in full the new notes and the special shares are converted to common stock, then the fair value of the shares at that time will be treated as compensation expense to the extent that the beneficiaries are also management of Southwest.

During 1994, Southwest was issued a 6% note from an officer of Southwest and stockholder of SRH. The note requires semi-monthly payments of $5,500 and is collateralized by SRH’s common stock held by the stockholder.

As part of the April 19, 2002 exchange transaction, Southwest exchanged the 6% note receivable from an officer of Southwest and stockholder of SRH plus all accrued and unpaid interest on the note since December 1, 2001, for 123,710 shares of SRH common stock, which collateralized the Note. The total principal and accrued and unpaid interest on the Note at the time of the exchange was approximately $1.6 million. The value assigned to the SRH stock was approximately $0.6 million. The difference between the carrying value of the Note and the value of the stock, or approximately $1.0 million, was expensed as general and administrative expense in the current period.

F-26

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In anticipation of the above noted transaction, the Amended and Restated Certificate of Incorporation was approved by the Board of Directors of Southwest on February 19, 2002, and by written consent of the sole stockholder of Southwest, dated April 19, 2002. Under the Amended and Restated Certificate of Incorporation, Southwest has the authority to issue 16,100,000 shares of Capital Stock, of which, 10,000,000 shares are designated as Common Stock, $.01 par value per share, 900,000 shares are designated as Class A Common Stock, $.01 par value per share, 200,000 shares are designated as Special Stock, $.01 par value per share and 500,000 shares are designated Preferred Stock, $1.00 par value per share.

Each holder of shares of Class A Common Stock shall have one vote for each share of Class A Common Stock held and shall vote with the Common Stock with respect to all matters submitted to the stockholders for a vote. Holders of the Class A Common Stock are entitled to elect six of the seven members of Southwest’s Board of Directors while the holders of the Common Stock are entitled to elect one member of the seven member Board.

The Class A Common Stock will automatically convert into shares of Common Stock on the basis of one share of Common Stock for each share of Class A Common Stock issued and outstanding (a) immediately prior to (i) the closing of a firm commitment underwritten initial public offering by Southwest of Southwest’s Common Stock resulting in the receipt of at least $10.0 million in net proceeds, pursuant to an effective registration statement filed under the Securities Act of 1933, as amended, or (ii) any other transaction pursuant to which Southwest’s Common Stock becomes listed on a national securities exchange or authorized for quotation on an inter-dealer quotation system or (b) immediately after H.H. Wommack, III (i) no longer directly or indirectly has beneficial ownership of 50% or more of the outstanding shares of Southwest’s Common Stock and (ii) resigns, is removed or otherwise no longer serves as an executive officer of Southwest.

Except as set forth above, the rights, including voting rights, preferences and limitations of the shares of Class A Common Stock are identical to shares of Common Stock.

10.    Commitments and Contingencies

The partnership agreements relating to certain limited partnerships for which Southwest serves as managing general partner provide for Southwest to offer to repurchase such limited partner units. Under the terms of three of the partnership agreements, Southwest is obligated to repurchase a maximum of $100,000 annually of the units of limited partnerships’ interests originally outstanding. Under the terms of nine other partnership agreements, Southwest’s obligation to repurchase units in any one year is limited to 10% of the capital contributed by all of the respective limited partners. The repurchase price is based on the discounted future revenues from oil and gas reserves of the respective partnership and the value of other partnership assets. Such amounts required for repurchase in connection with the acceptance by a portion of the limited partners is approximately $3,112,000 at December 31, 2001. The total amount of limited partner unit repurchases for the years ended December 31, 2001 and 2000 was approximately $2,669,000 and $722,000, respectively.

Southwest is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require Southwest to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are expensed when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

F-27

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Management recognizes a financial exposure that may require future expenditures presently existing for oil and gas properties and other operations. Other long-term liabilities at December 31, 2001 and 2000 include $459,000 and $663,000 respectively, for estimated future remedial actions and cleanup costs. Included in 2001 operating results, is a $204,000 revision for change in estimate for future remedial action and clean up costs. As of December 31, 2001, Southwest has not been fined, cited or notified of any environmental violations, which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, management does recognize that by the very nature of its business, significant costs could be incurred to bring Southwest into total compliance. The amount of such future expenditures is not readily determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of Southwest’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Southwest’s properties. It is reasonably possible this estimate could change materially in the near term.

Southwest has issued severance agreements to several members of its management team. These severance agreements provide for six months to one year annual salary as severance, upon termination due to change in control (as defined by the agreement). Southwest’s contingent liability under the severance agreements at December 31, 2001 is approximately $655,000.

In the normal course of its business, Southwest is subject to pending or threatened legal actions; in the opinion of management, any such matters will be resolved without material effect on Southwest’s operations, cash flow or financial position.

11.    Commodity Hedging and Derivative Financial Instruments

Southwest, from time to time, uses option contracts to mitigate the volatility of price changes on commodities Southwest produces and sells as well as to lock in prices to protect the economics related to certain capital projects.

On September 6, 2000, Southwest entered into a floor option, which provided Southwest with a crude oil price floor. The contract was for the period January 1, 2001 through December 31, 2001. The option was for a notional amount of 1,100 Bbls of oil a day at a floor price of $25, based on NYMEX Light Sweet Crude. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $466,000.

On October 11, 2000, Southwest entered into a floor option, which provided Southwest with a crude oil price floor. The contract was for the period January 1, 2001 through December 31, 2001. The option was for a notional amount of 500 bbls of oil a day at a floor price of $27, based on NYMEX Light Sweet Crude. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $224,000.

On November 20, 2000, Southwest entered into a floor option, which provided Southwest with a crude oil price floor. The contract was for the period June 1, 2001 through May 31, 2002. The option was for a notional amount of 1,000 Bbls of oil a day at a floor price of $22, based on NYMEX Light Sweet Crude. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $310,000.

On December 1, 2000, Southwest entered into a floor option, which provided Southwest with a natural gas price floor. The contract was for the period June 1, 2001 through May 31, 2002. The option was for a notional

F-28

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

amount of 3,325 MMBtu of natural gas a day at a floor price of $3.00, based on NYMEX Henry Hub. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $140,000.

On December 8, 2000, Southwest entered into a floor option, which provided Southwest with a natural gas price floor. The contract was for the period April 1, 2001 through March 31, 2002. The option was for a notional amount of 1,700 MMBtu of natural gas a day at a floor price of $4.50, based on NYMEX Henry Hub. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $416,000.

On February 14, 2001, Southwest entered into a floor option, which provided Southwest with a natural gas price floor. The contract was for the period April 1, 2001 through March 31, 2002. The option was for a notional amount of 3,000 MMBtu of natural gas a day at a floor price of $4.25, based on NYMEX Henry Hub. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $296,000.

On February 14, 2001, Southwest entered into a floor option, which provided Southwest with a natural gas price floor. The contract was for the period March 1, 2001 through August 31, 2001. The option was for a notional amount of 5,000 MMBtu of natural gas a day at a floor price of $4.50, based on NYMEX Henry Hub. The agreement was to be calculated on a monthly basis with payments to be made no later than five business days after calculating period. The cost of the floor was approximately $156,000.

In May 2002, Southwest entered into a collar, which provides Southwest with a natural gas price ceiling and floor. The contract is for the period June 2002 through May 2003. The collar is for a notional amount of 6,000 MMBtu of natural gas a day at a ceiling price of $5.70 and a floor price of $3.00, based on NYMEX Henry Hub.

In May 2002, Southwest entered into a collar, which provides Southwest with a crude oil price ceiling and floor. The contract is for the period June 2002 through May 2003. The collar is for a notional amount of 1,500 Bbls of oil a day at a ceiling price of $27.25 and a floor price of $21.00, based on NYMEX Light Sweet Crude.

Southwest has not elected to use hedge accounting on the above noted instruments and therefore, effective January 1, 2001, has marked to market these items and recorded all gains and losses through earnings.

Enron Bankruptcy

In the fourth quarter of 2001, Southwest and many others throughout the oil and gas industry were affected by the bankruptcy filing of Enron Corp. and subsidiaries. All of the Commodity Option Contracts referred to above, which were entered into during 2001 or 2000, were with Enron. As a result of Southwest’s evaluation of the increased credit risk associated with Enron pursuant to Enron’s bankruptcy filing, Southwest set up an allowance for all amounts owed to Southwest by Enron, which was approximately $1.1 million and marked to market all remaining Enron related Commodity Option Contracts by setting up an allowance for the fair market value of the contracts as of December 1, 2001 of approximately $2.1 million. The total charge to other expense during the fourth quarter of 2001, relating to the Enron bankruptcy was approximately $3.2 million.

12.    Comprehensive Income

Comprehensive income consists of net income (loss), as reflected on the consolidated statement of operations, and other gains and losses affecting stockholders’ equity that are excluded from net income (loss).

F-29

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Southwest recorded other comprehensive income during the first quarter of 2001. Total comprehensive income for the six months ended June 30, 2002 and the year ended December 31, 2001 is as follows (in thousand):

	2002			2001
Net income (loss)	$	3,821		$	(5,834	)
Other comprehensive income, net of tax:
Transition adjustment on implementation of SFAS 133—January 1, 2001		—			1,030
Reclassification of transition adjustment		(81	)		(949	)
Other comprehensive income		(81	)		81
Comprehensive income (loss)	$	3,740		$	(5,753	)

13.    Related Party Transactions

Southwest is the managing general partner for several public and private oil and gas limited partnerships, with an officer of Southwest also serving as a general partner for certain of the limited partnerships. As is usual in the oil and gas industry, the operator is paid an amount for administrative overhead attributable to operating such properties and management fees attributable to serving as managing general partner. As provided for in the partnership agreements, such amounts paid by the partnerships to Southwest approximated $2,798,000, $3,254,000 and $3,515,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Included in the 1999 amount, an affiliate of Southwest paid management fees of approximately $136,000, for the year ended December 31, 1999. In addition, Southwest and certain officers and employees may have an interest in some of the partnership properties.

An affiliate of Southwest borrowed $1.2 million in 1998. The unsecured note receivable accrued interest monthly at an interest rate of 20% until December 31, 1999. In December 1999, Southwest restructured the note by rolling the balance of the note at December 31, 1999 of approximately $707,000 plus some other miscellaneous receivables of approximately $148,000, into a new note aggregating approximately $855,000. The new note accrued interest monthly at 10.5% with monthly payments of $10,000 and a balloon payment of $810,000 due in June 2001. The note was again restructured in May 2001 with the new terms calling for six monthly payments of $12,000, twelve monthly payments of $15,000 and a balloon payment in December of 2002 of any unpaid principal and accrued interest, which should be approximately $675,000. The affiliate has not been able to make any payments on the note since June 2001. The balance of the note at December 31, 2001 is approximately $798,000. The total amount of the note net of an allowance of $397,000 has been reclassified to long-term and is recorded in other assets on the consolidated balance sheet. The affiliate continues to experience financial difficulties due to their highly leveraged capital structure. The affiliate’s management is currently in the process of renegotiating where possible the terms of the affiliate’s various obligations with its lenders and/or seeking new lenders or equity investors. Additionally, the affiliate’s management would consider disposing of certain assets in order to meet its obligations. In spite of the affiliate’s current financial difficulties Southwest believes the note, net of allowance, is collectible.

An affiliate of Southwest performs various oilfield services for limited partnerships managed by Southwest. Such services aggregated $194,000, $309,000 and $365,000 for the years ended December 31, 2001, 2000 and 1999. The same affiliate performed services for Southwest that aggregated approximately $930,000, $290,000 and $313,000, for the years ended December 31, 2001, 2000 and 1999. In August 2000, Southwest made a prepayment to the affiliate in the amount of $975,000 for oil and gas services to be provided in the future, as of December 31, 2001, the prepayment had been fully utilized.

F-30

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On August 11, 2000, Southwest invested $100,000 in a Web-based company through a Private Placement Offering. Southwest holds 200,000 shares of Series A Preferred Stock. The President of the Web-based company is the brother of H. H. Wommack, III, President of Southwest. As of June 30, 2002, the investment has been marked to market and an allowance of $100,000 set up to bring the carrying value to zero.

H. H. Wommack, III, President and Chief Executive Officer of Southwest, serves as a general partner of twenty four limited partnerships sponsored by Southwest since 1983, and he holds an interest in these partnerships of approximately 1%. Effective December 31, 2001, Southwest repurchased, for approximately $296,000, various general partner units from Mr. Wommack, representing his 1% interest in six limited partnerships. The partnership units purchased from Mr. Wommack were valued using the same methodology used to value limited partner unit repurchases per the partnership agreements.

14.    Disclosures About Fair Value of Financial Instruments

The carrying amount of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, other current assets and other current liabilities approximates fair value because of the short maturity of these instruments.

The fair value of Southwest’s 10.5% Senior Notes is estimated based on the quoted market price for the notes.

	2001				2000
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
10.5% Senior notes, net of discount $732 and $945, respectively	$	122,953	$	106,567	$	122,740	$	104,329

Based on the borrowing rates currently estimated to be available to Southwest for loans with similar terms, the fair value of all other long-term debt approximates the carrying amount as of December 31, 2001 and 2000.

The fair market value of the oil and gas floor options at December 31, 2001 was written down to zero based on an evaluation by management of Enron’s bankruptcy proceedings (see Note 11).

15.    Supplemental Financial Data—Oil and Gas Producing Activities (unaudited):

The following information is presented in accordance with Statement of Financial Accounting Standards No. 69, “Disclosure about Oil and Gas Producing Activities,” (SFAS No. 69), except as noted.

Costs incurred in connection with oil and gas producing activities are as follows (in thousands):

	June 30, 2002		Years ended December 31,
			2001		2000		1999
Acquisition of properties	$	129	$	8,120	$	1,318	$	417
Exploration costs		340		536		476		76
Development costs		1,681		15,262		8,770		3,195
Total costs incurred	$	2,150	$	23,918	$	10,564	$	3,688

F-31

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Results of operations for oil and gas producing activities are as follows (in thousands):

	June 30, 2002		Years ended December 31,
			2001		2000		1999
Revenues	$	18,775	$	50,991	$	54,263	$	31,425
Production costs		7,054		17,798		15,153		10,833
Depletion		3,206		9,681		4,992		4,901
		8,515		23,512		34,118		15,691
Income tax provision		2,895		7,994		11,600		5,335
Results of operations from oil and gas producing activities (excluding corporate overhead)	$	5,620	$	15,518	$	22,518	$	10,356

Reserve Quantity Information

The estimates of Southwest’s proved oil and gas reserves, which are located in the United States, are based on evaluations reviewed by independent petroleum engineers. Reserves were estimated in accordance with guidelines established by the U.S. Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. The reserve estimates at December 31, 2001 assume an average oil price of $18.44 per Bbl (reflecting adjustments for oil quality and gathering and transportation costs) and an average gas price of $2.36 per Mcf (reflecting adjustments for BTU content, gathering and transportation costs and gas processing and shrinkage).

F-32

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data, engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with the changes in prices and operating costs. Southwest emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change, as additional information becomes available in the future.

	Oil and Condensate (MBbls)		Natural Gas (MMcf)		Barrels of Oil Equivalent (MBOE)
Total Proved Reserves:
Balance January 1, 1999	20,944		58,273		30,656
Purchase of minerals-in-place	261		1,329		483
Sales of minerals-in-place	(1,704	)	(2,751	)	(2,163	)
Revisions of previous estimates	6,633		12,854		8,775
Production	(1,306	)	(4,627	)	(2,077	)
Balance, December 31, 1999	24,828		65,078		35,674
Purchase of minerals-in-place	82		580		179
Sales of minerals-in-place	(8	)	(18	)	(11	)
Revisions of previous estimates	2,131		9,518		3,717
Production	(1,236	)	(4,784	)	(2,033	)
Balance, December 31, 2000	25,797		70,374		37,526
Purchase of minerals-in-place	370		4,950		1,195
Sales of minerals-in-place	(11	)	(2	)	(11	)
Revisions of previous estimates	(4,992	)	4,580		(4,229	)
Production	(1,227	)	(5,119	)	(2,080	)
Balance, December 31, 2001	19,937		74,783		32,401
Purchase of minerals-in-place	265		2,893		747
Sales of minerals-in-place	(61	)	(55	)	(70	)
Revisions of previous estimates	904		2,777		1,367
Production	(561	)	(2,381	)	(958	)
Balance, June 30, 2002	20,484		78,017		33,487
Total proved developed reserves
January 1, 1999	12,006		37,481		18,253
December 31, 1999	16,618		43,023		23,789
December 31, 2000	18,161		46,592		25,926
December 31, 2001	14,274		50,251		22,649
June 30, 2002	15,001		50,503		23,418

F-33

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing discounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

	June 30, 2002			December 31,
				2001			2000			1999
	(in thousands)
Future cash inflows	$	745,262		$	544,205		$	1,342,066		$	727,615
Future production costs		(261,860	)		(212,849	)		(363,108	)		(237,142	)
Future development cost		(46,095	)		(46,214	)		(51,914	)		(47,212	)
Future net cash flows before income taxes		437,307			285,142			927,044			443,261
Future income tax expense		(125,783	)		(53,417	)		(274,566	)		(103,067	)
Future net cash flows		311,524			231,725			652,478			340,194
10% annual discount for estimated timing of cash flows		(158,951	)		(113,660	)		(319,246	)		(164,634	)
Standardized measure of discounted future net cash flows	$	152,573		$	118,065		$	333,232		$	175,560

Southwest plans to fund its capital expenditures budget through cash flow from operations based on current oil and gas pricing and estimated results of current and future capital projects.

F-34

SOUTHWEST ROYALTIES,  INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

	June 30, 2002			December 31,
				2001			2000			1999
	(in thousands)
Sales of oil and gas produced, net of production costs	$	(11,721	)	$	(33,193	)	$	(39,110	)	$	(20,592	)
Net change in sales prices net of production costs		66,050			(308,700	)		218,763			116,644
Extensions and discoveries, net of future production and development costs		—			—			—			—
Revisions to estimated future development costs		60			(1,748	)		(5,903	)		(4,059	)
Purchases of minerals-in-place		4,759			20,181			2,129			1,866
Revisions of previous quantity estimates		10,218			(20,092	)		49,574			60,317
Accretion of discount		14,346			47,346			22,875			7,190
Net change in income taxes		(40,562	)		114,836			(87,037	)		(53,188	)
Sales of minerals-in-place		(112	)		(97	)		(62	)		(5,685	)
Changes in production rates, timing and other		(8,530	)		(33,700	)		(3,557	)		1,167
		34,508			(215,167	)		157,672			103,660
Discounted future net cash flows—
Beginning of period		118,065			333,232			175,560			71,900
End of period	$	152,573		$	118,065		$	333,232		$	175,560

16.    Subsequent Events

In July 2002, Southwest entered into a collar, which provides Southwest with a natural gas price ceiling and floor. The contract is for the period June 2003 through August 2003. The collar is for a notional amount of 5,500 MMBtu of natural gas a day at a ceiling price of $4.90 and a floor price of $3.00, based on NYMEX Henry Hub.

In July 2002, Southwest entered into a collar, which provides Southwest with a crude oil price ceiling and floor. The contract is for the period June 2003 through August 2003. The collar is for a notional amount of 1,300 Bbls of oil a day at a ceiling price of $27.60 and a floor price of $21.00, based on NYMEX Light Sweet Crude.

On October 1, 2002, Southwest entered into employment agreements with three executive officers. If Southwest terminates the Executives without cause, and such termination is not due to disability, or death, or if the Executives terminate their employment for Good Reason in accordance with the terms of the agreement the agreement shall terminate and the Executives shall be entitled to various benefits. The employment agreements are effective October 1, 2002 and terminate September 30, 2005. The agreements automatically renew for successive one year periods beginning after September 30, 2005 unless otherwise canceled with written notice 90 days prior to the September 30 renewal date of each year. Southwest’s total contingent liability under the employment agreements at October 1, 2002 is approximately $2.9 million.

F-35        

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties, Inc. Income Fund V

(a Tennessee Limited Partnership):

We have audited the accompanying balance sheets of Southwest Royalties, Inc. Income Fund V (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties, Inc. Income Fund V as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-36

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	7,473		64,290		43,322
Receivable from Managing General Partner		37,832		—		115,255
Distribution receivable		304		304		—
Total current assets		45,609		64,594		158,577
Oil and gas properties—using the full-cost method of accounting		6,159,438		6,159,438		6,159,438
Less accumulated depreciation, depletion and amortization		5,882,800		5,864,800		5,772,800
Net oil and gas properties		276,638		294,638		386,638
	$	322,247		359,232		545,215
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Distribution payable	$	—		—		188
Payable to Managing General Partner		—		5,775		—
Total current liabilities		—		5,775		188
Partners’ equity:
General partners		(643,968	)	(640,847	)	(621,690	)
Limited partners		966,215		994,304		1,166,717
Total partners’ equity		322,247		353,457		545,027
	$	322,247		359,232		545,215

The accompanying notes are an integral part of these financial statements.

F-37

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,				For the years ended December 31,
	2002			2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	42,118		289,275	238,680	390,786	278,643
Interest		21		1,651	2,209	3,102	607
Miscellaneous settlement		3,301		—	—	—	—
		45,440		290,926	240,889	393,888	279,250
Expenses
General and administrative		58,650		57,309	115,459	117,537	117,762
Depreciation, depletion and amortization		18,000		34,000	92,000	22,000	44,000
		76,650		91,309	207,459	139,537	161,762
Net income (loss)	$	(31,210	)	199,617	33,430	254,351	117,488
Net income (loss) allocated to:
Managing General Partner	$	(2,809	)	17,966	3,009	22,892	10,574
General partner	$	(312	)	1,996	334	2,543	1,175
Limited partners	$	(28,089	)	179,655	30,087	228,916	105,739
Per limited partner unit	$	(3.75	)	23.96	4.01	30.53	14.10

The accompanying notes are an integral part of these financial statements.

F-38

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(628,874	)	1,102,062		473,188
Net income		11,749		105,739		117,488
Distributions		(5,000	)	(45,000	)	(50,000	)
Balance at December 31, 1999		(622,125	)	1,162,801		540,676
Net income		25,435		228,916		254,351
Distributions		(25,000	)	(225,000	)	(250,000	)
Balance at December 31, 2000		(621,690	)	1,166,717		545,027
Net income		3,343		30,087		33,430
Distributions		(22,500	)	(202,500	)	(225,000	)
Balance at December 31, 2001		(640,847	)	994,304		353,457
Net loss		(3,121	)	(28,089	)	(31,210	)
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(643,968	)	966,215		322,247

The accompanying notes are an integral part of these financial statements.

F-39

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interests	$	24,770		311,314		353,842		330,342		221,934
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(84,909	)	(88,620	)	(109,591	)	(84,578	)	(140,862	)
Interest received		21		1,651		2,209		3,102		607
Miscellaneous settlement		3,301		—		—		—		—
Net cash (used in) provided by operating activities		(56,817	)	224,345		246,460		248,866		81,679
Cash used in financing activities:
Distributions to partners		—		(225,154	)	(225,492	)	(249,883	)	(50,125	)
Net (decrease) increase in cash and cash equivalents		(56,817	)	(809	)	20,968		(1,017	)	31,554
Beginning of year		64,290		43,322		43,322		44,339		12,785
End of year	$	7,473		42,513		64,290		43,322		44,339
Reconciliation of net income (loss) to net cash (used in) provided by operating activities:
Net income (loss)	$	(31,210	)	199,617		33,430		254,351		117,488
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		18,000		34,000		92,000		22,000		44,000
(Increase) decrease in receivables		(17,348	)	22,039		115,162		(60,444	)	(56,709	)
(Decrease) increase in payables		(26,259	)	(31,311	)	5,868		32,959		(23,100	)
Net cash (used in) provided by operating activities	$	(56,817	)	224,345		246,460		248,866		81,679

The accompanying notes are an integral part of these financial statements.

F-40

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties, Inc. Income Fund V was organized under the laws of the state of Tennessee on May 1, 1986, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	90	%	10	%
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

F-41

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

The Partnership recognizes income from its net profits interest in oil and gas property on an accrual basis, while the quarterly cash distributions of the net profits interest are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. The net profits interest is a calculated revenue interest that burdens the underlying working interest in the property, and the net profits interest owner is not responsible for the actual development or production expenses incurred. Accordingly, if the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due to the Partnership’s net profits interest until the deficit is recovered from future net profits. The Partnership accrues a quarterly loss on its net profits interest provided there is a cumulative net amount due for accrued revenue as of the balance sheet date.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

F-42

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $528,389 and $522,470, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statements of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 7,499 limited partner units outstanding held by 559, 624 and 691 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

F-43

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings.

If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

After completion of the Partnership’s first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner’s interest in the Partnership, at a price based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented at the sole discretion of the Managing General Partner. However, the Managing General Partner’s obligation to purchase limited partner units is limited to an expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.

F-44

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.

However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of the Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $96,500, $100,700 and $92,200 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties in which the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $5,400, $24,800 and $47,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $109,200 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses.

(Payable) Receivables (to) from Southwest Royalties, Inc., the Managing General Partner, of $(5,775) and $115,255 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership approximating $900, $1,200 and $800 for the years ended December 31, 2001, 2000 and 1999, respectively.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 77% of the Partnership’s total oil and gas production during 2001: Duke Energy Field Services for 33%, Plains Marketing, LP for 28% and Sid Richardson Energy Services for 16%. Three purchasers accounted

F-45

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

for 76% of the Partnership’s total oil and gas production during 2000: Phillips 66 Company for 34%, Plain Marketing LP for 32% and Vintage Petroleum, Inc. for 10%. Three purchasers accounted for 64% of the Partnership’s total oil and gas production during 1999: Scurlock Permian Corporation for 28%, Phillips 66 Company for 26% and Vintage Petroleum Inc. for 10%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

7.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	78,000		531,000
Revisions of previous estimates	103,000		774,000
Production	(22,000	)	(125,000	)
December 31, 1999	159,000		1,180,000
Revisions of previous estimates	22,000		139,000
Production	(18,000	)	(101,000	)
December 31, 2000	163,000		1,218,000
Revisions of previous estimates	(102,000	)	(760,000	)
Production	(15,000	)	(94,000	)
December 31, 2001	46,000		364,000
Proved developed reserves—
December 31, 1999	134,000		1,093,000
December 31, 2000	145,000		1,169,000
December 31, 2001	36,000		324,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.85 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.70 per Mcf.

F-46

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves. Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	641,000	8,866,000	2,662,000
10% annual discount for estimated timing of cash flows		187,000	4,082,000	938,000
Standardized measure of discounted future net cash flows	$	454,000	4,784,000	1,724,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(239,000	)	(391,000	)	(279,000	)
Changes in prices and production costs		(4,614,000	)	2,996,000		373,000
Changes of production rates (timing) and other		1,017,000		(308,000	)	7,000
Revisions of previous quantities estimates		(972,000	)	591,000		1,125,000
Accretion of discount		478,000		172,000		45,000
Discounted future net cash flows
Beginning of year		4,784,000		1,724,000		453,000
End of year	$	454,000		4,784,000		1,724,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-47

SOUTHWEST ROYALTIES, INC. INCOME FUND V

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third		Fourth
2001:
Total revenues	$	170,313	120,612	(45,035	)	(5,001	)
Total expenses		40,531	50,779	67,176		48,973
Net income (loss)		129,782	69,833	(112,211	)	(53,974	)
Net income (loss) per limited partners unit		15.58	8.38	(13.47	)	(6.48	)
2000:
Total revenues	$	112,109	112,015	93,306		76,458
Total expenses		39,770	36,977	37,298		25,492
Net income		72,339	75,038	56,008		50,966
Net income per limited partners unit		8.68	9.01	6.72		6.12

F-48

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties, Inc. Income Fund VI

(a Tennessee Limited Partnership):

We have audited the accompanying balance sheets of Southwest Royalties, Inc. Income Fund VI (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties, Inc. Income Fund VI as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with generally accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-49

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	117,141		132,282		163,762
Receivable from Managing General Partner		—		18,003		301,006
Total current assets		117,141		150,285		464,768
Oil and gas properties—using the full-cost method of accounting		8,424,134		8,424,134		8,424,134
Less accumulated depreciation, depletion and amortization		6,937,000		6,886,000		6,646,000
Net oil and gas properties		1,487,134		1,538,134		1,778,134
	$	1,604,275		1,688,419		2,242,902
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Distribution payable	$	2,830		2,837		1,594
Payable to Managing General Partner		30,064		—		—
Total current liabilities		32,894		2,837		1,594
Partners’ equity:
General partners		(697,192	)	(685,772	)	(630,439	)
Limited partners		2,268,573		2,371,354		2,871,747
Total partners’ equity		1,571,381		1,685,582		2,241,308
	$	1,604,275		1,688,419		2,242,902

The accompanying notes are an integral part of these financial statements.

F-50

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,				For the years ended December 31,
	2002			2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	10,615		867,248	955,342	1,423,101	823,002
Interest		695		5,900	8,810	12,563	7,450
Miscellaneous settlement		581		—	—	—	—
		11,891		873,148	964,152	1,435,664	830,452
Expenses
General and administrative		75,092		76,321	152,483	153,091	150,589
Depreciation, depletion and amortization		51,000		100,000	240,000	67,000	156,000
		126,092		176,321	392,483	220,091	306,589
Net income (loss)	$	(114,201	)	696,827	571,669	1,215,573	523,863
Net income (loss) allocated to:
Managing General Partner	$	(10,278	)	62,714	51,450	109,401	47,147
General partner	$	(1,142	)	6,969	5,717	12,156	5,239
Limited partners	$	(102,781	)	627,144	514,502	1,094,016	471,477
Per limited partner unit	$	(5.14	)	31.36	25.73	54.70	23.57

The accompanying notes are an integral part of these financial statements.

F-51

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(639,382	)	2,791,254		2,151,872
Net income		52,386		471,477		523,863
Distributions		(47,500	)	(427,500	)	(475,000	)
Balance at December 31, 1999		(634,496	)	2,835,231		2,200,735
Net income		121,557		1,094,016		1,215,573
Distributions		(117,500	)	(1,057,500	)	(1,175,000	)
Balance at December 31, 2000		(630,439	)	2,871,747		2,241,308
Net income		57,167		514,502		571,669
Distributions		(112,500	)	(1,014,895	)	(1,127,395	)
Balance at December 31, 2001		(685,772	)	2,371,354		1,685,582
Net loss		(11,420	)	(102,781	)	(114,201	)
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(697,192	)	2,268,573		1,571,381

The accompanying notes are an integral part of these financial statements.

F-52

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interests	$	28,892		815,483		1,237,440		1,298,078		766,709
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(45,302	)	(51,386	)	(151,578	)	(155,768	)	(157,603	)
Interest received		695		5,900		8,810		12,563		7,450
Miscellaneous settlement		581		—		—		—		—
Net cash (used in) provided by operating activities		(15,134	)	769,997		1,094,672		1,154,873		616,556
Cash provided by investing activities:
Sale of oil and gas properties		—		—		—		2,500		—
Cash used in financing activities:
Distributions to partners		(7	)	(802,034	)	(1,126,152	)	(1,174,723	)	(473,983	)
Net (decrease) increase in cash and cash equivalents		(15,141	)	(32,037	)	(31,480	)	(17,350	)	142,573
Beginning of year		132,282		163,762		163,762		181,112		38,539
End of year	$	117,141		131,725		132,282		163,762		181,112
Reconciliation of net income (loss) to net cash (used in) provided by operating activities:
Net income (loss)	$	(114,201	)	696,827		571,669		1,215,573		523,863
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		51,000		100,000		240,000		67,000		156,000
(Increase) decrease in receivables		18,277		(51,765	)	282,098		(125,023	)	(56,294	)
Increase (decrease) in payables		29,790		24,935		905		(2,677	)	(7,013	)
Net cash (used in) provided by operating activities	$	(15,134	)	769,997		1,094,672		1,154,873		616,556

The accompanying notes are an integral part of these financial statements.

F-53

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties, Inc. Income Fund VI was organized under the laws of the state of Tennessee on December 4, 1986, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	90	%	10	%
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

F-54

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

The Partnership recognizes income from its net profits interest in oil and gas property on an accrual basis, while the quarterly cash distributions of the net profits interest are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. The net profits interest is a calculated revenue interest that burdens the underlying working interest in the property, and the net profits interest owner is not responsible for the actual development or production expenses incurred. Accordingly, if the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due to the Partnership’s net profits interest until the deficit is recovered from future net profits. The Partnership accrues a quarterly loss on its net profits interest provided there is a cumulative net amount due for accrued revenue as of the balance sheet date.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, the Partnership was over produced by 1,014, 6,004 and 1,429 mcf of gas.

F-55

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $959,132 and $1,076,779, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statements of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 20,000 limited partner units outstanding held by 669, 767 and 826 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Liquidity—MD&A

The Partnership accrued an oil and gas revenue receivable (included in the payable to the Managing General Partner) of $152,138 at June 30, 2002, and recognized a net loss in the second quarter of 2002 on an accrual basis for its net profits interest in oil and gas properties. Cash distributions of the net profits interest are based on actual cash received from the underlying oil and gas properties, net of expenses incurred during that quarterly period. Accordingly, if the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter no net cash is due to the Partnership’s net profits interest until the deficit is recovered from future net profits. Future cash distributions to the Partnership are dependent on a positive quarterly net profits calculation on the underlying properties, which differs from the calculation on an accrual basis.

F-56

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The Partnership’s wells have been depleting over its life and production has experienced declines from year to year, while costs have not always decreased proportionately. This economic decline coupled with the fluctuation of prices has caused the Partnership to experience periodic net losses. Because the Partnership is a net profit interest, this situation can cause the Partnership to generate a payable to the Managing General Partner. If the Partnership should continue to experience this economic decline thereby creating net losses and increasing the payable, the Managing General Partner may have to consider dissolution and termination steps according to the Partnership Agreement.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings.

F-57

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

After completion of the Partnership’s first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner’s interest in the Partnership, at a price based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented at the sole discretion of the Managing General Partner. However, the Managing General Partner’s obligation to purchase limited partner units is limited to an expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.

However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of the Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $105,000, $103,300 and $105,400, for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties in which the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $10,000, $54,800 and $75,500, for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $144,000 during 2001, 2000 and 1999, as an administrative fee for indirect general and administrative overhead expenses.

F-58

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $18,000 and $301,000 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership approximating $1,000, $1,300 and $900 for the years ended December 31, 2001, 2000 and 1999, respectively.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 68% of the Partnership’s total oil and gas production during 2001: Duke Energy Field Services for 55% and Plains Marketing LP for 13%. Two purchasers accounted for 59% of the Partnership’s total oil and gas production during 2000: Phillips 66 Natural Gas Co. for 48% and Plain Marketing, LP for 11%. Three purchasers accounted for 64% of the Partnership’s total oil and gas production during 1999: Phillips 66 Natural Gas Co. for 42%, Scurlock Permian LLC for 11% and Genesis Crude Oil for 11%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

7.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	256,000		5,083,000
Revisions of previous estimates	215,000		1,078,000
Production	(44,000	)	(407,000	)
December 31, 1999	427,000		5,754,000
Revisions of previous estimates	(6,000	)	220,000
Production	(33,000	)	(352,000	)
December 31, 2000	388,000		5,622,000
Revisions of previous estimates	(221,000	)	114,000
Production	(29,000	)	(368,000	)
December 31, 2001	138,000		5,368,000
Proved developed reserves—
December 31, 1999	385,000		5,398,000
December 31, 2000	308,000		5,196,000
December 31, 2001	98,000		5,017,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

F-59

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.50 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.14 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farmout arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farmout, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	9,769,000	49,205,000	14,581,000
10% annual discount for estimated timing of cash flows		5,238,000	26,968,000	6,733,000
Standardized measure of discounted future net cash flows	$	4,531,000	22,237,000	7,848,000

F-60

SOUTHWEST ROYALTIES, INC. INCOME FUND VI

(a Tennessee Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(955,000	)	(1,423,000	)	(823,000	)
Changes in prices and production costs		(16,948,000	)	15,689,000		2,271,000
Changes in estimated future development cost		—		105,000		(122,000	)
Changes of production rates (timing) and others		(1,136,000	)	(1,282,000	)	(25,000	)
Sales of minerals in place		—		(2,000	)	—
Revisions of previous quantities estimates		(891,000	)	517,000		2,278,000
Accretion of discount		2,224,000		785,000		388,000
Discounted future net cash flows—
Beginning of year		22,237,000		7,848,000		3,881,000
End of year	$	4,531,000		22,237,000		7,848,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third		Fourth
2001:
Total revenues	$	541,689	331,459	118,364		(27,360	)
Total expenses		77,358	98,963	142,226		73,936
Net income (loss)		464,331	232,496	(23,862	)	(101,296	)
Net income (loss) per limited partners unit		20.89	10.46	(1.07	)	(4.55	)
2000:
Total revenues	$	352,100	371,794	390,211		321,559
Total expenses		78,492	49,386	60,911		31,302
Net income		273,608	322,408	329,300		290,257
Net income per limited partners unit		12.31	14.51	14.82		13.06

F-61

INDEPENDENT AUDITORS REPORTS

The Partners

Southwest Oil & Gas

Income Fund VII-A, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund VII-A, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Oil & Gas Income Fund VII-A, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-62

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	30,531		52,669		68,661
Receivable from Managing General Partner		96,250		39,957		129,834
Total current assets		126,781		92,626		198,495
Oil and gas properties—using the full-cost method of accounting		4,505,788		4,504,731		4,503,306
Less accumulated depreciation, depletion and amortization		4,093,691		4,071,691		4,005,691
Net oil and gas properties		412,097		433,040		497,615
	$	538,878		525,666		696,110
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	1,232		1,360		1,693
Partners’ equity:
General partners		(580,690	)	(582,024	)	(565,013	)
Limited partners		1,118,336		1,106,330		1,259,430
Total partners’ equity		537,646		524,306		694,417
	$	538,878		525,666		696,110

The accompanying notes are an integral part of these financial statements.

F-63

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas revenue	$	370,273	460,225	745,318	930,919	606,979
Interest income from operations		349	2,509	3,632	4,615	2,728
Miscellaneous settlement		5,087	—	—	—	—
		375,709	462,734	748,950	935,534	609,707
Expenses
Production		148,215	152,497	312,063	318,910	256,890
General and administrative		58,154	58,217	115,416	117,861	114,369
Depreciation, depletion and amortization		22,000	27,000	66,000	29,000	51,000
		228,369	237,714	493,479	465,771	422,259
Net income	$	147,340	225,020	255,471	469,763	187,448
Net income allocated to:
Managing General Partner	$	13,261	20,252	22,992	42,278	16,871
General Partner	$	1,473	2,250	2,555	4,698	1,874
Limited partners	$	132,606	202,518	229,924	422,787	168,703
Per limited partner unit	$	8.84	13.50	15.33	28.19	11.25

The accompanying notes are an integral part of these financial statements.

F-64

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(568,734	)	1,225,940		657,206
Net income		18,745		168,703		187,448
Distribution		(18,500	)	(166,500	)	(185,000	)
Balance at December 31, 1999		(568,489	)	1,228,143		659,654
Net income		46,976		422,787		469,763
Distribution		(43,500	)	(391,500	)	(435,000	)
Balance at December 31, 2000		(565,013	)	1,259,430		694,417
Net income		25,547		229,924		255,471
Distribution		(42,558	)	(383,024	)	(425,582	)
Balance at December 31, 2001		(582,024	)	1,106,330		524,306
Net income		14,734		132,606		147,340
Distribution		(13,400	)	(120,600	)	(134,000	)
Balance at June 30, 2002 (unaudited)	$	(580,690	)	1,118,336		537,646

The accompanying notes are an integral part of these financial statements.

F-65

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	318,200		487,117		844,497		874,759		536,316
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(210,589	)	(225,502	)	(436,781	)	(428,907	)	(382,627	)
Interest received		349		2,509		3,632		4,615		2,728
Miscellaneous settlement		5,087		—		—		—		—
Net cash provided by operating activities		113,047		264,124		411,348		450,467		156,417
Cash flows from investing activities:
Additions to oil and gas properties		(1,057	)	(1,839	)	(6,220	)	(7,448	)	(4,052	)
Sale of oil and gas properties		—		100		4,795		—		—
Net cash used in investing activities		(1,057	)	(1,739	)	(1,425	)	(7,448	)	(4,052	)
Cash flows used in financing activities:
Distributions to partners		(134,128	)	(276,622	)	(425,915	)	(433,823	)	(185,068	)
Net (decrease) increase in cash and cash equivalents		(22,138	)	(14,237	)	(15,992	)	9,196		(32,703	)
Beginning of year		52,669		68,661		68,661		59,465		92,168
End of year	$	30,531		54,424		52,669		68,661		59,465
Reconciliation of net income to net cash provided by operating activities:
Net income	$	147,340		225,020		255,471		469,763		187,448
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		22,000		27,000		66,000		29,000		51,000
(Increase) decrease in receivables		(52,073	)	26,892		99,179		(56,160	)	(70,663	)
(Decrease) increase in payables		(4,220	)	(14,788	)	(9,302	)	7,864		(11,368	)
Net cash provided by operating activities	$	113,047		264,124		411,348		450,467		156,417

The accompanying notes are an integral part of these financial statements.

F-66

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Oil & Gas Income Fund VII-A, L.P. was organized under the laws of the state of Delaware on January 30, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property dispositions	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	90	%	10	%
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

F-67

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, the Partnership was under produced by 3,056 mcf of gas. As of December 31, 2000, the Partnership was under produced by 332 mcf of gas. As of December 31, 1999, the Partnership was over produced by 1,214 mcf of gas.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $123,205 and $82,531, more than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles.

F-68

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 15,000 limited partner units outstanding held by 566, 615 and 679 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

F-69

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

After completion of the Partnership’s first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner’s interest in the Partnership, at a price based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner’s obligation to purchase limited partner units is limited to an expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the

F-70

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $36,100, $34,200 and $33,800 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $10,200, $9,100 and $7,400 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $108,000 during 2001, 2000 and 1999, as an administrative fee for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $40,000 and $129,800 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001. For the years ended December 31, 2000 and 1999 there were approximately $100 and $300, respectively.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Four purchasers accounted for 63% of the Partnership’s total oil and gas production during 2001: Duke Energy Field Services for 25%, Sid Richardson Energy Services for 14%, Plains Marketing LP for 12% and BP Amoco for 12%. Four purchasers accounted for 70% of the Partnership’s total oil and gas production during 2000: Phillips 66 Natural Gas Co. for 32%, Plains Marketing LP for 14%, Amoco Production for 13% and Sun Refining and Marketing Co. for 11%. Four purchasers accounted for 68% of the Partnership’s total oil and gas production during 1999: Phillips 66 Natural Gas Co. for 29%, Sun Refining and Marketing Co. for 15%, Scurlock Permian LLC for 12% and Amoco Production for 12%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-71

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	88,000		635,000
Revisions of previous estimates	113,000		402,000
Production	(23,000	)	(94,000	)
December 31, 1999	178,000		943,000
Revisions of previous estimates	51,000		202,000
Production	(21,000	)	(82,000	)
December 31, 2000	208,000		1,063,000
Revisions of previous estimates	(35,000	)	(192,000	)
Production	(20,000	)	(76,000	)
December 31, 2001	153,000		795,000
Proved developed reserves—
December 31, 1999	174,000		930,000
December 31, 2000	205,000		1,051,000
December 31, 2001	150,000		784,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.13 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.36 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-72

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farmout arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farmout, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	4,501,000	15,851,000	6,120,000
Production and development costs		2,272,000	5,228,000	2,860,000
Future net cash flows		2,229,000	10,623,000	3,260,000
10% annual discount for estimated timing of cash flows		905,000	5,160,000	1,288,000
Standardized measure of discounted future net cash flows	$	1,324,000	5,463,000	1,972,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(433,000	)	(612,000	)	(350,000	)
Changes in prices and production costs		(4,395,000	)	2,936,000		588,000
Changes of production rates (timing) and others		454,000		(231,000	)	52,000
Revisions of previous quantities estimates		(311,000	)	1,201,000		1,059,000
Accretion of discount		546,000		197,000		57,000
Discounted future net cash flows—
Beginning of year		5,463,000		1,972,000		566,000
End of year	$	1,324,000		5,463,000		1,972,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-73

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	236,047	226,687	170,033	116,183
Total expenses		113,305	124,409	136,486	119,279
Net income (loss)		122,742	102,278	33,547	(3,096	)
Net income (loss) per limited partners unit		7.36	6.14	2.01	(.18	)
2000:
Total revenues	$	204,789	243,860	271,517	215,368
Total expenses		109,657	123,445	131,876	100,793
Net income		95,132	120,415	139,641	114,575
Net income per limited partners unit		5.71	7.22	8.38	6.87

F-74

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties Institutional

Income Fund VII-B, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund VII-B, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund VII-B, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-75

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	52,046		118,007		155,801
Receivable from Managing General Partner		123,332		71,440		190,243
Distribution receivable		156		—		—
Total current assets		175,534		189,447		346,044
Oil and gas properties—using the full-cost method of accounting		4,236,335		4,236,335		4,236,395
Less accumulated depreciation, depletion and amortization		3,556,370		3,528,370		3,431,370
Net oil and gas properties		679,965		707,965		805,025
	$	855,499		897,412		1,151,069
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	—		534		701
Partners’ equity:
General partners		(552,345	)	(548,207	)	(522,858	)
Limited partners		1,407,844		1,445,085		1,673,226
Total partners’ equity		855,499		896,878		1,150,368
	$	855,499		897,412		1,151,069

The accompanying notes are an integral part of these financial statements.

F-76

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	336,502	411,536	679,787	867,334	509,251
Interest		895	3,584	5,617	8,417	3,800
Miscellaneous settlement		5,872	—	—	—	—
		343,269	415,120	685,404	875,751	513,051
Expenses
General and administrative		56,648	57,610	115,165	117,165	113,122
Depreciation, depletion and amortization		28,000	44,000	97,000	62,000	83,000
		84,648	101,610	212,165	179,165	196,122
Net income	$	258,621	313,510	473,239	696,586	316,929
Net income allocated to:
Managing General Partner	$	23,276	28,216	42,592	62,693	28,524
General partner	$	2,586	3,135	4,732	6,966	3,169
Limited partners	$	232,759	282,159	425,915	626,927	285,236
Per limited partner unit	$	15.52	18.81	28.39	41.80	19.02

The accompanying notes are an integral part of these financial statements.

F-77

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(532,492	)	1,601,314		1,068,822
Net income		31,693		285,236		316,929
Distributions		(33,000	)	(311,786	)	(344,786	)
Balance at December 31, 1999		(533,799	)	1,574,764		1,040,965
Net income		69,659		626,927		696,586
Distributions		(58,718	)	(528,465	)	(587,183	)
Balance at December 31, 2000		(522,858	)	1,673,226		1,150,368
Net income		47,324		425,915		473,239
Distributions		(72,673	)	(654,056	)	(726,729	)
Balance at December 31, 2001		(548,207	)	1,445,085		896,878
Net income		25,862		232,759		258,621
Distributions		(30,000	)	(270,000	)	(300,000	)
Balance at June 30, 2002 (unaudited)	$	(552,345	)	1,407,844		855,499

The accompanying notes are an integral part of these financial statements.

F-78

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interest	$	273,795		464,481		803,263		784,549		407,013
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(45,833	)	(49,145	)	(119,838	)	(112,045	)	(104,793	)
Interest received		895		3,584		5,617		8,417		3,800
Miscellaneous settlement		5,872		—		—		—		—
Net cash provided by operating activities		234,729		418,920		689,042		680,921		306,020
Cash flows provided by investing activities:
Sale of oil and gas properties		—		100		60		—		14,933
Cash flows used in financing activities:
Distributions to partners		(300,690	)	(474,763	)	(726,896	)	(586,961	)	(345,307	)
Net (decrease) increase in cash and cash equivalents		(65,961	)	(55,743	)	(37,794	)	93,960		(24,354	)
Beginning of year		118,007		155,801		155,801		61,841		86,195
End of year	$	52,046		100,058		118,007		155,801		61,841
Reconciliation of net income to net cash provided by operating activities:
Net income	$	258,621		313,510		473,239		696,586		316,929
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		28,000		44,000		97,000		62,000		83,000
(Increase) decrease in receivables		(62,707	)	52,945		123,476		(82,785	)	(102,238	)
Increase (decrease) in payables		10,815		8,465		(4,673	)	5,120		8,329
Net cash provided by operating activities	$	234,729		418,920		689,042		680,921		306,020

The accompanying notes are an integral part of these financial statements.

F-79

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties Institutional Income Fund VII-B, L.P. was organized under the laws of the state of Delaware on January 28, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Syndication costs	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	90	%	10	%
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining

F-80

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expended or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expended. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31 2001 and 2000, the Partnership was under produced by 3,056 mcf and 332 mcf of gas, respectively. As of December 31 1999, the Partnership was over produced by 1,214 mcf of gas.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

F-81

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $281,380 and $311,625 less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 15,000 limited partner units outstanding held by 718, 769 and 871.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

F-82

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

After completion of the Partnership’s first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner’s interest in the Partnership, at a price based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner’s obligation to purchase limited partner units is limited to an expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.

The Partnership is subject to various federal, state and local environmental laws and regulations which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

F-83

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $19,800, $19,400 and $19,400 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $11,000, $9,100 and $3,500 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $108,000 during 2001, 2000 and 1999 as an administrative fee for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $71,400 and $190,200 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services for the year ended December 31, 2001. Legal services for the years ended December 31, 2000 and 1999 were approximately $100 and $200, respectively.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Four purchasers accounted for 66% of the Partnership’s total oil and gas production during 2001: Equiva Trading Company for 23%, Duke Energy Field Services for 21%, BP Amoco for 11% and Plains Marketing LP for 11%. Four purchasers accounted for 77% of the Partnership’s total oil and gas production during 2000: Phillips 66 Natural Gas Co. for 28%, Equiva Trading Company for 19%, BP Amoco for 17% and Plains Marketing LP for 13%. Four purchasers accounted for 74% of the Partnership’s total oil and gas production during 1999: Phillips 66 Natural Gas Co. for 27%, Equiva Trading Company for 19%, Amoco Production for 17% and Scurlock Permian LLC. for 11%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-84

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	148,000		672,000
Sales of reserves in place	(2,000	)	—
Revisions of previous estimates	121,000		272,000
Production	(30,000	)	(82,000	)
December 31, 1999	237,000		862,000
Revisions of previous estimates	9,000		145,000
Production	(29,000	)	(74,000	)
December 31, 2000	217,000		933,000
Revisions of previous estimates	124,000		(155,000	)
Production	(28,000	)	(66,000	)
December 31, 2001	313,000		712,000
Proved developed reserves—
December 31, 1999	234,000		851,000
December 31, 2000	214,000		926,000
December 31, 2001	309,000		705,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.99 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.21 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

F-85

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farmout arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farmout, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	5,059,000	10,895,000	5,122,000
10% annual discount for estimated timing of cash flows		2,339,000	5,164,000	2,102,000
Standardized measure of discounted future net cash flows	$	2,720,000	5,731,000	3,020,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(680,000	)	(868,000	)	(509,000	)
Changes in prices and production costs		(3,416,000	)	2,997,000		1,068,000
Changes of production rates
(timing) and others		(106,000	)	(230,000	)	46,000
Sales of minerals in place		—		—		(9,000	)
Revisions of previous quantities estimates		618,000		510,000		1,316,000
Accretion of discount		573,000		302,000		101,000
Discounted future net cash flows—
Beginning of year		5,731,000		3,020,000		1,007,000
End of year	$	2,720,000		5,731,000		3,020,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-86

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	220,468	194,652	156,058	114,226
Total expenses		51,451	50,162	64,726	45,826
Net income		169,017	144,490	91,332	68,400
Net income per limited partners unit		10.14	8.67	5.48	4.10
2000:
Total revenues	$	197,075	207,548	240,676	230,452
Total expenses		54,686	44,060	50,425	29,994
Net income		142,389	163,488	190,251	200,458
Net income per limited partners unit		8.54	9.81	11.42	12.03

F-87

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Oil & Gas Income Fund

VIII-A, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund VIII-A, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Oil & Gas Income Fund VIII-A, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-88

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	41,408	37,385	111,937
Receivable from Managing General Partner		101,267	59,724	175,865
Total current assets		142,675	97,109	287,802
Oil and gas properties—using the full-cost method of accounting		5,425,945	5,391,725	5,354,285
Less accumulated depreciation, depletion and amortization		5,087,466	5,074,466	5,029,466
Net oil and gas properties		338,479	317,259	324,819
	$	481,154	414,368	612,621
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	227	321	179
Partners’ equity—
General partners		13,394	5,406	20,745
Limited partners		467,533	408,641	591,697
Total partners’ equity		480,927	414,047	612,442
	$	481,154	414,368	612,621

The accompanying notes are an integral part of these financial statements.

F-89

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas revenue	$	486,875	743,238	1,290,533	1,537,038	952,972
Interest		217	2,892	4,076	6,554	1,539
Miscellaneous		309	—	—	3,955	—
		487,401	746,130	1,294,609	1,547,547	954,511
Expenses
Production		323,898	320,075	722,304	705,747	580,893
General and administrative		51,623	52,728	105,637	106,305	103,921
Depreciation, depletion and amortization		13,000	18,000	45,000	22,000	23,000
		388,521	390,803	872,941	834,052	707,814
Net income	$	98,880	355,327	421,668	713,495	246,697
Net income allocated to:
Managing General Partner	$	10,069	33,599	42,000	66,195	24,273
General Partner	$	1,119	3,734	4,667	7,354	2,696
Limited partners	$	87,692	317,994	375,001	639,946	219,728
Per limited partner unit	$	6.45	23.39	27.58	47.07	16.16

The accompanying notes are an integral part of these financial statements.

F-90

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(6,229	)	432,720		426,491
Net income		26,969		219,728		246,697
Distributions		(12,000	)	(146,801	)	(158,801	)
Balance at December 31, 1999		8,740		505,647		514,387
Net income		73,549		639,946		713,495
Distributions		(61,544	)	(553,896	)	(615,440	)
Balance at December 31, 2000		20,745		591,697		612,442
Net income		46,667		375,001		421,668
Distributions		(62,006	)	(558,057	)	(620,063	)
Balance at December 31, 2001		5,406		408,641		414,047
Net income		11,188		87,692		98,880
Distributions		(3,200	)	(28,800	)	(32,000	)
Balance at June 30, 2002 (unaudited)	$	13,394		467,533		480,927

The accompanying notes are an integral part of these financial statements.

F-91

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	452,356		786,335		1,427,576		1,475,772		845,350
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(382,545	)	(404,524	)	(848,843	)	(789,799	)	(685,534	)
Interest received		217		2,892		4,076		6,554		1,539
Miscellaneous settlement		309		—		—		—		—
Net cash provided by operating activities		70,337		384,703		582,809		692,527		161,355
Cash flows from investing activities:
Additions to oil and gas properties		(34,220	)	(34,398	)	(37,600	)	(8,370	)	(8,306	)
Sale of oil and gas properties		—		200		160		—		27,748
Net cash (used in) provided by investing activities		(34,220	)	(34,198	)	(37,440	)	(8,370	)	19,442
Cash flows used in financing activities:
Distributions to partners		(32,094	)	(425,060	)	(619,921	)	(615,511	)	(158,740	)
Net (decrease) increase in cash and cash equivalents		4,023		(74,555	)	(74,552	)	68,646		22,057
Beginning of year		37,385		111,937		111,937		43,291		21,234
End of year	$	41,408		37,382		37,385		111,937		43,291
Reconciliation of net income to net cash provided by operating activities:
Net income	$	98,880		355,327		421,668		713,495		246,697
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		13,000		18,000		45,000		22,000		23,000
(Increase) decrease in receivables		(34,519	)	43,097		137,043		(65,221	)	(107,622	)
(Decrease) increase in payables		(7,024	)	(31,721	)	(20,902	)	22,253		(720	)
Net cash provided by operating activities	$	70,337		384,703		582,809		692,527		161,355

The accompanying notes are an integral part of these financial statements.

F-92

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Oil & Gas Income Fund VIII-A, L.P. was organized under the laws of the state of Delaware on November 30, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Syndication costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent

F-93

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001 and 2000, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is

F-94

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

$466,871 and $543,828, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 13,596 limited partner units outstanding held by 518, 551 and 598 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate

F-95

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

After completion of the Partnership’s first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner’s interest in the Partnership, at a price based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner’s obligation to purchase limited partner units is limited to an expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect

F-96

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $139,100, $135,100 and $131,400 for the years ended December 31, 2001, 2000 and 1999 respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oil field services for properties in which the Partnership owns an interest. Such services aggregated approximately $2,700, $9,200 and $26,200 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $98,400 during 2001, 2000 and 1999 as an administrative fee for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $59,724 and $175,865 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 78% of the Partnership’s total oil and gas production during 2001: Plains Marketing LP for 58%, Mobil Corporation for 10% and Duke Energy Field Services for 10%. Two purchasers accounted for 81% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 60% and Mobil Corporation for 21%. Two purchasers accounted for 75% of the Partnership’s total oil and gas production during 1999: Scurlock Permian LLC for 54% and Mobil Corporation for 21%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-97

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	156,000		189,000
Revisions of previous estimates	365,000		1,001,000
Production	(46,000	)	(68,000	)
December 31, 1999	475,000		1,122,000
Revisions of previous estimates	105,000		(151,000	)
Production	(45,000	)	(59,000	)
December 31, 2000	535,000		912,000
Revisions of previous estimates	(151,000	)	(484,000	)
Production	(43,000	)	(60,000	)
December 31, 2001	341,000		368,000
Proved developed reserves—
December 31, 1999	468,000		1,122,000
December 31, 2000	527,000		909,000
December 31, 2001	316,000		365,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.92 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.58 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information,

F-98

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	7,053,000	22,825,000	13,754,000
Production and development costs		4,474,000	11,970,000	8,881,000
Future net cash flows		2,579,000	10,855,000	4,873,000
10% annual discount for estimated timing of cash flows		982,000	4,966,000	1,920,000
Standardized measure of discounted future net cash flows	$	1,597,000	5,889,000	2,953,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced net of production costs	$	(568,000	)	(831,000	)	(372,000	)
Changes in prices and production costs		(3,781,000	)	3,014,000		497,000
Changes of production rates (timing) and others		388,000		(227,000	)	37,000
Revisions of previous quantities estimates		(920,000	)	685,000		2,372,000
Accretion of discount		589,000		295,000		38,000
Discounted future net cash flows—
Beginning of year		5,889,000		2,953,000		381,000
End of year	$	1,597,000		5,889,000		2,953,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-99

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	395,505	350,625	312,739	235,740
Total expenses		171,024	219,778	230,078	252,061
Net income (loss)		224,481	130,847	82,661	(16,321	)
Net income per (loss) limited partners unit		14.80	8.59	5.35	(1.16	)
2000:
Total revenues	$	359,680	365,119	401,921	420,827
Total expenses		187,186	195,088	232,636	219,142
Net income		172,494	170,031	169,285	201,685
Net income per limited partners unit		11.36	11.23	11.15	13.33

F-100

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties Institutional

Income Fund VIII-B, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund VIII-B, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund VIII-B, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-101

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	34,322	63,123	101,708
Receivable from Managing General Partner		87,890	60,341	177,112
Total current assets		122,212	123,464	278,820
Oil and gas properties—using the full-cost method of accounting		4,133,496	4,133,496	4,133,496
Less accumulated depreciation, depletion and amortization		3,741,058	3,726,058	3,673,058
Net oil and gas properties		392,438	407,438	460,438
	$	514,650	530,902	739,258
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distributions payable	$	850	523	199
Partners’ equity:
General partners		6,462	6,620	22,188
Limited partners		507,338	523,759	716,871
Total partners’ equity		513,800	530,379	739,059
	$	514,650	530,902	739,258

The accompanying notes are an integral part of these financial statements.

F-102

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(A Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	139,277	347,149	538,441	813,940	384,352
Interest		400	2,954	4,549	7,024	2,026
Miscellaneous		2,253	—	—	3,914	—
		141,930	350,103	542,990	824,878	386,378
Expenses
General and administrative		38,509	38,943	78,407	79,549	77,506
Depreciation, depletion and amortization		15,000	22,000	53,000	32,000	33,000
		53,509	60,943	131,407	111,549	110,506
Net income	$	88,421	289,160	411,583	713,329	275,872
Net income allocated to:
Managing General Partner	$	9,308	28,004	41,812	67,080	27,798
General partner	$	1,034	3,112	4,646	7,453	3,089
Limited partners	$	78,079	258,044	365,125	638,796	244,985
Per limited partner unit	$	7.69	25.43	35.98	62.95	24.14

The accompanying notes are an integral part of these financial statements.

F-103

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(208	)	580,302		580,094
Net income		30,887		244,985		275,872
Distributions		(18,000	)	(162,000	)	(180,000	)
Balance at December 31, 1999		12,679		663,287		675,966
Net income		74,533		638,796		713,329
Distributions		(65,024	)	(585,212	)	(650,236	)
Balance at December 31, 2000		22,188		716,871		739,059
Net income		46,458		365,125		411,583
Distributions		(62,026	)	(558,237	)	(620,263	)
Balance at December 31, 2001		6,620		523,759		530,379
Net income		10,342		78,079		88,421
Distributions		(10,500	)	(94,500	)	(105,000	)
Balance at June 30, 2002 (unaudited)	$	6,462		507,338		513,800

The accompanying notes are an integral part of these financial statements.

F-104

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interests	$	104,016		385,560		654,636		761,009		288,105
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(30,797	)	(33,398	)	(77,831	)	(80,804	)	(78,645	)
Interest received		400		2,954		4,549		7,024		2,026
Miscellaneous settlement		2,253		—		—		—		—
Net cash provided by operating activities		75,872		355,116		581,354		687,229		211,486
Cash flows used in financing activities:
Distributions to partners		(104,673	)	(380,083	)	(619,939	)	(650,560	)	(180,009	)
Net (decrease) increase in cash and cash equivalents		(28,801	)	(24,967	)	(38,585	)	36,669		31,477
Beginning of year		63,123		101,708		101,708		65,039		33,562
End of year	$	34,322		76,741		63,123		101,708		65,039
Reconciliation of net income to net cash provided by operating activities:
Net income	$	88,421		289,160		411,583		713,329		275,872
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		15,000		22,000		53,000		32,000		33,000
(Increase) decrease in receivables		(35,261	)	38,411		116,195		(56,845	)	(96,247	)
Increase (decrease) in payables		7,712		5,545		576		(1,255	)	(1,139	)
Net cash provided by operating activities	$	75,872		355,116		581,354		687,229		211,486

The accompanying notes are an integral part of these financial statements.

F-105

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties Institutional Income Fund VIII-B, L.P. was organized under the laws of the state of Delaware on November 30, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The offering of limited partner units began March 31, 1988, minimum capital requirements were met July 11, 1988, with the offering concluded on March 31, 1989.

The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales from net profits interests	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property dispositions	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues

F-106

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit.

Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

F-107

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership’s tax basis in its oil and gas properties at December 31, 2001 and 2000 is $130,730 and $227,671, more respectively, than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 10,147 limited partner units outstanding held by 520, 537 and 579 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

F-108

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

After completion of the Partnership’s first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner’s interest in the Partnership, at a price based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner’s obligation to purchase limited partner units is limited to an expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.

F-109

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.

However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $108,900, $104,100 and $101,600 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $4,900, $8,000 and $19,700 for the years ended December 31, 2001, 2000, and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $72,000 during 2001, 2000 and 1999, as an administrative fee for reimbursement of indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $60,300 and $177,100 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 79% of the Partnership’s total oil and gas production during 2001: Plains Marketing LP for 57%, Mobil Corporation for 11% and Exxon Company USA for 11%. Two purchasers accounted for 80% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 57% and Mobil Corporation for

F-110

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

23%. Two purchasers accounted for 76% of the Partnership’s total oil and gas production during 1999: Scurlock Permian LLC for 52% and Mobil Corporation for 24%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	199,000		147,000
Revisions of previous estimates	291,000		894,000
Production	(42,000	)	(51,000	)
December 31, 1999	448,000		990,000
Revisions of previous estimates	79,000		(210,000	)
Production	(41,000	)	(44,000	)
December 31, 2000	486,000		736,000
Revisions of previous estimates	(92,000	)	(365,000	)
Production	(40,000	)	(44,000	)
December 31, 2001	354,000		327,000
Proved developed reserves—
December 31, 1999	441,000		990,000
December 31, 2000	479,000		736,000
December 31, 2001	331,000		327,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.94 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.52 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of

F-111

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	2,853,000	9,975,000	5,211,000
10% annual discount for estimated timing of cash flows		1,107,000	4,652,000	2,277,000
Standardized measure of discounted future net cash flows	$	1,746,000	5,323,000	2,934,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(538,000	)	(814,000	)	(384,000	)
Changes in prices and production costs		(3,333,000	)	2,591,000		554,000
Changes of production rates (timing) and others		415,000		(66,000	)	80,000
Revisions of previous quantities estimates		(653,000	)	385,000		2,106,000
Accretion of discount		532,000		293,000		53,000
Discounted future net cash flows—
Beginning of year		5,323,000		2,934,000		525,000
End of year	$	1,746,000		5,323,000		2,934,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-112

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	231,370	118,732	143,556	49,332
Total expenses		30,163	30,779	38,587	31,878
Net income		201,207	87,953	104,969	17,454
Net income per limited partners unit		17.74	7.69	9.12	1.43
2000:
Total revenues	$	184,602	193,079	208,778	238,419
Total expenses		29,435	27,608	30,349	24,157
Net income		155,167	165,471	178,429	214,262
Net income per limited partners unit		13.66	14.62	15.72	18.95

F-113

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Combination Income/Drilling

Program 1988, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Combination Income/Drilling Program 1988, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Combination Income/Drilling Program 1988, L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 24, 2002

F-114

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	10,918	13,981	231
Receivable from Managing General Partner		6,220	—	5,682
Total current assets		17,138	13,981	5,913
Oil and gas properties—using the full-cost method of accounting		1,490,085	1,490,085	1,491,245
Less accumulated depreciation, depletion and amortization		1,479,924	1,479,124	1,474,124
Net oil and gas properties		10,161	10,961	17,121
	$	27,299	24,942	23,034
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Distribution payable	$	345	345	569
Payable to Managing General Partner		—	2,784	—
Current liabilities		345	3,129	569
Partners’ equity:
General partners		2,769	1,894	1,341
Limited partners		24,185	19,919	21,124
Total partners’ equity		26,954	21,813	22,465
	$	27,299	24,942	23,034

The accompanying notes are an integral part of these financial statements.

F-115

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas revenue	$	45,917	70,941	114,533	165,052	100,304
Interest		—	37	63	—	—
Miscellaneous settlement		154	—	—	—	—
		46,071	70,978	114,596	165,052	100,304
Expenses
Production		27,260	35,401	74,202	98,617	73,205
General and administrative		12,870	12,526	25,046	25,083	26,328
Depreciation, depletion and amortization		800	2,000	5,000	900	2,000
		40,930	49,927	104,248	124,600	101,533
Net income (loss)	$	5,141	21,051	10,348	40,452	(1,229	)
Net income (loss) allocated to:
Managing General Partner	$	816	3,187	2,050	5,770	68
General partner	$	59	231	153	414	8
Limited partners	$	4,266	17,633	8,145	34,268	(1,305	)
Per limited partner unit	$	1.22	5.03	2.32	9.77	(.37	)

The accompanying notes are an integral part of these financial statements.

F-116

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance—January 1, 1999	$	(4,899	)	(11,726	)	(16,625	)
Net income (loss)		76		(1,305	)	(1,229	)
Balance—December 31, 1999		(4,823	)	(13,031	)	(17,854	)
Net income		6,184		34,268		40,452
Distributions		(20	)	(113	)	(133	)
Balance—December 31, 2000		1,341		21,124		22,465
Net income		2,203		8,145		10,348
Distributions		(1,650	)	(9,350	)	(11,000	)
Balance—December 31, 2001		1,894		19,919		21,813
Net income		875		4,266		5,141
Distributions		—		—		—
Balance—June 30, 2002 (unaudited)	$	2,769		24,185		26,954

The accompanying notes are an integral part of these financial statements.

F-117

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	40,095		77,542		132,064		155,012		89,246
Cash paid to Managing General
Partner for administrative
fees and general and administrative overhead		(43,312	)	(63,453	)	(108,313	)	(154,870	)	(89,234	)
Interest received		—		37		63		—		—
Miscellaneous settlement		154		—		—		—		—
Net cash (used in) provided by operating activities		(3,063	)	14,126		23,814		142		12
Cash flows from investing activities:
Additions to oil and gas properties		—		—		—		(12	)	(12	)
Sale of oil and gas property		—		1,200		1,160		—		—
Net cash provided by (used in) investing activities		—		1,200		1,160		(12	)	(12	)
Cash flows (used in) provided by financing activities:
Distributions to partners		—		(5,500	)	(11,224	)	(179	)	(1	)
Net (decrease) increase in cash and cash equivalents		(3,063	)	9,826		13,750		(49	)	(1	)
Beginning of year		13,981		231		231		280		281
End of year	$	10,918		10,057		13,981		231		280
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss)	$	5,141		21,051		10,348		40,452		(1,229	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		800		2,000		5,000		900		2,000
(Increase) decrease in receivables		(5,822	)	6,601		17,531		(10,040	)	(11,058	)
(Decrease) increase in payables		(3,182	)	(15,526	)	(9,065	)	(31,170	)	10,299
Net cash (used in) provided by operating activities	$	(3,063	)	14,126		23,814		142		12

The accompanying notes are an integral part of these financial statements.

F-118

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Combination Income/Drilling Program 1988, L.P. (the “Partnership”) was organized under the laws of the state of Delaware on November 14, 1988 for the purpose of acquiring producing oil and gas properties, drilling oil and gas wells and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners	General Partners
Interest income on capital contributions	100%	—
Oil and gas sales	85%	15	%
All other revenues	85%	15	%
Organization and offering costs(1)	100%	—
Amortization of organization costs	100%	—
Property acquisition costs	98%	2	%
Depreciation, depletion and amortization	98%	2	%
Drilling related costs	98%	2	%
Operating and administrative costs(2)	85%	15	%
All other costs	85%	15	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceeds 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution. For the purpose of allocating Administrative Costs, the Managing General Partner will allocate each employee’s time among three divisions: (1) operating partnerships; (2) corporate activities; and (3) currently offered or proposed partnerships. The Managing General Partner determines a percentage of total Administrative Costs per division based on the total allocated time per division and personnel costs (salaries) attributable to such time. Within the operating partnership division, Administrative Costs are further allocated on the basis of the total capital of each partnership invested in its operations.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost using the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

Depreciation, depletion and amortization of oil and gas properties is computed using the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves, by multiplying the total unamortized cost of oil and gas

F-119

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the production, or both could change significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners. Such items of deduction or loss passed through, along with each partner’s ability to treat cash distributions as non-taxable returns of capital, may be subject to certain limitations at the partners’ level.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes, that Statement,” the Partnership’s tax basis in its oil and gas properties at December 31, 2001 and 2000 is $143,600 and $191,400, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

F-120

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999 there were 3,509 limited partner units outstanding held by 177, 174 and 174 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Two customers purchased 69% and 31% of the Partnership’s oil and gas production during 2001. Two customers purchased 68% and 32% of the Partnership’s oil and gas production during 2000. Two customers purchased 67% and 33% of the Partnership’s oil and gas production during 1999.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the weighted average number of limited partnership units outstanding during the year.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

F-121

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

3.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of the Partnership’s properties.

4.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest is operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $27,800, $36,300 and $34,500 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $3,800, $9,100 and $1,500 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner was paid $21,000 for the years ended December 31, 2001, 2000 and 1999 as an administrative fee for reimbursement of indirect general and administrative overhead expenses.

Receivable (payables) from (to) Southwest Royalties, Inc., the Managing General Partner, of approximately $(2,784) and $5,682 are for oil and gas sales, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

A director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the years ended December 31, 2001, 2000 and 1999.

F-122

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

5.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	4,000		6,000
Revisions of previous estimates	35,000		136,000
Production	(4,000	)	(16,000	)
December 31, 1999	35,000		126,000
Revisions of previous estimates	18,000		80,000
Production	(4,000	)	(15,000	)
December 31, 2000	49,000		191,000
Revisions of previous estimates	(36,000	)	(160,000	)
Production	(4,000	)	(10,000	)
December 31, 2001	9,000		21,000
Proved developed reserves—
December 31, 1999	31,000		119,000
December 31, 2000	45,000		184,000
December 31, 2001	5,000		14,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.40 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.49 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

The Partnership has reserves, which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate the Partnership’s present reserves.

F-123

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farmout arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farmout, or receives cash.

The Partnership or the owners of properties in which the Partnership owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves, which qualify as proved developed non-producing reserves.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001			2000		1999
Future cash inflows	$	211,000		3,056,000		1,048,000
Production and development costs		(140,000	)	(1,683,000	)	(729,000	)
Future net cash flows		71,000		1,373,000		319,000
10% annual discount for estimated timing of cash flows		(24,000	)	(555,000	)	(99,000	)
Standardized measure of discounted future net cash flows	$	47,000		818,000		220,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(40,000	)	(66,000	)	(27,000	)
Changes in prices and production costs		(582,000	)	360,000		—
Changes of production rates (timing) and other		5,000		(35,000	)	(2,000	)
Revisions of previous quantities estimates		(236,000	)	317,000		227,000
Accretion of discount		82,000		22,000		2,000
Discounted future net cash flows—
Beginning of year		818,000		220,000		20,000
End of year	$	47,000		818,000		220,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-124

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Oil & Gas Income Fund IX-A, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund IX-A, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Oil & Gas Income Fund IX-A, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-125

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	20,690		38,153		165,929
Receivable from Managing General Partner		88,201		49,932		118,604
Total current assets		108,891		88,085		284,533
Oil and gas properties—using the full-cost method of accounting		3,130,687		3,130,327		3,124,703
Less accumulated depreciation, depletion and amortization		2,803,000		2,791,000		2,738,000
Net oil and gas properties		327,687		339,327		386,703
	$	436,578		427,412		671,236
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distributions payable	$	714		736		—
Partners’ equity:
General partners		(62,962	)	(65,081	)	(45,925	)
Limited partners		498,826		491,757		717,161
Total partners’ equity		435,864		426,676		671,236
	$	436,578		427,412		671,236

The accompanying notes are an integral part of these financial statements.

F-126

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas	$	372,964	607,737	1,009,784	1,208,575	729,841
Interest		288	3,330	4,572	8,672	3,346
Miscellaneous		9,142	—	—	126	1,514
		382,394	611,067	1,014,356	1,217,373	734,701
Expenses
Production		221,896	223,341	479,983	460,722	390,310
General and administrative		39,310	40,107	79,764	77,897	78,856
Depreciation, depletion and amortization		12,000	25,000	53,000	20,000	28,000
		273,206	288,448	612,747	558,619	497,166
Net income	$	109,188	322,619	401,609	658,754	237,535
Net income allocated to:
Managing General Partner	$	10,907	31,286	40,915	61,088	23,898
General Partner	$	1,212	3,476	4,546	6,788	2,655
Limited partners	$	97,069	287,857	356,148	590,878	210,982
Per limited partner unit	$	9.29	27.54	34.07	56.53	20.18

The accompanying notes are an integral part of these financial statements.

F-127

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(65,062	)	717,976		652,914
Net income		26,553		210,982		237,535
Distributions		(24,000	)	(238,173	)	(262,173	)
Balance at December 31, 1999		(62,509	)	690,785		628,276
Net income		67,876		590,878		658,754
Distributions		(51,292	)	(564,502	)	(615,794	)
Balance at December 31, 2000		(45,925	)	717,161		671,236
Net income		45,461		356,148		401,609
Distributions		(64,617	)	(581,552	)	(646,169	)
Balance at December 31, 2001		(65,081	)	491,757		426,676
Net income		12,119		97,069		109,188
Distributions		(10,000	)	(90,000	)	(100,000	)
Balance at June 30, 2002 (unaudited)	$	(62,962	)	498,826		435,864

The accompanying notes are an integral part of these financial statements.

F-128

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	344,980		639,641		1,112,807		1,147,506		655,511
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(271,491	)	(311,545	)	(594,099	)	(496,877	)	(457,578	)
Interest received		288		3,330		4,572		8,672		3,346
Miscellaneous settlement		9,142		—		—		—		—
Net cash provided by operating activities		82,919		331,426		523,280		659,301		201,279
Cash flows from investing activities:
Additions to oil and gas properties		(360	)	(5,771	)	(6,404	)	(31,032	)	(8,236	)
Sale of oil and gas properties		—		780		780		—		203,998
Net cash (used in) provided by investing activities		(360	)	(4,991	)	(5,624	)	(31,032	)	195,762
Cash flows used in financing activities:
Distributions to partners		(100,022	)	(434,586	)	(645,432	)	(615,920	)	(262,692	)
Net (decrease) increase in cash and cash equivalents		(17,463	)	(108,151	)	(127,776	)	12,349		134,349
Beginning of year		38,153		165,929		165,929		153,580		19,231
End of year	$	20,690		57,778		38,153		165,929		153,580
Reconciliation of net income to net cash provided by operating activities:
Net income	$	109,188		322,619		401,609		658,754		237,535
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		12,000		25,000		53,000		20,000		28,000
(Increase) decrease in receivables		(27,984	)	31,904		103,023		(61,195	)	(75,844	)
(Decrease) increase in payables		(10,285	)	(48,097	)	(34,352	)	41,742		11,588
Net cash provided by operating activities	$	82,919		331,426		523,280		659,301		201,279

The accompanying notes are an integral part of these financial statements.

F-129

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Oil & Gas Income Fund IX-A, L.P. was organized under the laws of the state of Delaware on March 9, 1989, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to

F-130

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001 the Partnership was overproduced by 403 mcf of gas. As of December 31, 2000, the Partnership was overproduced by 403 mcf of gas. As of December 31, 1999, the Partnership was overproduced by 403 mcf of gas.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $35,868 and $17,405 more, respectively, than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles.

F-131

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999 and there were 10,453 limited partner units outstanding held by 562, 561 and 568 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

F-132

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management was not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

F-133

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $80,400, $76,200 and $77,900 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $15,700, $23,300 and $18,500 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $73,200 during 2001, 2000 and 1999 as an administrative fee for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $49,900 and $118,600 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the years ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 71% of the Partnership’s total oil and gas production during 2001: Phillips 66 Company for 45%, Duke Energy Field Services for 14% and Plains Marketing LP for 12%. Two purchasers accounted for 77% of the Partnership’s total oil and gas production during 2000: Phillips 66 Company for 64%, and Plains Marketing LP for 13%. Two purchasers accounted for 72% of the Partnership’s total oil and gas production during 1999: Phillips 66 Company for 60%, and Scurlock Permian LLC for 12%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-134

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	186,000		1,049,000
Revisions of previous estimates	168,000		364,000
Production	(27,000	)	(143,000	)
Sale of minerals in place	(6,000	)	(45,000	)
December 31, 1999	321,000		1,225,000
Revisions of previous estimates	27,000		518,000
Production	(25,000	)	(139,000	)
December 31, 2000	323,000		1,604,000
Revisions of previous estimates	(89,000	)	(643,000	)
Production	(25,000	)	(122,000	)
December 31, 2001	209,000		839,000
Proved developed reserves—
December 31, 1999	291,000		1,128,000
December 31, 2000	305,000		1,517,000
December 31, 2001	194,000		728,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.34 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.26 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-135

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation.

In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	5,740,000	23,342,000	9,945,000
Production and development costs		2,872,000	8,358,000	4,762,000
Future net cash flows		2,868,000	14,984,000	5,183,000
10% annual discount for estimated timing of cash flows		1,159,000	7,071,000	2,285,000
Standardized measure of discounted future net cash flows	$	1,709,000	7,913,000	2,898,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced net of production costs	$	(530,000	)	(748,000	)	(340,000	)
Changes in prices and production costs		(5,896,000	)	4,096,000		1,037,000
Changes of production rates (timing) and others		392,000		(142,000	)	(123,000	)
Sales of minerals in place		—		—		(76,000	)
Revisions of previous quantities estimates		(961,000	)	1,519,000		1,254,000
Accretion of discount		791,000		290,000		104,000
Discounted future net cash flows—
Beginning of year		7,913,000		2,898,000		1,042,000
End of year	$	1,709,000		7,913,000		2,898,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-136

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	323,891	287,175	229,021	174,269
Total expenses		122,607	165,840	169,906	154,394
Net income		201,284	121,335	59,115	19,875
Net income per limited partners unit		17.24	10.29	4.92	1.62
2000:
Total revenues	$	271,817	295,638	321,962	327,956
Total expenses		132,254	130,803	143,193	152,369
Net income		139,563	164,835	178,769	175,587
Net income per limited partners unit		11.93	14.16	15.33	15.11

F-137

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties Institutional

Income Fund IX-B, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund IX-B, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the Untied States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund IX-B, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-138

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	18,238		28,023		80,803
Receivable from Managing General Partner		77,240		54,594		129,611
Total current assets		95,478		82,617		210,414
Oil and gas properties—using the full-cost method of accounting		2,955,644		2,955,644		2,956,364
Less accumulated depreciation,depletion and amortization		2,677,000		2,667,000		2,623,000
Net oil and gas properties		278,644		288,644		333,364
	$	374,122		371,261		543,778
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	145		251		—
Partners’ equity:
General partners		(66,325	)	(67,622	)	(54,745	)
Limited partners		440,302		438,632		598,523
Total partners’ equity		373,977		371,010		543,778
	$	374,122		371,261		543,778

The accompanying notes are an integral part of these financial statements.

F-139

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	140,108	338,229	484,452	628,194	322,555
Interest		255	2,492	3,546	7,094	3,511
Miscellaneous		4,526	—	—	—	1,396
		144,889	340,721	487,998	635,288	327,462
Expenses
General and administrative		36,922	37,283	74,319	72,790	73,939
Depreciation, depletion and amortization		10,000	19,000	44,000	15,000	25,000
		46,922	56,283	118,319	87,790	98,939
Net income	$	97,967	284,438	369,679	547,498	228,523
Net income allocated to:
Managing General Partner	$	9,717	27,310	37,231	50,625	22,817
General Partner	$	1,080	3,034	4,137	5,625	2,535
Limited partners	$	87,170	254,094	328,311	491,248	203,171
Per limited partner unit	$	8.91	25.98	33.56	50.22	20.77

The accompanying notes are an integral part of these financial statements.

F-140

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(65,090	)	696,009		630,919
Net income		25,352		203,171		228,523
Distributions		(23,000	)	(251,382	)	(274,382	)
Balance at December 31, 1999		(62,738	)	647,798		585,060
Net income		56,250		491,248		547,498
Distributions		(48,257	)	(540,523	)	(588,780	)
Balance at December 31, 2000		(54,745	)	598,523		543,778
Net income		41,368		328,311		369,679
Distributions		(54,245	)	(488,202	)	(542,447	)
Balance at December 31, 2001		(67,622	)	438,632		371,010
Net income		10,797		87,170		97,967
Distributions		(9,500	)	(85,500	)	(95,000	)
Balance at June 30, 2002 (unaudited)	$	(66,325	)	440,302		373,977

The accompanying notes are an integral part of these financial statements.

F-141

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
Cash flows from operating activities:
Cash received from net profits interests	$	116,547		367,427		574,333		574,941		260,510
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(36,007	)	(53,498	)	(89,182	)	(56,316	)	(71,802	)
Interest received		255		2,492		3,546		7,094		3,511
Miscellaneous settlement		4,526		—		—		—		—
Net cash provided by operating activities		85,321		316,421		488,697		525,719		192,219
Cash flows provided by investing activities:
Sale of oil and gas properties		—		720		720		—		213,097
Cash flows used in financing activities:
Distributions to partners		(95,106	)	(349,904	)	(542,197	)	(588,734	)	(274,960	)
Net (decrease) increase in cash and cash equivalents		(9,785	)	(32,763	)	(52,780	)	(63,015	)	130,356
Beginning of year		28,023		80,803		80,803		143,818		13,462
End of year	$	18,238		48,040		28,023		80,803		143,818
Reconciliation of net income to net cash provided by operating activities:
Net income	$	97,967		284,438		369,679		547,498		228,523
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,000		19,000		44,000		15,000		25,000
Decrease (increase) in receivables		(23,561	)	29,198		89,881		(53,252	)	(63,441	)
(Decrease) increase in payables		915		(16,215	)	(14,863	)	16,473		2,137
Net cash provided by operating activities	$	85,321		316,421		488,697		525,719		192,219

The accompanying notes are an integral part of these financial statements.

F-142

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties Institutional Income Fund IX-B, L.P. was organized under the laws of the state of Delaware on March 9, 1989, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners	General Partners
Oil and gas sales	90%	10	%
Interest income on capital contributions	100%	—
All other revenues	90%	10	%
Organization and offering costs(1)	100%	—
Syndication costs	100%	—
Amortization of organization costs	100%	—
Property acquisition costs	100%	—
Gain/loss on property disposition	90%	10	%
Operating and administrative costs(2)	90%	10	%
Depreciation, depletion and amortization of oil and gas properties	100%	—
All other costs	90%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to

F-143

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001 the Partnership was overproduced by 364 mcf of gas. As of December 31, 2000, the Partnership was overproduced by 364 mcf of gas. As of December 31, 1999, the Partnership was overproduced by 364 mcf of gas.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

F-144

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $134,867 and $128,061, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 9,782 limited partner units outstanding held by 610, 602 and 612 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

F-145

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercede SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

F-146

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $69,300, $65,500 and $86,500 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $15,000, $22,400 and $18,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $68,400 during 2001, 2000 and 1999 as an administrative fee for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $54,600 and $129,600 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have material adverse impact on the Partnership. Two purchasers accounted for 63% of the Partnership’s total oil and gas production during 2001: Phillips 66 Company for 48% and Duke Energy Field Services for 15%. One purchaser accounted for 69% of the Partnership’s total oil and gas production during 2000: Phillips 66 Company 69%. One purchaser accounted for 62% of the Partnership’s total oil and gas production during 1999: Phillips 66 Company for 62%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-147

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	172,000		984,000
Revisions of previous estimates	134,000		350,000
Production	(22,000	)	(136,000	)
Sale of minerals in place	(5,000	)	(42,000	)
December 31, 1999	279,000		1,156,000
Revisions of previous estimates	50,000		614,000
Production	(20,000	)	(130,000	)
December 31, 2000	309,000		1,640,000
Revisions of previous estimates	(100,000	)	(741,000	)
Production	(21,000	)	(115,000	)
December 31, 2001	188,000		784,000
Proved developed reserves—
December 31, 1999	252,000		1,066,000
December 31, 2000	293,000		1,564,000
December 31, 2001	183,000		686,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.29 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.26 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-148

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	2,618,000	15,466,000	4,794,000
10% annual discount for estimated timing of cash flows		1,063,000	7,508,000	2,172,000
Standardized measure of discounted future net cash flows	$	1,555,000	7,958,000	2,622,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(484,000	)	(628,000	)	(323,000	)
Changes in prices and production costs		(6,196,000	)	3,793,000		1,011,000
Changes of production rates (timing) and others		572,000		(172,000	)	(121,000	)
Sales of minerals in place		—		—		(70,000	)
Revisions of previous quantities estimates		(1,091,000	)	2,081,000		1,062,000
Accretion of discount		796,000		262,000		97,000
Discounted future net cash flows—
Beginning of year		7,958,000		2,622,000		966,000
End of year	$	1,555,000		7,958,000		2,622,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-149

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	211,858	128,863	91,878	55,399
Total expenses		25,257	31,026	35,274	26,762
Net income		186,601	97,837	56,604	28,637
Net income per limited partners unit		17.10	8.88	5.03	2.55
2000:
Total revenues	$	137,733	170,833	177,805	148,917
Total expenses		25,519	21,637	23,433	17,201
Net income		112,214	149,196	154,372	131,716
Net income per limited partners unit		10.25	13.70	14.15	12.12

F-150

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Oil & Gas Income Fund X-A, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund X-A, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Oil & Gas Income Fund X-A, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-151

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	4,057		21,313		16,448
Receivable from Managing General Partner		10,660		—		58,391
Total current assets		14,717		21,313		74,839
Oil and gas properties—using the full-cost method of accounting		3,825,257		3,817,786		3,796,887
Less accumulated depreciation, depletion and amortization		3,712,386		3,707,386		3,695,386
Net oil and gas properties		112,871		110,400		101,501
	$	127,588		131,713		176,340
LIABILITIES AND PARTNERS’ EQUITY
Current liability—
Distributions payable	$	336		336		677
Payable to Managing General Partner		—		6,787		—
Total current liabilities		336		7,123		677
Partners’ equity:
General partners		(18,602	)	(19,368	)	(15,461	)
Limited partners		145,854		143,958		191,124
Total partners’ equity		127,252		124,590		175,663
	$	127,588		131,713		176,340

The accompanying notes are an integral part of these financial statements.

F-152

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas income	$	155,810	216,124	346,699	447,179	273,357
Interest		—	217	231	336	—
Miscellaneous settlement		4,882	—	—	—	—
		160,692	216,341	346,930	447,515	273,357
Expenses
Production		111,253	122,760	241,723	231,020	207,725
General and administrative		41,777	42,054	84,280	82,764	83,448
Depreciation, depletion and amortization		5,000	5,000	12,000	8,000	9,000
		158,030	169,814	338,003	321,784	300,173
Net income (loss)	$	2,662	46,527	8,927	125,731	(26,816	)
Net income (loss) allocated to:
Managing General Partner	$	690	4,637	1,883	12,036	(1,604	)
General Partner	$	76	516	210	1,337	(178	)
Limited partners	$	1,896	41,374	6,834	112,358	(25,034	)
Per limited partner unit	$	18	3.95	65	10.72	(2.39	)

The accompanying notes are an integral part of these financial statements.

F-153

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(26,795	)	177,569		150,774
Net loss		(1,782	)	(25,034	)	(26,816	)
Balance at December 31, 1999		(28,577	)	152,535		123,958
Net income		13,373		112,358		125,731
Distributions		(257	)	(73,769	)	(74,026	)
Balance at December 31, 2000		(15,461	)	191,124		175,663
Net income		2,093		6,834		8,927
Distributions		(6,000	)	(54,000	)	(60,000	)
Balance at December 31, 2001		(19,368	)	143,958		124,590
Net income		766		1,896		2,662
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(18,602	)	145,854		127,252

The accompanying notes are an integral part of these financial statements.

F-154

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	140,019		236,165		391,231		415,489		248,321
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(154,686	)	(166,553	)	(305,357	)	(332,733	)	(305,667	)
Interest received		—		217		231		336		—
Miscellaneous settlement		4,882		—		—		—		—
Net cash provided by (used in) operating activities		(9,785	)	69,829		86,105		83,092		(57,346	)
Cash flows from investing activities:
Additions to oil and gas properties		(7,471	)	(12,079	)	(20,899	)	—		(1,252	)
Sale of oil and gas properties		—		—		—		6,312		44,870
Net cash (used in) provided by investing activities		(7,471	)	(12,079	)	(20,899	)	6,312		43,618
Cash flows (used in) provided by financing activities:
Distributions to partners		—		(60,299	)	(60,341	)	(74,160	)	260
Net (decrease) increase in cash and cash equivalents		(17,256	)	(2,549	)	4,865		15,244		(13,468	)
Beginning of year		21,313		16,448		16,448		1,204		14,672
End of year	$	4,057		13,899		21,313		16,448		1,204
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss)	$	2,662		46,527		8,927		125,731		(26,816	)
Adjustments to reconcile net income(loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		5,000		5,000		12,000		8,000		9,000
Decrease (increase) in receivables		(15,791	)	20,041		44,532		(31,690	)	(25,036	)
(Decrease) increase in payables		(1,656	)	(1,739	)	20,646		(18,949	)	(14,494	)
Net cash provided by (used in) operating activities	$	(9,785	)	69,829		86,105		83,092		(57,346	)

The accompanying notes are an integral part of these financial statements.

F-155

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Oil and Gas Income Fund X-A, L.P. was organized under the laws of the state of Delaware on January 29, 1990, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs, and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Syndication costs	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and as properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

F-156

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $53,919 and $67,656, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

F-157

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999 there were 10,484 limited partner units outstanding held by 569, 564 and 564 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

F-158

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance.

The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which

F-159

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

may be required, the determination of the Partnership’s liability in proportion to, other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $39,800, $45,100 and $56,700 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $15,300, $12,800 and $3,200 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $78,000 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses.

(Payable) Receivables (to) from Southwest Royalties, Inc., the Managing General Partner, of approximately $(6,800) and $58,400 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership approximately $300, $100 and $200 for the years ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 84% of the Partnership’s total oil and gas production during 2001: Plains Marketing for 52%, Navajo Refining Company for 22% and Duke Energy Field Services for 10%. Four purchasers accounted for 85% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 27%, Eaglewing Trading Inc. for 23%, Navajo Refining Company for 22% and Phillips 66 for 13%. Three purchasers accounted for 73% of the Partnership’s total oil and gas production during 1999: Scurlock Permian Corporation for 27%, Navajo Refining Company for 26% and Eaglewing Trading Inc. for 20%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-160

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	38,000		147,000
Revisions of previous estimates	120,000		32,000
Production	(15,000	)	(16,000	)
December 31, 1999	143,000		163,000
Revisions of previous estimates	21,000		20,000
Production	(14,000	)	(16,000	)
December 31, 2000	150,000		167,000
Revisions of previous estimates	(8,000	)	(41,000	)
Production	(13,000	)	(11,000	)
December 31, 2001	129,000		115,000
Proved developed reserves—
December 31, 1999	142,000		155,000
December 31, 2000	138,000		146,000
December 31, 2001	126,000		102,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $16.61 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.40 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-161

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves in conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	2,419,000	5,321,000	3,629,000
Production and development costs		1,379,000	2,497,000	2,097,000
Future net cash flows		1,040,000	2,824,000	1,532,000
10% annual discount for estimated timing of cash flows		461,000	1,262,000	609,000
Standardized measure of discounted future net cash flows	$	579,000	1,562,000	923,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(105,000	)	(216,000	)	(66,000	)
Changes in prices and production costs		(877,000	)	624,000		172,000
Changes of production rates (timing) and others		(99,000	)	(74,000	)	(48,000	)
Revisions of previous quantities estimates		(58,000	)	213,000		680,000
Accretion of discount		156,000		92,000		17,000
Discounted future net cash flows—
Beginning of year		1,562,000		923,000		168,000
End of year	$	579,000		1,562,000		923,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-162

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third		Fourth
2001:
Total revenues	$	117,399	98,942	72,974		57,615
Total expenses		94,065	75,746	84,358		83,834
Net income (loss)		23,334	23,196	(11,384	)	(26,219	)
Net income (loss) per limited partners unit		1.97	1.97	(1.02	)	(2.27	)
2000:
Total revenues	$	103,354	100,992	122,358		120,811
Total expenses		76,489	75,981	86,078		83,236
Net income		26,865	25,011	36,280		37,575
Net income per limited partners unit		2.28	2.14	3.09		3.22

F-163

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties Institutional

Income Fund X-A, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund X-A, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund X-A, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-164

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	13,126		13,299		61,502
Receivable from Managing General Partner		34,966		27,388		84,202
Total current assets		48,092		40,687		145,704
Oil and gas properties—using the full-cost method of accounting		4,239,490		4,239,490		4,239,490
Less accumulated depreciation, depletion and amortization		4,081,143		4,076,143		4,058,143
Net oil and gas properties		158,347		163,347		181,347
	$	206,439		204,034		327,051
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities—distribution payable	$	342		421		119
Partners’ equity:
General Partner		(11,979	)	(12,727	)	(2,195	)
Limited partners		218,076		216,340		329,127
Total partners’ equity		206,097		203,613		326,932
	$	206,439		204,034		327,051

The accompanying notes are an integral part of these financial statements.

F-165

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	53,156	140,126	189,907	317,883	133,177
Interest		—	413	492	650	94
Miscellaneous income		2,036	—	—	1,935	—
		55,192	140,539	190,399	320,468	133,271
Expenses
General and administrative		47,708	47,906	95,625	94,326	95,635
Depreciation, depletion and amortization		5,000	8,000	18,000	12,000	13,000
		52,708	55,906	113,625	106,326	108,635
Net income	$	2,484	84,633	76,774	214,142	24,636
Net income allocated to:
Managing General Partner	$	674	8,337	8,530	20,353	3,388
General Partner	$	74	926	947	2,261	376
Limited partners	$	1,736	75,370	67,297	191,528	20,872
Per limited partner unit	$	.15	6.66	5.95	16.93	1.84

The accompanying notes are an integral part of these financial statements.

F-166

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(22,491	)	265,967		243,476
Net income		3,764		20,872		24,636
Distributions		—		—		—
Balance at December 31, 1999		(18,727	)	286,839		268,112
Net income		22,614		191,528		214,142
Distributions		(6,082	)	(149,240	)	(155,322	)
Balance at December 31, 2000		(2,195	)	329,127		326,932
Net income		9,477		67,297		76,774
Distributions		(20,009	)	(180,084	)	(200,093	)
Balance at December 31, 2001		(12,727	)	216,340		203,613
Net income		748		1,736		2,484
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(11,979	)	218,076		206,097

The accompanying notes are an integral part of these financial statements.

F-167

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interests	$	42,061		172,528		246,980		279,138		72,643
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(44,191	)	(47,426	)	(95,884	)	(94,861	)	(96,166	)
Interest received		—		413		492		650		94
Miscellaneous settlement		2,036		—		—		—		—
Net cash (used in) provided by operating activities		(94	)	125,515		151,588		184,927		(23,429	)
Cash flows from investing activities:
Sale of oil and gas properties		—		—		—		—		44,871
Additions of oil and gas properties		—		—		—		(5	)	—
Net cash (used in) provided by investing activities		—		—		—		(5	)	44,871
Cash flows (used in) provided by financing activities:
Distributions to partners		(79	)	(164,770	)	(199,791	)	(155,632	)	139
Net (decrease) increase in cash and cash equivalents		(173	)	(39,255	)	(48,203	)	29,290		21,581
Beginning of year		13,299		61,502		61,502		32,212		10,631
End of year	$	13,126		22,247		13,299		61,502		32,212
Reconciliation of net income to net cash provided by (used in) operating activities:
Net income	$	2,484		84,633		76,774		214,142		24,636
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		5,000		8,000		18,000		12,000		13,000
(Increase) decrease in receivables		(11,095	)	32,402		57,073		(40,680	)	(60,534	)
Increase (decrease) in payables		3,517		480		(259	)	(535	)	(531	)
Net cash (used in) provided by operating activities	$	(94	)	125,515		151,588		184,927		(23,429	)

The accompanying notes are an integral part of these financial statements.

F-168

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties Institutional Income Fund X-A, L.P. was organized under the laws of the state of Delaware on November 27, 1990 for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization or organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion, and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

F-169

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $518,992 and $559,264, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

F-170

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 11,316 limited partner units outstanding held by 580 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

F-171

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

F-172

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $43,000, $48,400 and $60,300 for the years ended December 31, 2001, 2000, and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $18,400, $18,300 and $8,900 for the years ended December 31, 2001, 2000, and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $90,000 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $27,400 and $84,200 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services for the year 2001 and approximately $100 for the year ended December 31, 2000. There were no legal services provided for the year ending December 31, 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 59% of the Partnership’s total oil and gas production during 2001: Plains Marketing LP for 42% and Navajo Refining Company Inc. for 17%. Four purchasers accounted for 72% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 25%, Eaglewing Trading Inc. for 18%, Navajo Refining Company Inc. for 17% and Phillip 66 for 12%. Four purchasers accounted for 69% of the Partnership’s total oil and gas production during 1999: Scurlock Permian Corporation for 24%, Navajo Refining Company Inc. for 20%, Eaglewing Trading Inc. for 15% and Phillips 66 for 10%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-173

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	46,000		223,000
Revisions of previous estimates	185,000		94,000
Production	(17,000	)	(39,000	)
December 31, 1999	214,000		278,000
Revisions of previous estimates	19,000		87,000
Production	(15,000	)	(33,000	)
December 31, 2000	218,000		332,000
Revisions of previous estimates	(16,000	)	(78,000	)
Production	(15,000	)	(33,000	)
December 31, 2001	187,000		221,000
Proved developed reserves—
December 31, 1999	213,000		270,000
December 31, 2000	205,000		311,000
December 31, 2001	184,000		209,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $16.88 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.33 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-174

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	2,042,000	5,503,000	3,095,000
10% annual discount for estimated timing of cash flows		947,000	2,679,000	1,435,000
Standardized measure of discounted future net cash flows	$	1,095,000	2,824,000	1,660,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(190,000	)	(318,000	)	(133,000	)
Changes in prices and production costs		(1,612,000	)	1,058,000		307,000
Changes of production rates (timing) and others		(68,000	)	(88,000	)	(69,000	)
Revisions of previous quantities estimates		(141,000	)	346,000		1,279,000
Accretion of discount		282,000		166,000		25,000
Discounted future net cash flows—
Beginning of year		2,824,000		1,660,000		251,000
End of year	$	1,095,000		2,824,000		1,660,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-175

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third		Fourth
2001:
Total revenues	$	91,036	49,502	25,880		23,981
Total expenses		28,794	27,112	29,635		28,084
Net income (loss)		62,242	22,390	(3,755	)	(4,103	)
Net income (loss) per limited partners unit		4.91	1.75	(.35	)	(.36	)
2000:
Total revenues	$	67,654	66,976	81,523		104,315
Total expenses		28,064	24,827	27,807		25,628
Net income		39,590	42,149	53,716		78,687
Net income per limited partners unit		3.11	3.34	4.24		6.23

F-176

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Oil & Gas

Income Fund X-B, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund X-B, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Oil & Gas Income Fund X-B, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-177

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	10,774		13,190		92,659
Receivable from Managing General Partner		70,350		39,827		152,562
Total current assets		81,124		53,017		245,221
Oil and gas properties—using the full-cost method of accounting		4,470,138		4,459,997		4,443,303
Less accumulated depreciation, depletion and amortization		4,166,706		4,149,706		4,084,706
Net oil and gas properties		303,432		310,291		358,597
	$	384,556		363,308		603,818
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	373		373		58
Partners’ equity:
General partners		(2,394	)	(6,219	)	11,363
Limited partners		386,577		369,154		592,397
Total partners’ equity		384,183		362,935		603,760
	$	384,556		363,308		603,818

The accompanying notes are an integral part of these financial statements.

F-178

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas income	$	346,059	526,481	869,806	1,150,000	734,011
Interest from operations		52	2,119	2,829	4,483	1,224
Miscellaneous income		—	—	—	270	—
		346,111	528,600	872,635	1,154,753	735,235
Expenses
Production		269,250	278,494	591,157	552,793	484,476
General and administrative		38,613	38,819	77,860	76,840	77,072
Depreciation, depletion and amortization		17,000	24,000	65,000	29,000	30,000
		324,863	341,313	734,017	658,633	591,548
Net income	$	21,248	187,287	138,618	496,120	143,687
Net income allocated to:
Managing General Partner	$	3,442	19,016	18,326	47,261	15,632
General Partner	$	383	2,113	2,036	5,251	1,737
Limited partners	$	17,423	166,158	118,256	443,608	126,318
Per limited partner unit	$	1.60	15.26	10.86	40.74	11.60

The accompanying notes are an integral part of these financial statements.

F-179

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(10,854	)	459,719		448,865
Net income		17,369		126,318		143,687
Distributions		(7,000	)	(71,268	)	(78,268	)
Balance at December 31, 1999		(485	)	514,769		514,284
Net income		52,512		443,608		496,120
Distributions		(40,664	)	(365,980	)	(406,644	)
Balance at December 31, 2000		11,363		592,397		603,760
Net income		20,362		118,256		138,618
Distributions		(37,944	)	(341,499	)	(379,443	)
Balance at December 31, 2001		(6,219	)	369,154		362,935
Net income		3,825		17,423		21,248
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(2,394	)	386,577		384,183

The accompanying notes are an integral part of these financial statements.

F-180

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	318,994		552,644		989,012		1,087,471		648,055
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(311,321	)	(329,503	)	(675,488	)	(598,462	)	(575,015	)
Interest received		52		2,119		2,829		4,483		1,224
Net cash provided by operating activities		7,725		225,260		316,353		493,492		74,264
Cash flows used in investing activities:
Additions to oil and gas properties		(10,141	)	(29,346	)	(16,694	)	(29,520	)	(7,653	)
Cash flows used in financing activities:
Distributions to partners		—		(252,017	)	(379,128	)	(406,658	)	(78,293	)
Net (decrease) increase in cash and cash equivalents		(2,416	)	(56,103	)	(79,469	)	57,314		(11,682	)
Beginning of period		13,190		92,659		92,659		35,345		47,027
End of period	$	10,774		36,556		13,190		92,659		35,345
Reconciliation of net income to net cash provided by operating activities:
Net income	$	21,248		187,287		138,618		496,120		143,687
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,000		24,000		65,000		29,000		30,000
Decrease (increase) in receivables		(27,065	)	26,163		119,206		(62,799	)	(85,956	)
(Decrease) increase in payables		(3,458	)	(12,190	)	(6,471	)	31,171		(13,467	)
Net cash provided by operating activities	$	7,725		225,260		316,353		493,492		74,264

The accompanying notes are an integral part of these financial statements.

F-181

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Oil & Gas Income Fund X-B, L.P. was organized under the laws of the state of Delaware on November 27, 1990 for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization or organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion, and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the production, or both could be changed significantly in the near term due

F-182

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes, the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $236,284 and $288,582, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

F-183

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of per Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 10,889 limited partner units outstanding held by 527, 527 and 528 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

F-184

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.

However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the

F-185

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $164,900, $158,900 and $161,500 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $6,300, $7,600 and $2,400 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $72,000 during 2001, 2000 and 1999, as an administrative fee for reimbursement of indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $39,800 and $152,600 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 71% of the Partnership’s total oil and gas production during 2001: Teppco Crude Oil LLC for 40%, Plains Marketing LP for 21% and Raptor Resources Inc. for 10%. Three purchasers accounted for 79% of the Partnership’s total oil and gas production during 2000: Teppco Crude Oil LLC for 47%, Plains Marketing LP for 20% and Mobil Corporation for 12%. Three purchasers accounted for 78% of the Partnership’s total oil and gas production during 1999: Teppco Crude Oil for 46%, Scurlock Permian LLC for 19% and Mobil Corporation for 13%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-186

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	80,000		383,000
Revisions of estimates in place	297,000		132,000
Production	(38,000	)	(55,000	)
December 31, 1999	339,000		460,000
Revisions of estimates in place	6,000		221,000
Production	(34,000	)	(51,000	)
December 31, 2000	311,000		630,000
Revisions of estimates in place	(121,000	)	(243,000	)
Production	(31,000	)	(52,000	)
December 31, 2001	159,000		335,000
Proved developed reserves—
December 31, 1999	327,000		402,000
December 31, 2000	308,000		576,000
December 31, 2001	156,000		326,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.48 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.00 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-187

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	3,614,000	14,086,000	8,807,000
Production and development costs		2,137,000	6,718,000	5,155,000
Future net cash flows		1,477,000	7,368,000	3,652,000
10% annual discount for estimated timing of cash flows		670,000	3,584,000	1,553,000
Standardized measure of discounted future net cash flows	$	807,000	3,784,000	2,099,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(279,000	)	(597,000	)	(250,000	)
Changes in prices and production costs		(2,457,000	)	1,833,000		395,000
Changes of production rates (timing) and others		(12,000	)	(150,000	)	(75,000	)
Revisions of previous quantities estimates		(607,000	)	389,000		1,611,000
Accretion of discount		378,000		210,000		38,000
Discounted future net cash flows—
Beginning of year		3,784,000		2,099,000		380,000
End of year	$	807,000		3,784,000		2,099,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-188

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third		Fourth
2001:
Total revenues	$	278,405	250,194	197,207		146,829
Total expenses		167,331	173,982	194,508		198,196
Net income (loss)		111,074	76,212	2,699		(51,367	)
Net income (loss) per limited partners unit		9.09	6.17	(.02	)	(4.38	)
2000:
Total revenues	$	255,757	271,828	302,886		324,282
Total expenses		187,818	150,890	171,611		148,314
Net income		67,939	120,938	131,275		175,968
Net income per limited partners unit		5.53	9.99	10.80		14.42

F-189

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties Institutional

Income Fund X-B, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund X-B, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund X-B, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-190

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	36,089		48,952		80,863
Receivable from Managing General Partner		67,600		53,962		117,172
Total current assets		103,689		102,914		198,035
Oil and gas properties—using the full-cost method of accounting		3,888,882		3,888,882		3,888,882
Less accumulated depreciation, depletion and amortization		3,524,853		3,510,853		3,455,853
Net oil and gas properties		364,029		378,029		433,029
	$	467,718		480,943		631,064
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	1		37		1
Partners’ equity:
General partners		(41,750	)	(41,831	)	(32,315	)
Limited partners		509,467		522,737		663,378
Total partners’ equity		467,717		480,906		631,063
	$	467,718		480,943		631,064

The accompanying notes are an integral part of these financial statements.

F-191

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	89,060	245,183	381,306	433,937	193,199
Interest from operations		239	2,016	3,220	3,391	2,049
		89,299	247,199	384,526	437,328	195,248
Expenses
General and administrative		38,488	38,859	77,887	76,486	76,975
Depreciation, depletion and amortization		14,000	22,000	55,000	25,000	29,000
		52,488	60,859	132,887	101,486	105,975
Net income	$	36,811	186,340	251,639	335,842	89,273
Net income allocated to:
Managing General Partner	$	4,573	18,751	27,598	32,476	10,644
General Partner	$	508	2,083	3,066	3,608	1,183
Limited partners	$	31,730	165,506	220,975	299,758	77,446
Per limited partner unit	$	2.84	14.80	19.76	26.81	6.93

The accompanying notes are an integral part of these financial statements.

F-192

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(40,552	)	679,752		639,200
Net income		11,827		77,446		89,273
Distributions		(12,000	)	(144,511	)	(156,511	)
Balance at December 31, 1999		(40,725	)	612,687		571,962
Net income		36,084		299,758		335,842
Distributions		(27,674	)	(249,067	)	(276,741	)
Balance at December 31, 2000		(32,315	)	663,378		631,063
Net income		30,664		220,975		251,639
Distributions		(40,180	)	(361,616	)	(401,796	)
Balance at December 31, 2001		(41,831	)	522,737		480,906
Net income		5,081		31,730		36,811
Distributions		(5,000	)	(45,000	)	(50,000	)
Balance at June 30, 2002 (unaudited)	$	(41,750	)	509,467		467,717

The accompanying notes are an integral part of these financial statements.

F-193

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interests	$	73,754		248,546		443,948		409,263		116,940
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(36,820	)	(39,365	)	(77,319	)	(75,989	)	(78,608	)
Interest received		239		2,016		3,220		3,391		2,049
Net cash provided by operating activities		37,173		211,197		369,849		336,665		40,381
Cash flows provided by investing activities:
Sale of oil and gas properties		—		—		—		—		7,990
Cash flows used in financing activities:
Distributions to partners		(50,036	)	(224,952	)	(401,760	)	(276,779	)	(156,521	)
Net (decrease) increase in cash and cash equivalents		(12,863	)	(13,755	)	(31,911	)	59,886		(108,150	)
Beginning of period		48,952		80,863		80,863		20,977		129,127
End of period	$	36,089		67,108		48,952		80,863		20,977
Reconciliation of net income to net cash provided by operating activities:
Net income	$	36,811		186,340		251,639		335,842		89,273
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		14,000		22,000		55,000		25,000		29,000
(Increase) decrease in receivables		(15,306	)	3,363		62,642		(24,674	)	(76,259	)
Increase (decrease) in payables		1,668		(506	)	568		497		(1,633	)
Net cash provided by operating activities	$	37,173		211,197		369,849		336,665		40,381

The accompanying notes are an integral part of these financial statements.

F-194

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties Institutional Income Fund X-B, L.P. was organized under the laws of the state of Delaware on November 27, 1990 for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to

F-195

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of the oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

F-196

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $662,619 and $686,178, respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999 there were 11,181 limited partner units outstanding held by 593, 589 and 602 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

F-197

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

F-198

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $76,400, $74,000 and $80,300 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $14,500, $20,800 and $16,700 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $72,000 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $54,000 and $117,200 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Four purchasers accounted for 67% of the Partnership’s total oil and gas production during 2001: Plains Marketing LP for 29%, Duke Energy Field Services for 17%, Mobil Corporation for 11% and Exxon Company USA for 10%. Three purchasers accounted for 78% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 34%, Mobil Corporation for 24% and Phillips 66 for 20%. Three purchasers accounted for 73% of the Partnership’s total oil and production during 1999: Scurlock Permian LLC for 30%, Mobil Corporation for 26% and Phillips 66 for 17%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other

F-199

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	95,000		504,000
Revisions of previous estimates	241,000		247,000
Production	(26,000	)	(67,000	)
December 31, 1999	310,000		684,000
Revisions of previous estimates	13,000		173,000
Production	(22,000	)	(64,000	)
December 31, 2000	301,000		793,000
Revisions of previous estimates	(84,000	)	(101,000	)
Production	(22,000	)	(77,000	)
December 31, 2001	195,000		615,000
Proved developed reserves—
December 31, 1999	298,000		604,000
December 31, 2000	297,000		715,000
December 31, 2001	192,000		606,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.44 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $1.80 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

F-200

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying the industry audit standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	1,896,000	8,786,000	4,023,000
10% annual discount for estimated timing of cash flows		813,000	4,193,000	1,810,000
Standardized measure of discounted future net cash flows	$	1,083,000	4,593,000	2,213,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(382,000	)	(434,000	)	(193,000	)
Changes in prices and production costs		(3,323,000	)	2,284,000		511,000
Changes of production rates (timing) and others		103,000		(135,000	)	(122,000	)
Revisions of previous quantities estimates		(367,000	)	444,000		1,473,000
Accretion of discount		459,000		221,000		49,000
Discounted future net cash flows—
Beginning of year		4,593,000		2,213,000		495,000
End of year	$	1,083,000		4,593,000		2,213,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-201

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	147,305	99,894	66,097	71,230
Total expenses		29,157	31,702	41,160	30,868
Net income		118,148	68,192	24,937	40,362
Net income per limited partners unit		9.42	5.38	1.81	3.15
2000:
Total revenues	$	50,786	93,488	137,006	156,048
Total expenses		27,251	23,184	29,170	21,881
Net income		23,535	70,304	107,836	134,167
Net income per limited partners unit		1.82	5.62	8.59	10.77

F-202

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Oil & Gas

Income Fund X-C, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund X-C, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Oil & Gas Income Fund X-C, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-203

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	18,691		28,071		65,399
Receivable from Managing General Partner		17,705		38,135		112,098
Total current assets		36,396		66,206		177,497
Oil and gas properties—using the full-cost method of accounting		2,437,320		2,418,934		2,411,782
Less accumulated depreciation, depletion and amortization		2,235,496		2,215,496		2,083,496
Net oil and gas properties		201,824		203,438		328,286
	$	238,220		269,644		505,783
LIABILITIES AND PARTNERS’ EQUITY
Current liability—Distribution payable	$	131		131		—
Partners’ equity:
General partners		(13,952	)	(12,810	)	(2,383	)
Limited partners		252,041		282,323		508,166
Total partners’ equity		238,089		269,513		505,783
	$	238,220		269,644		505,783

The accompanying notes are an integral part of these financial statements.

F-204

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,				For the years ended December 31,
	2002			2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas income	$	309,316		498,314	871,673	929,367	734,832
Interest from operations		89		2,003	2,961	3,199	1,357
		309,405		500,317	874,634	932,566	736,189
Expenses
Production		300,294		284,734	575,963	571,449	510,036
General and administrative		20,535		20,666	41,462	40,595	41,343
Depreciation, depletion and amortization		20,000		50,000	132,000	38,000	50,000
		340,829		355,400	749,425	650,044	601,379
Net income (loss)	$	(31,424	)	144,917	125,209	282,522	134,810
Net income (loss) allocated to:
Managing General Partner	$	(1,028	)	17,543	23,149	28,848	16,633
General Partner	$	(114	)	1,949	2,572	3,204	1,848
Limited partners	$	(30,282	)	125,425	99,488	250,470	116,329
Per limited partner unit	$	(4.85	)	20.08	15.93	40.10	18.62

The accompanying notes are an integral part of these financial statements.

F-205

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(15,686	)	494,641		478,955
Net income		18,481		116,329		134,810
Distributions		(9,500	)	(103,704	)	(113,204	)
Balance at December 31, 1999		(6,705	)	507,266		500,561
Net income		32,052		250,470		282,522
Distributions		(27,730	)	(249,570	)	(277,300	)
Balance at December 31, 2000		(2,383	)	508,166		505,783
Net income		25,721		99,488		125,209
Distributions		(36,148	)	(325,331	)	(361,479	)
Balance at December 31, 2001		(12,810	)	282,323		269,513
Net loss		(1,142	)	(30,282	)	(31,424	)
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(13,952	)	252,041		238,089

The accompanying notes are an integral part of these financial statements.

F-206

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	284,475		550,219		945,276		929,927		657,582
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(275,558	)	(310,228	)	(617,065	)	(601,992	)	(538,938	)
Interest received		89		2,003		2,961		3,199		1,357
Net cash provided by operating activities		9,006		241,994		331,172		331,134		120,001
Cash flows from investing activities:
Additions to oil and gas properties		(18,386	)	—		(7,152	)	(14,870	)	(22,035	)
Sale of oil and gas properties		—		177		—		—		18,762
Net cash (used in) provided by investing activities		(18,386	)	177		(7,152	)	(14,870	)	(3,273	)
Cash flows used in financing activities:
Distributions to partners		—		(225,000	)	(361,348	)	(277,300	)	(113,111	)
Net (decrease) increase in cash and cash equivalents		(9,380	)	17,171		(37,328	)	38,964		3,617
Beginning of period		28,071		65,399		65,399		26,435		22,818
End of period	$	18,691		82,570		28,071		65,399		26,435
Reconciliation of net income (loss) to net cash provided by operating activities:
Net income (loss)	$	(31,424	)	144,917		125,209		282,522		134,810
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		20,000		50,000		132,000		38,000		50,000
(Increase) decrease in receivables		(24,841	)	51,905		73,603		560		(77,250	)
Increase (decrease) in payables		45,271		(4,828	)	360		10,052		12,441
Net cash provided by operating activities	$	9,006		241,994		331,172		331,134		120,001

The accompanying notes are an integral part of these financial statements.

F-207

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Oil & Gas Income Fund X-C, L.P. was organized under the laws of the state of Delaware on September 20, 1991, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to several purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Syndication costs	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to

F-208

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of the oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $109,421 and $35,661 respectively, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

F-209

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999 there were 6,246 limited partner units outstanding held by 291 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those

F-210

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not

F-211

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $180,000, $172,200 and $173,800, respectively, for the years ended December 31, 2001, 2000 and 1999. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $16,200, $15,000 and $4,100 for the year ended December 31, 2001, 2000 and 1999.

Southwest Royalties, Inc., the Managing General Partner, was paid $36,000 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $38,100 and $112,100 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the year ended December 31, 2001, 2000 and 1999.

6.    Major Customers

The Managing General Partner intends that no material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 85% of the Partnership’s total oil and gas production during 2001: Teppco Crude Oil LLC for 60%, George L McLeod LP for 14% and Plains Marketing LP for 11%. Two purchasers accounted for 84% of the Partnership’s total oil and gas production during 2000: Teppco Crude oil LLC for 73% and Plains Marketing LP for 11%. Three purchasers accounted for 82% of the Partnership’s total oil and gas production during 1999: Teppco Crude Oil LLC for 62%, George L. McLeod for 10% and Scurlock Permian LLC for 10%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

F-212

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	40,000		573,000
Revisions of previous estimates	163,000		171,000
Production	(35,000	)	(75,000	)
December 31, 1999	168,000		669,000
Revisions of previous estimates	(23,000	)	(78,000	)
Production	(30,000	)	(28,000	)
December 31, 2000	115,000		563,000
Revisions of previous estimates	(58,000	)	(53,000	)
Production	(29,000	)	(55,000	)
December 31, 2001	28,000		455,000
Proved developed reserves—
December 31, 1999	168,000		632,000
December 31, 2000	115,000		563,000
December 31, 2001	28,000		455,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.48 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $1.85 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-213

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farmout arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farmout, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	1,350,000	8,086,000	5,209,000
Production and development costs		718,000	3,243,000	3,008,000
Future net cash flows		632,000	4,843,000	2,201,000
10% annual discount for estimated timing of cash flows		236,000	2,314,000	861,000
Standardized measure of discounted future net cash flows	$	396,000	2,529,000	1,340,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(296,000	)	(354,000	)	(225,000	)
Changes in prices and production costs		(2,179,000	)	1,966,000		(45,000	)
Changes of production rates (timing) and others		344,000		(121,000	)	(48,000	)
Revisions of previous quantities estimates		(255,000	)	(436,000	)	918,000
Accretion of discount		253,000		134,000		67,000
Discounted future net cash flows—
Beginning of year		2,529,000		1,340,000		673,000
End of year	$	396,000		2,529,000		1,340,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-214

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First			Second	Third		Fourth
2001:
Total revenues	$	298,866	*	201,450	181,362		192,956
Total expenses		165,793		189,606	200,743		193,283
Net income (loss)		133,073		11,844	(19,381	)	(327	)
Net income (loss) per limited partners unit		18.87		1.21	(3.64	)	(.51	)
2000:
Total revenues	$	221,704		203,848	250,753		256,261
Total expenses		181,790		163,207	138,732		166,315
Net income		39,914		40,641	112,021		89,946
Net income per limited partners unit		5.54		5.79	15.95		12.82

* The first quarter of 2001 includes an increase of revenues by $42,000 for an under accrual of estimated revenues related to the prior year.

F-215

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Royalties Institutional

Income Fund X-C, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund X-C, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund X-C, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-216

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	12,311		15,300		87,960
Receivable from Managing General Partner		14,607		35,973		111,036
Total current assets		26,918		51,273		198,996
Oil and gas properties—using the full-method of accounting		2,221,662		2,221,662		2,221,662
Less accumulated depreciation, depletion and amortization		2,081,479		2,066,479		1,960,479
Net oil and gas properties		140,183		155,183		261,183
	$	167,101		206,456		460,179
LIABILITIES AND PARTNERS’ EQUITY
Partners’ equity:
General partners	$	(29,358	)	(26,923	)	(12,149	)
Limited partners		196,459		233,379		472,328
Total partners’ equity		167,101		206,456		460,179
	$	167,101		206,456		460,179

The accompanying notes are an integral part of these financial statements.

F-217

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,				For the years ended December 31,
	2002			2001	2001	2000	1999
	(unaudited)
Revenues
Income from net profits interests	$	(5,028	)	169,882	220,775	386,562	180,192
Interest from operations		57		2,047	2,745	3,579	771
Miscellaneous settlement		1,131		—	—	—	—
		(3,840	)	171,929	223,520	390,141	180,963
Expenses
General and administrative		20,515		19,989	40,655	40,195	41,876
Depreciation, depletion and amortization		15,000		36,000	106,000	31,000	40,000
		35,515		55,989	146,655	71,195	81,876
Net income (loss)	$	(39,355	)	115,940	76,865	318,946	99,087
Net income (loss) allocated to:
Managing General Partner	$	(2,192	)	13,675	16,458	31,496	12,518
General partner	$	(243	)	1,519	1,828	3,499	1,391
Limited partners	$	(36,920	)	100,746	58,579	283,951	85,178
Per limited partner unit	$	(6.17	)	16.84	9.79	47.46	14.24

The accompanying notes are an integral part of these financial statements.

F-218

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partners			Limited Partners		Total
Balance at January 1, 1999	$	(26,648	)	429,121		402,473
Net income		13,909		85,178		99,087
Distributions		(5,800	)	(68,477	)	(74,277	)
Balance at December 31, 1999		(18,539	)	445,822		427,283
Net income		34,995		283,951		318,946
Distributions		(28,605	)	(257,445	)	(286,050	)
Balance at December 31, 2000		(12,149	)	472,328		460,179
Net income		18,286		58,579		76,865
Distributions		(33,060	)	(297,528	)	(330,588	)
Balance at December 31, 2001		(26,923	)	233,379		206,456
Net loss		(2,435	)	(36,920	)	(39,355	)
Distributions		—		—		—
Balance at June 30, 2002 (unaudited)	$	(29,358	)	196,459		167,101

The accompanying notes are an integral part of these financial statements.

F-219

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from net profits interests	$	14,300		211,986		296,433		389,892		116,032
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(18,477	)	(21,088	)	(41,251	)	(41,557	)	(44,517	)
Interest received		57		2,047		2,745		3,579		771
Miscellaneous settlement		1,131		—		—		—		—
Net cash (used in) provided by operating activities		(2,989	)	192,945		257,927		351,914		72,286
Cash flows provided by investing activities:
Sale of oil and gas properties		—		—		—		—		18,762
Cash flows used in financing activities:
Distributions to partners		—		(220,000	)	(330,587	)	(286,052	)	(74,291	)
Net (decrease) increase in cash and equivalents		(2,989	)	(27,055	)	(72,660	)	65,862		16,757
Beginning of period		15,300		87,960		87,960		22,098		5,341
End of period	$	12,311		60,905		15,300		87,960		22,098
Reconciliation of net income (loss) to net cash (used in) provided by operating activities:
Net income (loss)	$	(39,355	)	115,940		76,865		318,946		99,087
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization		15,000		36,000		106,000		31,000		40,000
Decrease (increase) in receivables		19,328		42,104		75,655		3,330		(64,160	)
Increase (decrease) in payables		2,038		(1,099	)	(593	)	(1,362	)	(2,641	)
Net cash (used in) provided by operating activities	$	(2,989	)	192,945		257,927		351,914		72,286

The accompanying notes are an integral part of these financial statements.

F-220

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Royalties Institutional Income Fund X-C, L.P. was organized under the laws of the state of Delaware on September 20, 1991, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to several purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, as the individual general partner. Revenues, costs and expenses are allocated as follows:

	Limited Partners		General Partners
Interest income on capital contributions	100	%	—
Oil and gas sales	90	%	10	%
All other revenues	90	%	10	%
Organization and offering costs(1)	100	%	—
Syndication costs	100	%	—
Amortization of organization costs	100	%	—
Property acquisition costs	100	%	—
Gain/loss on property disposition	90	%	10	%
Operating and administrative costs(2)	90	%	10	%
Depreciation, depletion and amortization of oil and gas properties	100	%	—
All other costs	90	%	10	%

(1) All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to

F-221

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership’s interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method, the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

F-222

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is $448,747 and $386,853 more, respectively, than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999 there were 5,983 limited partner units outstanding held by 334, 333 and 336 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Liquidity—MD&A

The Partnership accrued an oil and gas revenue receivable (included in the receivable from the Managing General Partner) of $66,667 at June 30, 2002, and recognized a net loss in the first quarter of 2002 which was partially offset by a net profit in the second quarter of 2002 on an accrual basis for its net profits interest in oil and gas properties. Cash distributions of the net profits interest are based on actual cash received from the underlying oil and gas properties, net of expenses incurred during that quarterly period. Accordingly, if the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter no net cash is due to the Partnership’s net profits interest until the deficit is recovered from future net profits. Future cash distributions to the Partnership are dependent on a positive quarterly net profits calculation on the underlying properties, which differs from the calculation on an accrual basis.

The Partnership’s wells have been depleting over its life and production has experienced declines from year to year, while costs have not always decreased proportionately. This economic decline coupled with the

F-223

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

fluctuation of prices has caused the Partnership to experience periodic net losses. Because the Partnership is a net profit interest, this situation can cause the Partnership to generate a payable to the Managing General Partner. If the Partnership should continue to experience this economic decline thereby creating net losses and increasing the payable, the Managing General Partner may have to consider dissolution and termination steps according to the Partnership Agreement.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values.

F-224

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $183,300, $175,300 and $176,300 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $16,200, $15,000 and $4,800 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $36,000 during 2001, 2000 and 1999, for reimbursement of indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $36,000 and $111,000 are from oil and gas production, net of lease operating costs and production taxes, as of December 2001 and 2000, respectively.

F-225

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership approximating none for the years ended December 31, 2001, 2000 and 1999.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 77% of the Partnership’s total oil and gas production during 2001: Teppco Crude Oil LLC for 65% and Plains Marketing LP for 12%. Two purchasers accounted for 84% of the Partnership’s total oil and gas production during 2000: Teppco Crude Oil LLC for 72% and Plains Marketing LP for 12%. Two purchasers accounted for 79% of the Partnership’s total oil and gas production during 1999: Teppco Crude Oil LLC for 68% and Scurlock Permian LLC for 11%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s sales of oil and gas production.

7.    Estimated Oil and Gas Reserves—(unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	32,000		481,000
Production	(35,000	)	(50,000	)
Revision of estimates in place	167,000		169,000
December 31, 1999	164,000		600,000
Production	(30,000	)	(30,000	)
Revision of estimates in place	(19,000	)	(22,000	)
December 31, 2000	115,000		548,000
Revision of estimates in place	(64,000	)	(111,000	)
Production	(29,000	)	(44,000	)
December 31, 2001	22,000		393,000
Proved developed reserves—
December 31, 1999	164,000		563,000
December 31, 2000	115,000		548,000
December 31, 2001	22,000		393,000

All of the Partnership’s reserves are located within the continental United States.

*  Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines

F-226

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.66 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $1.65 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing, proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

Because the Partner does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows, net of production and development costs	$	528,000	4,765,000	2,057,000
10% annual discount for estimated timing of cash flows		209,000	2,324,000	823,000
Standardized measure of discounted future net cash flows	$	319,000	2,441,000	1,234,000

F-227

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(221,000	)	(387,000	)	(180,000	)
Changes in prices and production costs		(2,125,000	)	1,833,000		(46,000	)
Changes of production rates (timing) and others		281,000		(95,000	)	(22,000	)
Revisions of previous quantities estimates		(301,000	)	(267,000	)	912,000
Accretion of discount		244,000		123,000		52,000
Discounted future net cash flows—
Beginning of year		2,441,000		1,234,000		518,000
End of year	$	319,000		2,441,000		1,234,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third		Fourth
2001:
Total revenues	$	123,389	48,540	40,406		11,185
Total expenses		24,053	31,935	59,225		31,442
Net income (loss)		99,336	16,605	(18,819	)	(20,257	)
Net income (loss) per limited partners unit		14.71	2.13	(3.65	)	(3.40	)
2000:
Total revenues	$	73,477	88,926	113,653		114,085
Total expenses		21,347	14,246	20,265		15,337
Net income		52,130	74,680	93,388		98,748
Net income per limited partners unit		7.66	11.17	13.88		14.75

F-228

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Developmental Drilling Fund 1990, LP.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 1990, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 1990, LP. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 24, 2002

F-229

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002			December 31,
				2001		2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	8,537		8,952		13,826
Receivable from Managing General Partner		9,897		6,600		4,592
Total current assets		18,434		15,552		18,418
Oil and gas properties—using the full-cost method of accounting		1,546,322		1,546,322		1,540,692
Less accumulated depreciation, depletion and amortization		1,468,425		1,466,425		1,458,425
Net oil and gas properties		77,897		79,897		82,267
	$	96,331		95,449		100,685
LIABILITIES AND PARTNERS’ EQUITY
Current liability—Distribution payable	$	—		39		—
Partners’ equity:
Managing General Partner		183,922		183,484		183,075
Investor partners		(87,591	)	(88,074	)	(82,390	)
Total partners equity		96,331		95,410		100,685
	$	96,331		95,449		100,685

The accompanying notes are an integral part of these financial statements.

F-230

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas revenue	$	47,351	68,950	118,576	115,706	101,928
Interest		8	12	60	244	88
		47,359	68,962	118,636	115,950	102,016
Expenses
Production		18,182	38,032	63,835	37,906	44,997
General and administrative		8,256	8,043	16,078	16,532	17,367
Depreciation, depletion and amortization		2,000	4,000	8,000	3,000	6,000
		28,438	50,075	87,913	57,438	68,364
Net income	$	18,921	18,887	30,723	58,512	33,652
Net income allocated to:
Managing General Partner	$	3,138	3,433	5,809	9,227	5,948
Investor partners	$	15,783	15,454	24,914	49,285	27,704
Per investor partner unit	$	90.97	89.07	143.60	284.07	159.68

The accompanying notes are an integral part of these financial statements.

F-231

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	Managing General Partner			Investor Partners		Total
Balance—January 1, 1999	$	180,350		(88,829	)	91,521
Net income		5,948		27,704		33,652
Distributions		(3,225	)	(18,275	)	(21,500	)
Balance—December 31, 1999		183,073		(79,400	)	103,673
Net income		9,227		49,285		58,512
Distributions		(9,225	)	(52,275	)	(61,500	)
Balance—December 31, 2000		183,075		(82,390	)	100,685
Net income		5,809		24,914		30,723
Distributions		(5,400	)	(30,598	)	(35,998	)
Balance—December 31, 2001		183,484		(88,074	)	95,410
Net income		3,138		15,783		18,921
Distributions		(2,700	)	(15,300	)	(18,000	)
Balance—June 30, 2002 (unaudited)	$	183,922		(87,591	)	96,331

The accompanying notes are an integral part of these financial statements.

F-232

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	43,220		70,790		125,472		118,350		89,947
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(25,604	)	(54,775	)	(88,817	)	(48,747	)	(67,416	)
Interest received		8		12		60		244		88
Net cash provided by operating activities		17,624		16,027		36,715		69,847		22,619
Cash flows used in investing activities:
Additions to oil and gas properties		—		(5,630	)	(5,630	)	—		—
Cash flows used in financing activities:
Distribution to partners		(18,039	)	(14,927	)	(35,959	)	(60,882	)	(21,515	)
Net (decrease) increase in cash and cash equivalents		(415	)	(4,530	)	(4,874	)	8,965		1,104
Beginning of year		8,952		13,826		13,826		4,861		3,757
End of year	$	8,537		9,296		8,952		13,826		4,861
Reconciliation of net income to net cash provided by operating activities:
Net income	$	18,921		18,887		30,723		58,512		33,652
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		2,000		4,000		8,000		3,000		6,000
(Increase) decrease in receivables		(4,131	)	1,840		6,896		2,643		(11,981	)
Increase (decrease) in payables		834		(8,700	)	(8,904	)	5,692		(5,052	)
Net cash provided by operating activities	$	17,624		16,027		36,715		69,847		22,619

The accompanying notes are an integral part of these financial statements.

F-233

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Developmental Drilling Fund 1990, L.P.(the “Partnership”) was organized under the laws of the state of Delaware on July 18, 1990, for the purpose of drilling oil and gas wells and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Investor Partners		Managing General Partner
Development costs	100	%	—
Interest income on capital contributions	100	%	—
Oil and gas sales	85	%	15	%
All other revenues	85	%	15	%
Organization and offering costs(1)	100	%	—
Lease acquisition costs	100	%	—
Depreciation, depletion and amortization of oil and gas properties	100	%	—
Production and administrative costs(2)	85	%	15	%
All other costs	85	%	15	%

(1) All organization costs in excess of 4% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 4% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceeds 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution. For the purpose of allocating Administrative Costs, the Managing General Partner will allocate each employee’s time among three divisions: (1) operating partnerships; (2) corporate activities; and (3) currently offered or proposed partnerships. The Managing General Partner determines a percentage of total Administrative Costs per division based on the total allocated time per division and personnel costs (salaries) attributable to such time. Within the operating partnership division, Administrative Costs are further allocated on the basis of the total capital of each partnership invested in its operations.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost using the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

Depreciation, depletion and amortization of oil and gas properties is computed using the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves, by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is

F-234

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could change significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles required management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners. Such items of deduction or loss passed through, along with each partner’s ability to treat cash distributions as non-taxable returns of capital, may be subject to certain limitations at the partners’ level.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its oil and gas properties at December 31, 2001, 2000 and 1999 is $59,376, $66,762 and $69,247, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

F-235

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Number of Investor Partner Units

As of December 31, 2001, 2000 and 1999 there were 173.5 investor partner units outstanding held by 95, 94 and 92 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Two customers purchased 67% and 33% of the Partnership’s oil and gas production during 2001. Two customers purchased 70% and 30% of the Partnership’s oil and gas production during 2000. Three customers purchased 60%, 26% and 11% of the Partnership’s oil and gas production during 1999.

Net Income per limited partnership unit

The net income per limited partnership unit is calculated by using the weighted average number of limited partnership units outstanding during the year.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less

F-236

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

4.    Related Party Transactions

All of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $7,900, $7,600 and $6,500 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. There were no oilfield services for the year ending December 31, 2001. Such services aggregated $400 and $40 for the years ended December 31, 2000 and 1999.

A director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided for the years ended December 31, 2001, 2000 and 1999.

Southwest Royalties, Inc. the Managing General Partner, was paid $12,000 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $6,600 and $4,592 are for oil and gas sales, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

F-237

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

5.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves
January 1, 1999	32,000		97,000
Revisions of previous estimates	22,000		62,000
Production	(4,000	)	(17,000	)
December 31, 1999	50,000		142,000
Revisions of previous estimates	15,000		68,000
Production	(3,000	)	(9,000	)
December 31, 2000	62,000		201,000
Revisions of previous estimates	(14,000	)	(89,000	)
Production	(3,000	)	(9,000	)
December 31, 2001	45,000		103,000
Proved developed reserves
December 31, 1999	50,000		142,000
December 31, 2000	62,000		201,000
December 31, 2001	45,000		103,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.69 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.22 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Partnership has reserves, which are classified as proved developed producing. All of the proved reserves are included in the engineering reports, which evaluate the Partnership’s present reserves.

F-238

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001			2000		1999
Future cash inflows	$	1,031,000		3,615,000		1,517,000
Production and development costs		(741,000	)	(1,601,000	)	(915,000	)
Future net cash flows		290,000		2,014,000		602,000
10% annual discount for estimated timing of cash flows		(102,000	)	(1,110,000	)	(262,000	)
Standardized measure of discounted future net cash flows	$	188,000		904,000		340,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(55,000	)	(78,000	)	(57,000	)
Changes in prices and production costs		(985,000	)	422,000		151,000
Changes of production rates (timing) and other		321,000		(63,000	)	(3,000	)
Revisions of previous quantities estimates		(87,000	)	249,000		149,000
Accretion of discount		90,000		34,000		9,000
Discounted future net cash flows—
Beginning of year		904,000		340,000		91,000
End of year	$	188,000		904,000		340,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-239

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Developmental Drilling

Fund 91-A, L.P.

(a Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 91-A, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 91-A, L.P. as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-240

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	8,714	12,402	14,338
Receivable from Managing General Partner		10,506	2,047	12,165
Total current assets		19,220	14,449	26,503
Oil and gas properties—using the full-cost method of accounting		1,098,776	1,098,776	1,098,592
Less accumulated depreciation, depletion and amortization		986,000	980,000	960,000
Net oil and gas properties		112,776	118,776	138,592
	$	131,996	133,225	165,095
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distributions payable	$	—	39	—
Partners’ equity:
Managing General Partner		23,042	22,513	23,823
Investor partners		108,954	110,673	141,272
Total partners’ equity		131,996	133,186	165,095
	$	131,996	133,225	165,095

The accompanying notes are an integral part of these financial statements.

F-241

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas sales	$	50,218	79,022	139,132	162,628	251,484
Interest income from operations		3	112	154	256	542
		50,221	79,134	139,286	162,884	252,026
Expenses
Production		27,571	38,787	73,616	78,873	79,606
General and administrative		7,840	7,659	15,345	14,769	16,430
Depreciation, depletion and amortization		6,000	9,000	20,000	11,000	36,000
		41,411	55,446	108,961	104,642	132,036
Net income	$	8,810	23,688	30,325	58,242	119,990
Net income allocated to:
Managing General Partner	$	1,629	3,596	5,536	7,617	17,159
Investor partners	$	7,181	20,092	24,789	50,625	102,831
Per investor partner unit	$	6.27	17.56	21.66	44.23	89.85

The accompanying notes are an integral part of these financial statements.

F-242

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

For the years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	Managing General Partner			Investor Partners		Total
Balance at January 1, 1999	$	21,711		171,187		192,898
Net income		17,159		102,831		119,990
Distributions		(9,350	)	(75,650	)	(85,000	)
Balance at December 31, 1999		29,520		198,368		227,888
Net income		7,617		50,625		58,242
Distributions		(13,314	)	(107,721	)	(121,035	)
Balance at December 31, 2000		23,823		141,272		165,095
Net income		5,536		24,789		30,325
Distributions		(6,846	)	(55,388	)	(62,234	)
Balance at December 31, 2001		22,513		110,673		133,186
Net income		1,629		7,181		8,810
Distributions		(1,100	)	(8,900	)	(10,000	)
Balance at June 30, 2002 (unaudited)	$	23,042		108,954		131,996

The accompanying notes are an integral part of these financial statements.

F-243

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	44,242		89,420		152,656		166,419		235,741
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(37,894	)	(52,363	)	(92,367	)	(87,964	)	(101,686	)
Interest received		3		112		154		256		542
Net cash provided by operating activities		6,351		37,169		60,443		78,711		134,597
Cash flows used in investing activities:
Additions to oil and gas properties		—		—		(184	)	(151	)	(873	)
Cash flows used in financing activities:
Distributions to partners		(10,039	)	(42,452	)	(62,195	)	(120,418	)	(88,247	)
Net (decrease) increase in cash and cash equivalents		(3,688	)	(5,283	)	(1,936	)	(41,858	)	45,477
Beginning of period		12,402		14,338		14,338		56,196		10,719
End of period	$	8,714		9,055		12,402		14,338		56,196
Reconciliation of net income to net cash provided by operating activities:
Net income	$	8,810		23,688		30,325		58,242		119,990
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		6,000		9,000		20,000		11,000		36,000
(Increase) decrease in receivables		(5,976	)	10,398		13,524		3,791		(15,743	)
(Decrease) increase in payables		(2,483	)	(5,917	)	(3,406	)	5,678		(5,650	)
Net cash provided by operating activities	$	6,351		37,169		60,443		78,711		134,597

The accompanying notes are an integral part of these financial statements.

F-244

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Developmental Drilling Fund 91-A, L.P. was organized under the laws of the state of Delaware on January 7, 1991 for the purpose of drilling developmental and exploratory wells and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Managing General Partner	Investor Partners
Interest income on capital contributions	—	100%
Oil and gas sales*	11%	89%
All other revenues*	11%	89%
Organization and offering costs(1)	—	100%
Syndication costs	—	100%
Amortization of organization costs	—	100%
Lease acquisition costs	1%	99%
Gain/loss on property disposition*	11%	89%
Operating and administrative costs*(2)	11%	89%
Depreciation, depletion and amortization of oil and gas properties	—	100%
Intangible drilling and development costs	—	100%
All other costs*	11%	89%

* After the Investor Partners have received distributions totaling 150% of their capital contributions, the allocation will change to 15% Managing General Partner and 85% Investor Partners.

(1) All organization costs in excess of 4% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 4% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent

F-245

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its net oil and gas properties at December 31, 2001 and 2000 is

F-246

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

$113,822 and $130,818, respectively, less than that shown on the accompanying balance sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Investor Partner Units

As of December 31, 2001, 2000 and 1999, there were 1,144.5 investor partner units outstanding held by 102, 103 and 103 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived

F-247

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect

F-248

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $11,800, $11,400 and $13,000 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $1,100, $4,300 and $7,300 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid $10,800 in 2001 and 2000 and $11,000 in 1999 for indirect general and administrative overhead expenses.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $2,000 and $12,200 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services. The Partnership had no legal services for the years ended December 31, 2001, 2000 and 1999, respectively.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 94% of the Partnership’s total oil and gas production during 2001: Plains Marketing LP for 76% and Duke Energy Field Services for 18%. Two purchasers accounted for 91% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 78% and Duke Energy Transport for 13%. Two purchasers accounted for 85% of the Partnership’s total oil and gas production during 1999: Navajo Refining Company, Inc. for 52% and Scurlock Permian LLC for 33%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s total oil and gas production.

F-249

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

7.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	46,000		68,000
Revisions of estimates in place	11,000		13,000
Production	(13,000	)	(20,000	)
December 31, 1999	44,000		61,000
Revisions of estimates in place	10,000		15,000
Production	(5,000	)	(7,000	)
December 31, 2000	49,000		69,000
Revisions of estimates in place	(20,000	)	(32,000	)
Production	(4,000	)	(6,000	)
December 31, 2001	25,000		31,000
Proved developed reserves—
December 31, 1999	44,000		61,000
December 31, 2000	49,000		69,000
December 31, 2001	25,000		31,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.98 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.28 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data

F-250

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing and proved developed non-producing. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	553,000	1,966,000	1,179,000
Production and development costs		395,000	1,129,000	686,000
Future net cash flows		158,000	837,000	493,000
10% annual discount for estimated timing of cash flows		37,000	275,000	142,000
Standardized measure of discounted future net cash flows	$	121,000	562,000	351,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(66,000	)	(84,000	)	(172,000	)
Changes in prices and production costs		(346,000	)	157,000		167,000
Changes of production rates (timing) and others		16,000		(28,000	)	(20,000	)
Revisions of previous quantities estimates		(101,000	)	116,000		89,000
Changes in estimated future development costs		—		15,000		(16,000	)
Accretion of discount		56,000		35,000		28,000
Discounted future net cash flows—
Beginning of year		562,000		351,000		275,000
End of year	$	121,000		562,000		351,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-251

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second		Third		Fourth
2001:
Total revenues	$	55,540	23,594		32,635		27,517
Total expenses		23,108	32,338		33,137		20,378
Net income (loss)		32,432	(8,744	)	(502	)	7,139
Net income (loss) per limited partners unit		24.74	(7.18	)	(1.06	)	5.16
2000:
Total revenues	$	36,095	43,158		50,190		33,441
Total expenses		27,399	23,166		26,858		27,219
Net income		8,696	19,992		23,332		6,222
Net income per limited partners unit		6.38	15.35		17.76		4.74

F-252

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Developmental Drilling

Fund 92-A

(A Delaware Limited Partnership):

We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 92-A (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 92-A as of December 31, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 10, 2002

F-253

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	17,842	16,508	26,865
Receivable from Managing General Partner		28,234	28,977	41,053
Total current assets		46,076	45,485	67,918
Oil and gas properties—using the full-cost method of accounting		1,313,124	1,313,124	1,314,517
Less accumulated depreciation, depletion and amortization		1,134,240	1,127,240	1,103,240
Net oil and gas properties		178,884	185,884	211,277
	$	224,960	231,369	279,195
LIABILITIES AND PARTNERS’ EQUITY
Current liability—distribution payable	$	95	79	—
Partners’ equity:
Managing General Partner		27,987	27,924	30,554
Investor partners		196,878	203,366	248,641
Total partners’ equity		224,865	231,290	279,195
	$	224,960	231,369	279,195

The accompanying notes are an integral part of these financial statements.

F-254

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas sales	$	124,415	200,270	332,643	371,824	249,636
Interest income from operations		37	353	549	729	329
		124,452	200,623	333,192	372,553	249,965
Expenses
Production		55,450	72,735	131,781	123,971	102,784
General and administrative		8,427	8,298	16,518	15,942	17,414
Depreciation, depletion and amortization		7,000	12,000	24,000	15,000	17,000
		70,877	93,033	172,299	154,913	137,198
Net income	$	53,575	107,590	160,893	217,640	112,767
Net income allocated to:
Managing General Partner	$	6,663	13,155	20,338	25,590	14,274
Investor partners	$	46,912	94,435	140,555	192,050	98,493
Per investor partner unit	$	33.34	67.12	99.90	136.50	70.00

The accompanying notes are an integral part of these financial statements.

F-255

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	Managing General Partner			Investor Partners		Total
Balance at January 1, 1999	$	24,750		233,678		258,428
Net income		14,274		98,493		112,767
Distributions		(9,350	)	(75,650	)	(85,000	)
Balance at December 31, 1999		29,674		256,521		286,195
Net income		25,590		192,050		217,640
Distributions		(24,710	)	(199,930	)	(224,640	)
Balance at December 31, 2000		30,554		248,641		279,195
Net income		20,338		140,555		160,893
Distributions		(22,968	)	(185,830	)	(208,798	)
Balance at December 31, 2001		27,924		203,366		231,290
Net income		6,663		46,912		53,575
Distributions		(6,600	)	(53,400	)	(60,000	)
Balance at June 30, 2002 (unaudited)	$	27,987		196,878		224,865

The accompanying notes are an integral part of these financial statements.

F-256

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	122,677		209,455		353,274		361,584		223,480
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(61,396	)	(86,729	)	(156,854	)	(133,476	)	(123,478	)
Interest received		37		353		549		729		329
Net cash provided by operating activities		61,318		123,079		196,969		228,837		100,331
Cash flows from investing activities:
Addition to oil and gas properties		—		—		—		(75	)	(20	)
Sale of oil and gas properties		—		—		1,393		—		—
Net cash provided by (used in) investing activities		—		—		1,393		(75	)	(20	)
Cash flows used in financing activities:
Distributions to partners		(59,984	)	(130,000	)	(208,719	)	(224,640	)	(85,080	)
Net increase (decrease) in cash and cash equivalents		1,334		(6,921	)	(10,357	)	4,122		15,231
Beginning of period		16,508		26,865		26,865		22,743		7,512
End of period	$	17,842		19,944		16,508		26,865		22,743
Reconciliation of net income to net cash provided by operating activities:
Net income	$	53,575		107,590		160,893		217,640		112,767
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		7,000		12,000		24,000		15,000		17,000
(Increase) decrease in receivables		(1,738	)	9,185		20,631		(10,240	)	(26,156	)
Increase (decrease) in payables		2,481		(5,696	)	(8,555	)	6,437		(3,280	)
Net cash provided by operating activities	$	61,318		123,079		196,969		228,837		100,331

The accompanying notes are an integral part of these financial statements.

F-257

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Developmental Drilling Fund 92-A, L.P. was organized under the laws of the state of Delaware on May 5, 1992, for the purpose of engaging primarily in the business of drilling developmental and exploratory wells, to produce and market crude oil and natural gas produced from such properties, and acquire leases which contain drilling prospects. The activities of the Partnership should continue for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership anticipates selling its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Managing General Partner	Investor Partners
Interest income on capital contributions	—	100%
Oil and gas sales*	11%	89%
All other revenues*	11%	89%
Organization and offering costs(1)	—	100%
Syndication costs	—	100%
Amortization of organization costs	—	100%
Lease acquisition costs	1%	99%
Gain/loss on property disposition*	11%	89%
Operating and administrative costs*(2)	11%	89%
Depreciation, depletion and amortization of oil and gas properties	—	100%
Intangible drilling and development costs	—	100%
All other costs*	11%	89%

* After the Investor Partners have received distributions totaling 150% of their capital contributions, the allocation will change to 15% Managing General Partner and 85% Investor Partners.

(1) All organization costs in excess of 4% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 4% of initial capital contributions for such organization costs.

(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

The Partnership’s policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.

F-258

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Under the future gross revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Syndication Costs

Syndication costs are accounted for as a reduction of partnership equity.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for over or under deliveries of gas. Under this method, the Partnership records revenues based on the payments it has received for sales from purchasers. As of December 31, 2001, 2000 and 1999, the Partnership was not over or under produced.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

F-259

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its net oil and gas assets at December 31, 2001 and 2000 was $173,234 and $194,608, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Investor Partner Units

As of December 31, 2001, 2000 and 1999, there were 1,407 investor units outstanding held by 105, 103 and 103 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Fair Value of Financial Instruments

The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.

Net Income (loss) per limited partnership unit

The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

F-260

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Liquidity—Managing General Partner

The Managing General Partner has a highly leveraged capital structure with $50.0 million and $123.7 million of principal due in August of 2003 and October of 2004, respectively. The Managing General Partner will incur approximately $17.6 million in interest payments in 2002 on its debt obligations. Due to the depressed commodity prices experienced during the last quarter of 2001, the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.

There can be no assurance that the Managing General Partner’s debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner’s ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values. Upon the occurrence of any event of dissolution by the Managing General Partner, the holders of a majority of limited partnership interests may, by written agreement, elect to continue the business of the Partnership in the Partnership’s name, with Partnership property, in a reconstituted partnership under the terms of the partnership agreement and to designate a successor Managing General Partner.

4.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by Nations Bank, N.A. of Midland, Texas, plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

F-261

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.

However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

5.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $23,600, $22,700 and $22,400 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $500, $3,700 and $2,900 for the years ended December 31, 2001, 2000 and 1999, respectively.

Southwest Royalties, Inc., the Managing General Partner, was paid an administrative fee of $12,000 during 2001, 2000 and 1999 for reimbursement of indirect general and administrative overhead expenses.

In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services for December 31, 2001, 2000 and 1999.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $29,000 and $41,100 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

6.    Major Customers

No material portion of the Partnership’s business is dependent on a single purchaser, or a very few purchaser, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 93% of the Partnership’s total oil and gas production during 2001: Plains Marketing LP for 58%, Duke Energy Field Services for 21% and Navajo Refining Company, Inc. for 14%. Three purchasers accounted for 94% of the Partnership’s total oil and gas production during 2000: Plains Marketing LP for 63%, Navajo Refining Company, Inc. for 16% and Duke Energy Transport and Trad. for 15%. Three purchasers accounted for 95% of the Partnership’s total oil and gas production during 1999: Scurlock Permian LLC for 59%, Duke Energy Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%. All purchasers of the Partnership’s oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing the Partnership’s production, the Managing General Partner believes that a substitute purchaser or purchasers could

F-262

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership’s total oil and gas production.

7.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	76,000		168,000
Production	(11,000	)	(25,000	)
Revisions of estimates in place	44,000		166,000
December 31, 1999	109,000		309,000
Production	(10,000	)	(20,000	)
Revisions of estimates in place	11,000		(47,000	)
December 31, 2000	110,000		242,000
Revisions of estimates in place	(22,000	)	26,000
Production	(9,000	)	(23,000	)
December 31, 2001	79,000		245,000
Proved developed reserves—
December 31, 1999	109,000		309,000
December 31, 2000	110,000		242,000
December 31, 2001	79,000		245,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.90 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.34 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

F-263

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves which are classified as proved developed producing. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	2,059,000	5,290,000	3,328,000
Production and development costs		1,334,000	2,403,000	1,838,000
Future net cash flows		725,000	2,887,000	1,490,000
10% annual discount for estimated timing of cash flows		260,000	1,309,000	603,000
Standardized measure of discounted future net cash flows	$	465,000	1,578,000	887,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(201,000	)	(248,000	)	(147,000	)
Changes in prices and production costs		(1,178,000	)	866,000		374,000
Changes of production rates (timing) and others		177,000		(49,000	)	(3,000	)
Revisions of previous quantities estimates		(69,000	)	33,000		396,000
Accretion of discount		158,000		89,000		24,000
Discounted future net cash flows—
Beginning of year		1,578,000		887,000		243,000
End of year	$	465,000		1,578,000		887,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-264

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

8.    Selected Quarterly Financial Results—(unaudited)

	Quarter
	First		Second	Third	Fourth
2001:
Total revenues	$	124,995	75,628	66,151	66,418
Total expenses		43,013	50,019	39,776	39,491
Net income		81,982	25,609	26,375	26,927
Net income per limited partners unit		51.31	15.81	16.14	16.64
2000:
Total revenues	$	90,020	92,567	108,127	81,839
Total expenses		37,602	37,618	45,451	34,242
Net income		52,418	54,949	62,676	47,597
Net income per limited partners unit		32.77	34.52	39.25	29.95

F-265

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Partners, L.P. and Subsidiary

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Partners, L.P. and subsidiary (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Partners, L.P. and subsidiary as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

As discussed in note 3, retained earnings as of December 31, 1999 and the deferred tax liability and income tax expense as of and for the year ended December 31, 2000, have been restated in the accompanying financial statements.

KPMG LLP

Midland, Texas

March 24, 2002

F-266

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

CONSOLIDATED BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)			Restated
ASSETS
Current assets:
Cash and cash equivalents	$	69,879	13,498	377,932
Receivable from Managing General Partner		—	—	260,932
Prepayment—Federal income tax		—	157,800	16,000
Total current assets		69,879	171,298	654,864
Oil and gas properties—using the full-cost method of accounting		11,818,774	11,317,777	10,075,832
Less accumulated depreciation, depletion and amortization		8,071,419	7,911,419	7,052,419
Net oil and gas properties		3,747,355	3,406,358	3,023,413
	$	3,817,234	3,577,656	3,678,277
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	156,590	—	232,762
Distribution payable		—	—	5,689
Payable to Managing General Partner		8,449	126,313	—
Total current liabilities		165,039	126,313	238,451
Long-term debt		287,300	—	—
Deferred income taxes of subsidiary		171,828	171,828	138,013
Partners’ equity:
General Partner		233,147	246,114	249,459
Limited partners		2,959,920	3,033,401	3,052,354
Total partners’ equity		3,193,067	3,279,515	3,301,813
	$	3,817,234	3,577,656	3,678,277

The accompanying notes are an integral part of these consolidated financial statements.

F-267

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)							Restated
Revenues
Oil and gas revenue	$	791,290		1,792,494		2,711,350		3,732,728		2,133,633
Interest		181		4,174		6,209		7,327		4,575
		791,471		1,796,668		2,717,559		3,740,055		2,138,208
Expenses
Production		677,079		859,602		1,643,759		1,492,347		1,174,497
General and administrative		36,835		40,024		70,092		64,318		65,787
Depreciation, depletion and amortization		160,000		381,000		859,000		255,000		418,374
Interest expense		4,005		5,950		5,950		50,597		75,342
		877,919		1,286,576		2,578,801		1,862,262		1,734,000
Net income (loss) before provision for income taxes		(86,448	)	510,092		138,758		1,877,793		404,208
Income tax (expense) benefit of subsidiary		—		(170,000	)	(33,815	)	(333,259	)	195,246
Net income (loss)	$	(86,448	)	340,092		104,943		1,544,534		599,454
Net income (loss) allocated to:
General Partner	$	(12,967	)	51,014		15,741		231,680		89,918
Limited partners	$	(73,481	)	289,078		89,202		1,312,854		509,536
Per limited partner unit	$	(1,689	)	6,645		2,051		30,181		11,713

The accompanying notes are an integral part of these consolidated financial statements.

F-268

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	General Partner			Limited Partners		Total
Balance—January 1,1999	$	(33,786	)	1,447,300		1,413,514
Net income		89,918		509,536		599,454
Distribution		—		—		—
Balance—December 31, 1999 – Restated		56,132		1,956,836		2,012,968
Net income—Restated		231,680		1,312,854		1,544,534
Distribution		(38,353	)	(217,336	)	(255,689	)
Balance—December 31, 2000—Restated		249,459		3,052,354		3,301,813
Net income		15,741		89,202		104,943
Distribution		(19,086	)	(108,155	)	(127,241	)
Balance—December 31, 2001		246,114		3,033,401		3,279,515
Net loss		(12,967	)	(73,481	)	(86,448	)
Distribution		—		—		—
Balance—June 30, 2002 (unaudited)	$	233,147		2,959,920		3,193,067

The accompanying notes are an integral part of these consolidated financial statements.

F-269

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)							Restated
Cash flows from operating activities:
Cash received from oil and gas sales	$	756,659		2,050,424		3,144,181		3,458,320		1,982,091
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(801,152	)	(11,900	)	(1,765,387	)	(1,528,906	)	(1,234,898	)
Interest received		181		4,174		6,209		7,327		4,575
Income taxes paid		—		(141,800	)	(141,800	)	—		—
Income tax refund		157,800		—		—		—		—
Net cash provided by operating activities		113,488		1,900,898		1,243,203		1,936,741		751,768
Cash flows from investing activities:
Additions to oil and gas properties		(500,997	)	(1,078,714	)	(1,289,945	)	(1,231,030	)	(262,650	)
Sale of oil and gas properties		—		—		48,000		—		112,500
Net cash used in investing activities		(500,997	)	(1,078,714	)	(1,241,945	)	(1,231,030	)	(150,150	)
Cash flows from financing activities:
Distributions		—		(130,689	)	(132,930	)	(250,000	)	—
Proceeds from debt		470,000		—		—		—		—
Debt payment		(26,110	)	(232,762	)	(232,762	)	(420,571	)	(345,000	)
Net cash (used in) provided by financing activities		443,890		(363,451	)	(365,692	)	(670,571	)	(345,000	)
Net increase (decrease) in cash and cash equivalents		56,381		458,733		(364,434	)	35,140		256,618
Beginning of period		13,498		377,932		377,932		342,792		86,174
End of period	$	69,879		836,665		13,498		377,932		342,792
Reconciliation of net income (loss) to net cash provided by operating activities:
Net income (loss)	$	(86,448	)	340,092		104,943		1,544,534		599,454
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		160,000		381,000		859,000		255,000		418,374
Deferred income taxes		—		170,000		33,815		333,259		(195,246	)
Federal income taxes		157,800		(141,800	)	(141,800	)	—		—
(Increase) decrease in receivables		(34,631	)	257,930		432,831		(274,408	)	(151,542	)
(Decrease) increase in payables		(83,233	)	893,676		(45,586	)	78,356		80,728
Net cash provided by operating activities	$	113,488		1,900,898		1,243,203		1,936,741		751,768

The accompanying notes are an integral part of these consolidated financial statements.

F-270

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Organization

Southwest Partners, L.P. (the “Partnership”) was organized under the laws of the State of Delaware on March 31, 1993, for the purpose of acquiring or investing in oil and gas companies, purchasing direct interests in oil and gas properties, or drilling developmental and exploratory wells. The Partnership intends to wind up its operations and distribute its assets or the proceeds there from on or before December 31, 2003, unless sooner terminated or extended in accordance with the terms of the Partnership Agreement. The Partnership anticipates selling its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the General Partner. Revenues, costs and expenses are allocated as follows:

	General Partner	Limited Partners
Interest income on capital contributions	—	100%
Oil and gas sales	15%	85%
All other revenues	15%	85%
Organization and offering costs	—	100%
Syndication costs	—	100%
Amortization of organization costs	—	100%
Lease acquisition costs	15%	85%
Gain/loss on property disposition	15%	85%
Operating and administrative costs	15%	85%
Depreciation, depletion and amortization of oil and gas properties	15%	85%
Intangible drilling and development costs	15%	85%
All other costs	15%	85%

After payout, allocations will be seventy-five (75%) to the limited partners and twenty-five (25%) to the General Partner. Payout is when the limited partners have received an amount equal to one hundred-ten percent (110%) of their limited partner capital contributions.

Method of Allocation of Administrative Costs

For the purpose of allocating Administrative Costs, the Managing General Partner will allocate each employee’s time among three divisions: (1) operating partnerships; (2) corporate activities; and (3) currently offered or proposed partnerships. The Managing General Partner determines a percentage of total Administrative Costs per division based on the total allocated time per division and personnel costs (salaries) attributable to such time. Within the operating partnership division, Administrative Costs are further allocated on the basis of the total capital of each partnership invested in its operations.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost using the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

F-271

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Depreciation, depletion and amortization of oil and gas properties is computed using the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves, by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could change significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Basis of Consolidation

The consolidated financial statements include the accounts of the Partnership and its wholly-owned subsidiary, Tex-Hal Partners, Inc. All significant intercompany balances and transactions have been eliminated.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing agreements. Under this method, the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and values.

F-272

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income Taxes

Income taxes are computed on the Partnerships wholly-owned subsidiary based on the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. Deferred tax assets and liabilities are recognized for the estimated future tax effects attributed to temporary differences between the book and tax bases of assets, liabilities and carryforward items. The measurement of current and deferred tax assets and liabilities is based on enacted law.

No provision for income taxes is reflected in these consolidated financial statements for the Partnership, except for its wholly-owned subsidiary, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

Cash and Cash Equivalents

For purposes of the consolidated statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, 2001, 2000 and 1999, there were 43.5 limited partner units outstanding, held by 84 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Two customers purchased 63% and 33% of the Partnership’s oil and gas production during 2001. Two customers purchased 54% and 43% of the Partnership’s oil and gas production during 2000 and 1999.

Net Income per limited partnership unit

The net income per limited partnership unit is calculated by using the weighted average number of limited partnership units outstanding during the year.

3.    Restatement

Retained earnings as of December 31, 1999 has been restated to reflect an adjustment related to statutory depletion carryforwards which had not previously been considered in the calculation of deferred income taxes of subsidiary.

F-273

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

This adjustment resulted in a decrease in the previously reported deferred tax liability of the subsidiary of $116,834. The impact of this adjustment increased retained earnings by $116,834 from amounts previously reported.

Retained earnings at December 31, 1999, as previously reported	$	1,896,134
Deferred income tax restatement		116,834
Retained earnings at December 31, 1999, as restated	$	2,012,968

Deferred income tax liability of the subsidiary and income tax expense of the subsidiary as of and for the year ended December 31, 2000 have been restated to reflect an adjustment related to statutory depletion earned in the period, which had not been considered in the calculation of deferred income taxes. The adjustment resulted in an increase in net income of $135,136 related to a decrease in deferred income tax expense of the subsidiary and a corresponding decrease in the deferred income tax liability of the subsidiary.

4.    Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

5.    Notes Payable

September 2, 1998, the Partnership entered into a $1,500,000 line of credit note with a financial institution. On September 2, 1998, the Partnership borrowed on their line of credit in the amount of $983,333 and consolidated a balance of $104,999 from an existing term note payable originally dated November 5, 1995. Payments were as follows: twelve monthly payments of $30,000, plus interest, calculated at an interest rate of 1.000 percentage point over the Prime Rate; eleven monthly payments of $25,000, plus interest; and a final payment of principal and accrued interest due September 1, 2000. The Managing General Partner, on July 5, 2000 refinanced the Partnership debt. The refinancing allowed for a line of credit up to $1.5 million and extended the due date from September 2, 2000 until July 5, 2002. At present, the line of credit has not been drawn. The

F-274

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

payments under the refinancing were $43,333 principal plus interest calculated at the prime rate. Interest expense totaled $5,950 and $50,597 for years ended December 31, 2001 and 2000, respectively.

There are no maturities of long-term debt at December 31, 2001.

6.    Provision for Income Taxes

Reconciliation’s between the amount determined by applying the tax rate to income before income taxes with the income tax provision is as follows:

	2001			Restated 2000		Restated 1999
Computed “expected” tax expense	$	42,018		567,718		105,684
Permanent and Other Differences		(8,203	)	(234,459	)	(300,930	)
Expense for income taxes	$	33,815		333,259		(195,246	)

The following is a summary of the significant components of the wholly-owned subsidiary’s deferred tax assets and liabilities:

	2001			Restated 2000		Restated 1999
Deferred tax assets
Net operating loss	$	107,827		61,630		106,615
Statutory depletion carryover		251,970		251,970		116,834
		359,797		313,600		223,449
Deferred tax liabilities
Oil & gas properties		(485,589	)	(418,157	)	(28,203	)
Accrued expenses		(46,036	)	(33,456	)	—
		(531,625	)	(451,613	)	(28,203	)
Valuation allowance		—		—		—
Net deferred tax liabilities	$	(171,828	)	(138,013	)	195,246

A valuation allowance is provided when it is more likely than not that some portion of the deferred tax assets will not be realized. Based on expectations for the future, management has determined that taxable income will be sufficient to fully utilize available carryforwards prior to their ultimate expirations. The wholly owned subsidiary has a net operating loss carryforward of $317,140 as of December 31, 2001. The net operating loss carryforward will expire in 2021.

7.    Commitments and Contingent Liabilities

The Partnership, as an incentive to brokers who sold in excess of one Unit, agreed to distribute three percent (3%) of the Partnership liquidation proceeds which will be distributed to the General Partner in proportion to the dollar amount of the Units sold by each such broker. This special distribution will only be made on liquidation on or before December 31, 2003, of the Partnership, from the liquidation proceeds distributable to the General Partner and only if the Limited Partners have received one hundred percent (100%) of their Capital Contributions

F-275

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

and a ten percent (10%) cumulative (but not compounded) return. As of December 31, 1997, there were six (6) such brokers who sold in excess of one Unit qualifying for the special distribution.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.

However, the General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of the Partnership’s properties.

8.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $35,200, $33,300 and $42,000 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the General Partner perform various oilfield services for properties in which the Partnership owns an interest. Costs for such services aggregated approximately $900, $400 and $4,000 for the years ended December 31, 2001, 2000 and 1999, respectively.

Amounts due (to) from Southwest Royalties, Inc., totaled $(126,313) and $260,932 as of December 31, 2001 and 2000, and represented oil and gas production, net of lease operating costs and production taxes.

Southwest Royalties, Inc., the General Partner, was paid $54,000 during 2001, 2000 and 1999, as an administrative fee, for indirect general and administrative overhead expenses in accordance with the terms of the Partnership prospectus.

F-276

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

9.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
January 1, 1999	784,000		11,458,000
Sales of Reserves	(68,000	)	(253,000	)
Production	(50,000	)	(664,000	)
Revisions of estimates in place	235,000		2,878,000
December 31, 1999	901,000		13,419,000
Production	(43,000	)	(616,000	)
Revisions of estimates in place	46,000		(1,865,000	)
December 31, 2000	904,000		10,938,000
Production	(42,000	)	(429,000	)
Revisions of estimates in place	(205,000	)	(2,641,000	)
December 31, 2001	657,000		7,868,000
Proved developed reserves—
December 31, 1999	514,000		5,772,000
December 31, 2000	539,000		4,887,000
December 31, 2001	321,000		2,986,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $19.16 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $1.97 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

The Partnership has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

F-277

SOUTHWEST PARTNERS, L.P. AND SUBSIDIARY

(a Delaware Limited Partnership)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out or receives cash.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001			2000		1999
Future cash inflows	$	26,137,000		126,679,000		45,505,000
Production and development costs		13,837,000		35,609,000		23,286,000
Future net cash flows before income taxes		12,300,000		91,070,000		22,219,000
Future income tax expense		2,862,000		30,964,000		7,313,000
Future net cash flows		9,438,000		60,106,000		14,906,000
10% annual discount for estimated timing of cash flows		(5,164,000	)	(28,032,000	)	(7,417,000	)
Standardized measure of discounted future net cash flows	$	4,274,000		32,074,000		7,489,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(1,067,000	)	(2,006,000	)	(959,000	)
Changes in prices and production costs		(35,830,000	)	42,396,000		5,250,000
Changes in estimated future development costs		319,000		(379,000	)	(256,000	)
Changes of production rates (timing) and other		(7,906,000	)	1,347,000		1,455,000
Revisions of previous quantities estimates		(2,892,000	)	(5,040,000	)	3,241,000
Accretion of discount		4,860,000		1,116,000		232,000
Sales of minerals in place		—		—		(115,000	)
Net change in income taxes		14,716,000		(12,849,000	)	(3,674,000	)
Discounted future net cash flows—
Beginning of year		32,074,000		7,489,000		2,315,000
End of year	$	4,274,000		32,074,000		7,489,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

10.    Subsequent Event

Southwest Partners entered into a note agreement with a financial institution subsequent to December 31, 2001 for approximately $470,000. Principal and interest are due and payable beginning May 19, 2002 and subsequent payments to be made on or before the nineteenth day of each month thereafter. The entire outstanding principal and accrued, unpaid interest shall be due and payable in full on March 19, 2005, the date of final maturity. Interest under the note shall accrue at an annual rate equal to the prime rate, plus two percentage points. The note is collateralized by a deed of trust and financing statement covering oil and gas properties owned by Tex-Hal Partners, Inc.

F-278

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Developmental Drilling Fund 1993, L.P.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 1993, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 1993, L.P. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 24, 2002

F-279

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	19,523	44,697	61,636
Receivable from Managing General Partner		57,560	29,675	62,817
Total current assets		77,083	74,372	124,453
Oil and gas properties—using the full-cost method of accounting		1,937,611	1,937,611	1,937,611
Less accumulated depreciation, depletion and amortization		1,385,921	1,362,921	1,292,921
Net oil and gas properties		551,690	574,690	644,690
	$	628,773	649,062	769,143
PARTNERS’ EQUITY
Partners’ equity:
Managing General Partner	$	27,902	27,834	34,043
Investor partners		600,871	621,228	735,100
Total partners’ equity	$	628,773	649,062	769,143

The accompanying notes are an integral part of these financial statements.

F-280

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas revenue	$	185,651	252,671	442,640	563,680	367,811
Interest income from operations		47	549	856	1,115	615
		185,698	253,220	443,496	564,795	368,426
Expenses
Production		74,746	74,657	145,600	171,746	128,957
General and administrative		8,241	8,115	16,028	15,894	17,256
Depreciation, depletion and amortization		23,000	30,000	70,000	41,000	43,348
		105,987	112,772	231,628	228,640	189,561
Net income	$	79,711	140,448	211,868	336,155	178,865
Net income allocated to:
Managing General Partner	$	11,068	18,449	30,305	41,077	24,013
Investor partners	$	68,643	121,999	181,563	295,078	154,852
Per investor partner unit	$	33.03	58.71	87.37	142.00	74.52

The accompanying notes are an integral part of these financial statements.

F-281

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	Managing General Partner			Investor Partners		Total
Balance—January 1, 1999	$	22,779		720,667		743,446
Net income		24,013		154,852		178,865
Distributions		(15,730	)	(127,270	)	(143,000	)
Balance—December 31, 1999		31,062		748,249		779,311
Net income		41,077		295,078		336,155
Distributions		(38,096	)	(308,227	)	(346,323	)
Balance—December 31, 2000		34,043		735,100		769,143
Net income		30,305		181,563		211,868
Distributions		(36,514	)	(295,435	)	(331,949	)
Balance—December 31, 2001		27,834		621,228		649,062
Net income		11,068		68,643		79,711
Distributions		(11,000	)	(89,000	)	(100,000	)
Balance—June 30, 2002 (unaudited)	$	27,902		600,871		628,773

The accompanying notes are an integral part of these financial statements.

282

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	160,731		279,615		492,429		531,737		321,400
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(85,952	)	(106,901	)	(178,275	)	(163,906	)	(141,854	)
Interest received		47		549		856		1,115		615
Net cash provided by operating activities		74,826		173,263		315,010		368,946		180,161
Cash flows used in investing activities:
Additions to oil and gas properties		—		—		—		(2,432	)	(2,588	)
Cash flows used in financing activities:
Distribution to partners		(100,000	)	(195,000	)	(331,949	)	(346,152	)	(143,000	)
Net (decrease) increase in cash and cash equivalents		(25,174	)	(21,737	)	(16,939	)	20,362		34,573
Beginning of period		44,697		61,636		61,636		41,274		6,701
End of period	$	19,523		39,899		44,697		61,636		41,274
Reconciliation of net income to net cash provided by operating activities:
Net income	$	79,711		140,448		211,868		336,155		178,865
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		23,000		30,000		70,000		41,000		43,348
Decrease (increase) in receivables		(24,920	)	26,944		49,789		(31,943	)	(46,411	)
(Decrease) increase in payables		(2,965	)	(24,129	)	(16,647	)	23,734		4,359
Net cash provided by operating activities	$	74,826		173,263		315,010		368,946		180,161

The accompanying notes are an integral part of these financial statements.

F-283

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Developmental Drilling Fund 1993, L.P. (the “Partnership”) was organized under the laws of the state of Delaware on August 27, 1993, for the purpose of engaging primarily in the business of drilling developmental and exploratory wells, to produce and market crude oil and natural gas produced from such properties, and acquire leases which contain drilling prospects. The activities of the Partnership should continue for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership anticipates selling its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Investor Partners	Managing General Partner(1)
Organization and offering expenses(2)	100%	—
Lease acquisition and drilling costs	99%	1%
Operating costs*	89%	11%
Administrative costs(3)*	89%	11%
Direct costs*	89%	11%
All other costs*	89%	11%
Interest income earned on capital contributions	100%	—
Oil and gas revenues and other revenues *	89%	11%
Intangible drilling costs	99%	1%
Depreciation	99%	1%
Depletion allowances	99%	1%

* After the investor partners have received distributions totaling 150% of their capital contributions, the allocation will change to 15% Managing General Partner and 85% investor partners.

(1) The Managing General Partner will make a contribution to the capital of the Partnership at the conclusion of its respective Offering Period in an amount equal to one percent (1%) of the Net Capital Contributions to the Partnership.

(2) Organization and Offering Expenses includes the payment by the Partnership of Organization Costs in an amount equal to four percent (4%) of Capital Contributions for reimbursement of expenses. All Organization Costs in excess of four percent (4%) of Capital Contributions with respect to the Partnership will be allocated to and paid by the Managing General Partner.

(3) Administrative Costs will be paid from the Partnership revenues; however, Administrative Costs in any Partnership year in excess of two percent (2%) of Capital Contributions shall be paid by the Managing General Partner. For the purpose of allocating Administrative Costs, the Managing General Partner will allocate each employee’s time among three divisions: (1) operating partnerships; (2) corporate activities; and (3) currently offered or proposed partnerships. The Managing General Partner determines a percentage of total Administrative Costs per division based on the total allocated time per division and personnel costs (salaries) attributable to such time. Within the operating partnership division, Administrative Costs are further allocated on the basis of the total capital of each partnership invested in its operations.

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost using the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of

F-284

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

Depreciation, depletion and amortization of oil and gas properties is computed using the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves, by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the production, or both could change significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners.

F-285

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes,” the Partnership’s tax basis in its assets at December 31, 2001, 2000 and 1999 is $537,527, $579,871 and $576,506, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Investor Partner Units

As of December 31, 2001, 2000 and 1999 there were 2,078 investor units outstanding held by 102, 102 and 101 partners, respectively.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Three customers purchased 49%, 25% and 24% of the Partnership’s oil and gas production during 2001. Four customers purchased 38%, 25%, 24% and 13% of the Partnership’s oil and gas production during 2000. Three customers purchased 54%, 25% and 12% of the Partnership’s oil and gas production during 1999.

Net Income per limited partnership unit

The net income per limited partnership unit is calculated by using the weighted average number of limited partnership units outstanding during the year.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived

F-286

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

4.    Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest is operated by and purchased from the Managing General Partner. As is usual in the industry and as provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $26,700, $25,700 and $25,300 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $1,400, $6,400 and $1,500, for the years ended December 31, 2001, 2000 and 1999.

A director and officer of the Managing General Partner is a partner in a law firm, with such firm providing no legal services to the Partnership for the year ended December 31, 2001, 2000 and 1999.

Southwest Royalties, Inc., the Managing Partner, was paid $12,000 during 2001, 2000 and 1999 as an administrative fee for indirect general and administrative overhead expenses.

F-287

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $29,675 and $62,817 are for oil and gas sales, net of lease operating costs and production taxes, as of December 31, 2001 and 2000, respectively.

5.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	183,000		378,000
Production	(17,000	)	(33,000	)
Revision of estimates in place	25,000		244,000
December 31, 1999	191,000		589,000
Production	(16,000	)	(31,000	)
Revision of estimates in place	10,000		(138,000	)
December 31, 2000	185,000		420,000
Production	(15,000	)	(26,000	)
Revision of estimates in place	(37,000	)	(119,000	)
December 31, 2001	133,000		275,000
Proved developed reserves—
December 31, 1999	175,000		563,000
December 31, 2000	169,000		393,000
December 31, 2001	117,000		249,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $17.84 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.48 per Mcf.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent

F-288

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership’s present reserves.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 is presented below:

	2001		2000	1999
Future cash inflows	$	3,050,000	8,793,000	5,814,000
Production and development costs		1,575,000	3,675,000	2,592,000
Future net cash flows		1,475,000	5,118,000	3,222,000
10% annual discount for estimated timing of cash flows		531,000	2,287,000	1,458,000
Standardized measure of discounted future net cash flows	$	944,000	2,831,000	1,764,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(297,000	)	(392,000	)	(239,000	)
Changes in prices and production costs		(1,816,000	)	1,409,000		881,000
Changes of production rates (timing) and other		243,000		18,000		(75,000	)
Revisions of previous quantities estimates		(300,000	)	(144,000	)	401,000
Accretion of discount		283,000		176,000		72,000
Discounted future net cash flows—
Beginning of year		2,831,000		1,764,000		724,000
End of year	$	944,000		2,831,000		1,764,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-289

INDEPENDENT AUDITORS REPORT

The Partners

Southwest Developmental Drilling Fund 1994, LP.

(a Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 1994, L.P. (the “Partnership”) as of December 31, 2001 and 2000, and the related statements of operations, changes in partners’ equity and cash flows for each of the years in the three year period ended December 31, 2001. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 1994, LP. as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

KPMG LLP

Midland, Texas

March 24, 2002

F-290

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

BALANCE SHEETS

	June 30, 2002		December 31,
			2001	2000
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	9,695	18,736	20,979
Receivable from Managing General Partner		15,466	12,560	25,535
Total current assets		25,161	31,296	46,514
Oil and gas properties—using the full-cost method of accounting		2,010,296	2,010,296	2,009,976
Less accumulated depreciation, depletion and amortization		1,895,407	1,891,407	1,875,407
Net oil and gas properties		114,889	118,889	134,569
	$	140,050	150,185	181,083
PARTNERS’ EQUITY
Partners’ equity:
Managing General Partner	$	13,002	13,717	15,516
Investor partners		127,048	136,468	165,567
Total partners’ equity		140,050	150,185	181,083
	$	140,050	150,185	181,083

The accompanying notes are an integral part of these financial statements.

F-291

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF OPERATIONS

	For the six months ended June 30,			For the years ended December 31,
	2002		2001	2001	2000	1999
	(unaudited)
Revenues
Oil and gas revenue	$	73,062	125,827	209,021	262,882	182,630
Interest from operations		20	220	327	509	189
		73,082	126,047	209,348	263,391	182,819
Expenses
Production		30,919	31,231	70,924	78,295	72,782
General and administrative		14,298	14,008	27,988	27,954	29,267
Depreciation, depletion and amortization		4,000	8,000	16,000	9,000	16,642
		49,217	53,239	114,912	115,249	118,691
Net income	$	23,865	72,808	94,436	148,142	64,128
Net income allocated to:
Managing General Partner	$	3,025	8,809	11,988	17,196	8,765
Investor partners	$	20,840	63,999	82,448	130,946	55,363
Per investor partner unit	$	9.32	28.63	36.89	58.59	24.77

The accompanying notes are an integral part of these financial statements.

F-292

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

STATEMENT OF CHANGES IN PARTNERS’ EQUITY

Years ended December 31, 2001, 2000 and 1999

and the six months ended June 30, 2002

	Managing General Partner			Investor Partners		Total
Balance—January 1, 1999	$	10,290		154,300		164,590
Net income		8,765		55,363		64,128
Distributions		(4,290	)	(41,985	)	(46,275	)
Balance—December 31, 1999		14,765		167,678		182,443
Net income		17,196		130,946		148,142
Distributions		(16,445	)	(133,057	)	(149,502	)
Balance—December 31, 2000		15,516		165,567		181,083
Net income		11,988		82,448		94,436
Distributions		(13,787	)	(111,547	)	(125,334	)
Balance—December 31, 2001		13,717		136,468		150,185
Net income		3,025		20,840		23,865
Distributions		(3,740	)	(30,260	)	(34,000	)
Balance—June 30, 2002 (unaudited)	$	13,002		127,048		140,050

The accompanying notes are an integral part of these financial statements.

F-293

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

STATEMENTS OF CASH FLOWS

	For the six months ended June 30,					For the years ended December 31,
	2002			2001		2001		2000		1999
	(unaudited)
Cash flows from operating activities:
Cash received from oil and gas sales	$	69,379		131,882		229,497		261,584		153,015
Cash paid to Managing General Partner for administrative fees and general and administrative overhead		(44,440	)	(53,798	)	(106,413	)	(101,703	)	(100,776	)
Interest received		20		220		327		509		189
Net cash provided by operating activities		24,959		78,304		123,411		160,390		52,428
Cash flows from investing activities:
Additions to oil and gas properties		—		—		(320	)	—		(1,161	)
Sale of oil and gas properties		—		—		—		649		—
Net cash (used in) provided by investing activities		—		—		(320	)	649		(1,161	)
Cash flows used in financing activities:
Distribution to partners		(34,000	)	(87,500	)	(125,334	)	(149,502	)	(46,275	)
Net (decrease) increase in cash and cash equivalents		(9,041	)	(9,196	)	(2,243	)	11,537		4,992
Beginning of period		18,736		20,979		20,979		9,442		4,450
End of period	$	9,695		11,783		18,736		20,979		9,442
Reconciliation of net income to net provided by operating activities:
Net income	$	23,865		72,808		94,436		148,142		64,128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		4,000		8,000		16,000		9,000		16,642
(Increase) decrease in receivables		(3,683	)	6,055		20,476		(1,298	)	(29,615	)
Increase (decrease) in payables		777		(8,559	)	(7,501	)	4,546		1,273
Net cash provided by operating activities	$	24,959		78,304		123,411		160,390		52,428

The accompanying notes are an integral part of these financial statements.

F-294

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS

1.    Organization

Southwest Developmental Drilling Fund 1994, L.P. (the “Partnership”) was organized under the laws of the state of Delaware on July 13, 1994 for the purpose of engaging primarily in the business of drilling developmental and exploratory wells, to produce and market crude oil and natural gas produced from such properties, and acquire leases which contain drilling prospects. The activities of the Partnership should continue for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership anticipates selling its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:

	Investor Partners		Managing General Partner(1)
Organization and offering expenses(2)	100	%	—
Lease acquisition and drilling costs	99	%	1	%
Operating costs*	89	%	11	%
Administrative costs(3)*	89	%	11	%
Direct costs*	89	%	11	%
All other costs*	89	%	11	%
Interest income earned on capital contributions	100	%	—
Oil and gas revenues and other revenues*	89	%	11	%
Intangible drilling costs	99	%	1	%
Depreciation	99	%	1	%
Depletion allowances	99	%	1	%

* After the Investor Partners have received distributions totaling 150% of their capital contributions, the allocation will change to 15% Managing General Partner and 85% Investor Partners.

(1) The Managing General Partner will make a contribution to the capital of the Partnership at the conclusion of its respective Offering Period in an amount equal to one percent (1%) of the Net Capital Contributions to the Partnership.

(2) Organization and Offering Expenses includes the payment by the Partnership of Organization Costs in an amount equal to four percent (4%) of Capital Contributions for reimbursement of expenses. All Organization Costs in excess of four percent (4%) of Capital Contributions with respect to the Partnership will be allocated to and paid by the Managing General Partner.

(3) Administrative Costs will be paid from the Partnership revenues; however, Administrative Costs in any Partnership year in excess of two percent (2%) of Capital Contributions shall be paid by the Managing General Partner. For the purpose of allocating Administrative Costs, the Managing General Partner will allocate each employee’s time among three divisions: (1) operating partnerships; (2) corporate activities; and (3) currently offered or proposed partnerships. The Managing General Partner determines a percentage of total Administrative Costs per division based on the total allocated time per division and personnel costs (salaries) attributable to such time. Within the operating partnership division, Administrative Costs are further allocated on the basis of the total capital of each partnership invested in its operations.

F-295

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

2.    Summary of Significant Accounting Policies

Oil and Gas Properties

Oil and gas properties are accounted for at cost using the full cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.

Depreciation, depletion and amortization of oil and gas properties is computed using the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves, by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership’s independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could change significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2001, 2000 and 1999, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Estimates and Uncertainties

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserve estimates, which are inherently imprecise. Actual results could differ from those estimates.

Environmental Costs

The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Gas Balancing

The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2001, 2000 and 1999, there were no significant amounts of imbalance in terms of units and value.

F-296

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership’s income or loss are passed through to the individual partners. In accordance with the requirements of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” The Partnership’s tax basis in its assets at December 31, 2001, 2000 and 1999 was $31,872, $23,205 and $7,330 less than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Investor Partner Units

As of December 31, 2001, 2000 and 1999 there were 2,235 investor units outstanding held by 114, 114 and 112 partners, respectively.

Concentrations of Credit Risk

The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.

Three customers purchased 53%, 28% and 16% of the Partnership’s oil and gas production during 2001. Three customers purchased 50%, 29% and 18% of the Partnership’s oil and gas production during 2000. Three customers purchased 55%, 24% and 19% of the Partnership’s oil and gas production during 1999.

Net Income per limited partnership unit

The net income per limited partnership unit is calculated by using the weighted average number of limited partnership units outstanding during the year.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No.133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Assessment by the Managing General Partner revealed this pronouncement to have no impact on the partnerships.

The FASB has issued Statement No. 143 “Accounting for Asset Retirement Obligations” which establishes requirements for the accounting of removal-type costs associated with asset retirements. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Managing General Partner is currently assessing the impact on the partnerships financial statements.

F-297

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

On October 3, 2001, the FASB issued Statement No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” This pronouncement supercedes SFAS 121 “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed” and eliminates the requirement of Statement 121 to allocate goodwill to long-lived assets to be tested for impairment. The provisions of this statement are effective for financial statements issued for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Managing General Partner is currently assessing the impact to the partnerships financial statements.

3.    Commitments and Contingent Liabilities

The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the Managing General Partner in its sole and absolute discretion.

The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.

As of December 31, 2001, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance.

The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership’s liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership’s properties.

4.    Related Party Transactions

The oil and gas properties in which the Partnership has an interest are operated by the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $11,600, $11,200 and $11,000 for the years ended December 31, 2001, 2000 and 1999, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately none, $1,300 and $3,200 for the years ended December 31, 2001, 2000 and 1999, respectively.

F-298

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

Southwest Royalties, Inc., the Managing General Partner, was paid an administrative fee of $24,000 during 2001, 2000 and 1999 for reimbursement of indirect general and administrative overhead expenses.

A director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services provided during 2001, 2000 and 1999.

Receivables from Southwest Royalties, Inc., the Managing General Partner, of $12,560 and $25,535 is for oil and gas sales, net of lease operating costs and production taxes as of December 31, 2001 and 2000.

5.    Estimated Oil and Gas Reserves (unaudited)

The Partnership’s interest in proved oil and gas reserves is as follows:

	Oil (bbls)		Gas (mcf)
Proved developed and undeveloped reserves—
January 1, 1999	42,000		109,000
Production	(8,000	)	(15,000	)
Revisions of previous estimates	38,000		97,000
December 31, 1999	72,000		191,000
Production	(7,000	)	(13,000	)
Revisions of previous estimates	16,000		17,000
December 31, 2000	81,000		195,000
Production	(7,000	)	(10,000	)
Revisions of previous estimates	(18,000	)	(64,000	)
December 31, 2001	56,000		121,000
Proved developed reserves—
December 31, 1999	72,000		191,000
December 31, 2000	81,000		195,000
December 31, 2001	56,000		121,000

All of the Partnership’s reserves are located within the continental United States.

* Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2002 are an average price of $18.91 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2002 are an average price of $2.34 per Mcf.

F-299

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

(a Delaware Limited Partnership)

NOTES TO FINANCIAL STATEMENTS—(Continued)

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Partnership has reserves, which are classified as proved developed producing. All of the proved reserves are included in the engineering reports, which evaluate the Partnership’s present reserves.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001, 2000 and 1999 are presented below:

	2001		2000	1999
Future cash inflows	$	1,344,000	4,071,000	2,175,000
Production and development costs		804,000	1,798,000	1,246,000
Future net cash flows		540,000	2,273,000	929,000
10% annual discount for estimated timing of cash flows		192,000	1,086,000	353,000
Standardized measure of discounted future net cash flows	$	348,000	1,187,000	576,000

The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2001, 2000 and 1999 are as follows:

	2001			2000		1999
Sales of oil and gas produced, net of production costs	$	(138,000	)	(185,000	)	(110,000	)
Changes in prices and production costs		(880,000	)	601,000		205,000
Changes of production rates (timing) and other		191,000		(60,000	)	9,000
Revisions of previous quantities estimates		(131,000	)	197,000		300,000
Accretion of discount		119,000		58,000		16,000
Discounted future net cash flows—
Beginning of year		1,187,000		576,000		156,000
End of year	$	348,000		1,187,000		576,000

Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.

F-300

UNAUDITED MAXIMUM PRO FORMA FINANCIAL INFORMATION

The following unaudited maximum pro forma financial information has been prepared to assist in the analysis of the financial effects of the combination transactions involving Southwest and the partnerships. This pro forma information is based on the historical financial statements of the entities participating in the combination transactions.

The information was prepared based on the following:

• After completion of the combination transactions, 1,688,347 Southwest common shares are assumed to be outstanding. For information regarding the merger value of the limited partners’ share of the partnerships, see Method of Determining Merger Values elsewhere in this document.

• Both Southwest and the partnerships utilize the full cost method of accounting for their oil and gas activities.

• The combination transactions are completed by June 30, 2002.

• The combination transactions are accounted for as a reorganization of interests under common control in a manner similar to a pooling of interests.

• The unaudited pro forma balance sheet has been prepared as if the combination transactions occurred on June 30, 2002. The unaudited pro forma statements of operations and cash flows have been prepared as if the combination transactions occurred on January 1, 2001.

• Targeted annual general and administrative expense savings from the combination transactions have not been reflected as an adjustment to the historical data.

• Costs of the combination transactions incurred are estimated to be $3.0 million. Costs related to the combination transactions with the partnerships will be expensed by Southwest in the period the combination transactions are completed.

The unaudited pro forma financial statements and related notes are presented for illustrative purposes only. If the combination transactions had occurred in the past, Southwest’s financial position or operating results might have been different from those presented in the unaudited pro forma information. The unaudited pro forma information should not be relied on as an indication of the financial position or operating results that Southwest would have achieved if the combination transactions had occurred as of June 30, 2002 or January 1, 2001. The unaudited pro forma information also should not be relied on as an indication of the future results that Southwest will achieve after the completion of the combination transactions.

P-1

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA BALANCE SHEET

As of June 30, 2002

(in thousands, except share data)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
ASSETS
Current assets
Cash and cash equivalents	$	6,901		$	560		$	(132	)(b)	$	7,453
								124	(c)
Restricted cash		598			—			—			598
Accounts receivable, net		6,734			1,594			(1,432	)(a)		6,150
								(878	)(b)
								132	(c)
Other current assets		671			—			—			671
Total current assets		14,904			2,154			(2,186	)		14,872
Oil and gas properties, using the full cost method of accounting, net		86,464			10,268			302	(b)		97,034
Other property and equipment, net		4,124			—			—			4,124
Other assets, net		4,562			—			—			4,562
Total assets	$	110,054		$	12,422		$	(1,884	)	$	120,592
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	18,204		$	157		$	(30	)(b)	$	18,331
Accounts payable and accrued expenses		7,308			856			(1,432	)(a)		9,371
								(361	)(b)
								3,000	(d)
Total current liabilities		25,512			1,013			1,177			27,702
Long-term debt		121,900			287			(53	)(b)		122,134
Other long-term liabilities		521			—			—			521
Deferred income taxes payable		2,501			—			201	(e)		2,375
								(327	)(g)
Stockholders’ equity
Preferred stock—$1 par value		—			—			—			—
Common stock—$.01 par value		1			—			7	(f)		8
Class A common stock—$.01 par value		9			—			—			9
Additional paid-in capital		38,917			—			(28,951	)(f)		9,966
Accumulated deficit		(79,307	)		—			(264	)(b)		(42,123	)
								(201	)(e)
								(3,000	)(d)
								40,322	(f)
								327	(g)
General partners equity		—			(2,190	)		103	(c)		—
								2,087	(f)
Limited partners equity		—			13,312			153	(c)		—
								(13,465	)(f)
Total stockholders’ deficit		(40,380	)		11,122			(2,882	)		(32,140	)
Total liabilities and stockholders’ equity	$	110,054		$	12,422		$	(1,884	)	$	120,592
Book value per share	$	(40.38	)							$	(19.04	)
Common shares outstanding		1,000,000									1,688,347

See accompanying notes to unaudited pro forma financial information.

P-2

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA STATEMENT OF OPERATIONS

Six months ended June 30, 2002

(in thousands, except per share data)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Operating revenues
Oil and gas	$	18,775		$	6,271		$	(1,353	)(h)	$	23,693
Other		165			—			—			165
Total operating revenues		18,940			6,271			(1,353	)		23,858
Operating expenses
Oil and gas production		7,054			4,392			(930	)(i)		9,759
								(757	)(h)
General and administrative, net		2,001			717			930	(i)		3,302
								(346	)(h)
Depreciation, depletion and amortization		3,478			448			(99	)(h)		3,827
Other		119			—			—			119
Total operating expenses		12,652			5,557			(1,202	)		17,007
Operating income (loss)		6,288			714			(151	)		6,851
Other income (expense)
Interest and dividend income		117			3			—			120
Miscellaneous income		—			39			(8	)(h)		31
Interest expense		(6,918	)		(4	)		—			(6,922	)
Other		(522	)		—			—			(522	)
		(7,323	)		38			(8	)		(7,293	)
Income (loss) before income taxes and transaction expenses		(1,035	)		752			(159	)		(442	)
Income tax (expense) benefit		—			—			(201	)(j)		(201	)
Income (loss) before transaction expenses		(1,035	)		752			(360	)		(643	)
Transaction expenses		—			—			3,000	(k)		3,000
Net income (loss) after transaction expenses	$	(1,035	)	$	752		$	(3,360	)	$	(3,643	)
Net income (loss) per common share outstanding—Basic:
Before transaction expenses	$	(2.26	)							$	(.56	)
After transaction expenses	$	(2.26	)							$	(3.18	)
Weighted average common shares outstanding—Basic		458,011						688,347	(l)		1,146,358

See accompanying notes to unaudited pro forma financial information.

P-3

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA STATEMENT OF CASH FLOWS

Six months ended June 30, 2002

(in thousands)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from operating activities
Net income (loss)	$	3,821		$	752		$	(360	)(m)	$	1,213
								(3,000	)(p)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		3,478			448			(99	)(m)		3,827
Noncash interest expense		676			—			—			676
Noncash reclassification of unrealized gain		(81	)		—			—			(81	)
Noncash interest income		(36	)		—			—			(36	)
Noncash unrealized loss on oil and gas hedges		415			—			—			415
Noncash unrealized loss on investments		1,222			—			—			1,222
Extraordinary loss from early extinguishment of debt		2,132			—			—			2,132
Extraordinary gain from exchange transaction		(9,489	)		—			—			(9,489	)
Gain on sale of assets		(2	)		—			—			(2	)
Bad debt expense		51			—			—			51
Deferred income taxes		2,501			—			201	(o)		2,702
Changes in operating assets and liabilities—
Accounts receivable		(962	)		(394	)		2,179	(n)		823
Prepaid federal income taxes		—			158			—			158
Other current assets		(315	)		—			—			(315	)
Accounts payable and accrued expenses		(1,078	)		(40	)		(1,793	)(n)		89
								3,000	(p)
Accrued interest payable		332			—			—			332
Restricted cash		42			—			—			42
Net cash provided by operating activities		2,707			924			128			3,759
Cash flows from investing activities
Proceeds from sale of oil and gas properties		294			—			—			294
Investment in oil and gas properties		(2,150	)		(571	)		(203	)(m)		(2,924	)
Proceeds from sale of other property and equipment		2			—			—			2
Purchase of other property and equipment		(35	)		—			—			(35	)
Purchase of other assets		(51	)		—			—			(51	)
Net cash used in investing activities		(1,940	)		(571	)		(203	)		(2,714	)

(continued)

See accompanying notes to unaudited pro forma financial information.

P-4

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA STATEMENT OF CASH FLOWS—(Continued)

Six months ended June 30, 2002

(in thousands)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from financing activities
Distribution to partners	$	—		$	(1,039	)	$	256	(m)	$	(783	)
Proceeds from borrowings		55,113			470			(88	)(m)		55,495
Payments on debt		(50,068	)		(26	)		5	(m)		(50,089	)
Additions to debt issue costs		(1,790	)		—			—			(1,790	)
Change in other long-term liabilities		(6	)		—			—			(6	)
Prepayment penalty on early extinguishment of debt		(1,000	)		—			—			(1,000	)
Offering costs associated with exchange transaction		(2,584	)		—			—			(2,584	)
Other		—			—			(105	)(m)		(105	)
Net cash provided by (used in) financing activities		(335	)		(595	)		68			(862	)
Net (decrease) increase in unrestricted cash and cash equivalents		432			(242	)		(7	)		183
Unrestricted cash and cash equivalents—
beginning of period		6,469			802			(1	)		7,270
Unrestricted cash and cash equivalents—
end of period	$	6,901		$	560		$	(8	)	$	7,453
Non-cash investing and financing activities
Extinguishment of $114.2 million of debt, net of a $0.6 million unamortized discount as part of the exchange transaction	$	(114,187	)	$	—		$	—		$	(114,187	)
Issuance of $60.0 million face value variable interest senior notes as part of the exchange transaction plus $15.1 million of future interest costs in accordance with SFAS No. 15	$	75,088		$	—		$	—		$	75,088
Issuance of 900,000 shares of Southwest stock with a fair market value of $29.6 million as part of the exchange transaction	$	29,586		$	—		$	—		$	29,586
Exchange of note receivable from stockholder for stock in privately held company, which collateralized the note	$	1,584		$	—		$	—		$	1,584
Supplemental disclosures of cash flow information
Interest paid	$	5,909		$	4		$	—		$	5,913
Income taxes paid (received)	$	—		$	—		$	—		$	—

See accompanying notes to unaudited pro forma financial information.

P-5

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA STATEMENT OF OPERATIONS

Year ended December 31, 2001

(in thousands, except per share data)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Operating revenues
Oil and gas	$	50,991		$	17,149		$	(3,472	)(h)	$	64,668
Other		249			—			—			249
Total operating revenues		51,240			17,149			(3,472	)		64,917
Operating expenses
Oil and gas production		17,798			9,382			(1,841	)(i)		23,815
								(1,524	)(h)
General and administrative, net		3,133			1,442			1,841	(i)		5,716
								(700	)(h)
Depreciation, depletion and amortization		10,249			2,080			(344	)(h)		11,985
Other		238			—			—			238
Total operating expenses		31,418			12,904			(2,568	)		41,754
Operating income (loss)		19,822			4,245			(904	)		23,163
Other income (expense)
Interest and dividend income		813			57			(12	)(h)		858
Interest expense		(19,579	)		(6	)		—			(19,585	)
Other		(890	)		—			—			(890	)
		(19,656	)		51			(12	)		(19,617	)
Income (loss) before income taxes and transaction expenses		166			4,296			(916	)		3,546
Income tax expense		(6,000	)		(34	)		(1,115	)(j)		(7,149	)
Income (loss) before transaction expenses		(5,834	)		4,262			(2,031	)		(3,603	)
Transaction expenses		—			—			3,000	(k)		3,000
Net income (loss) after transaction expenses	$	(5,834	)	$	4,262		$	(5,031	)	$	(6,603	)
Net income (loss) per common share outstanding—Basic:
Before transaction expenses	$	(58.34	)							$	(4.57	)
After transaction expenses	$	(58.34	)							$	(8.38	)
Weighted average common shares outstanding—Basic		100,000						688,347	(l)		788,347

See accompanying notes to unaudited pro forma financial information.

P-6

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA STATEMENT OF CASH FLOWS

Year ended December 31, 2001

(in thousands)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from operating activities
Net income (loss)	$	(5,834	)	$	4,262		$	(2,031	)(m)	$	(6,603	)
								(3,000	)(p)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		10,249			2,080			(344	)(m)		11,985
Noncash interest expense		1,662			—			—			1,662
Noncash reclassification of unrealized gain		(949	)		—			—			(949	)
Noncash unrealized loss on oil and gas hedges		1,003			—			—			1,003
Gain on sale of assets		(15	)		—			—			(15	)
Bad debt expense		566			—			—			566
Deferred income taxes		6,000			34			1,115	(o)		7,149
Changes in operating assets and liabilities—
Accounts receivable		2,915			2,059			1,465	(n)		6,439
Prepaid federal income taxes		—			(142	)		—			(142	)
Other current assets		2,817			—			—			2,817
Accounts payable and accrued expenses		(2,454	)		(165	)		(1,560	)(n)		(1,179	)
								3,000	(p)
Accrued interest payable		(82	)		—			—			(82	)
Restricted cash		119			—			—			119
Net cash provided by (used in) operating activities		15,997			8,128			(1,355	)		22,770
Cash flows from investing activities
Proceeds from sale of oil and gas properties		65			57			—			122
Investment in oil and gas properties		(23,918	)		(1,454	)		(277	)(m)		(25,649	)
Proceeds from sale of other property and equipment		18			—			—			18
Purchase of other property and equipment		(320	)		—			—			(320	)
Proceeds from sale of other assets		20			—			—			20
Purchase of other assets		(605	)		—			—			(605	)
Other		32			—			—			32
Net cash used in investing activities		(24,708	)		(1,397	)		(277	)		(26,382	)

(continued)

See accompanying notes to unaudited pro forma financial information.

P-7

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MAXIMUM PRO FORMA STATEMENT OF CASH FLOWS—(Continued)

Year ended December 31, 2001

(in thousands)

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from financing activities
Distribution to partners	$	—		$	(7,510	)	$	1,599	(m)	$	(5,911	)
Proceeds from borrowings		178			—			—			178
Payments on debt		(155	)		(233	)		—			(388	)
Change in other long-term liabilities		(222	)		—			—			(222	)
Deferred debt costs		(216	)		—			—			(216	)
Other		—			—			(440	)(m)		(440	)
Net cash provided by (used in) financing activities		(415	)		(7,743	)		1,159			(6,999	)
Net decrease in unrestricted cash and cash equivalents		(9,126	)		(1,012	)		(473	)		(10,611	)
Unrestricted cash and cash equivalents—
beginning of period		15,595			1,814			472			17,881
Unrestricted cash and cash equivalents—
end of period	$	6,469		$	802		$	(1	)	$	7,270
Non-cash investing and financing activities
Unrealized gain on oil and gas commodity option contracts—taken to other comprehensive income	$	1,030		$	—		$	—		$	1,030
Decrease in other long-term liabilities associated with deferred debt costs	$	(500	)	$	—		$	—		$	(500	)
Increase in accrued expenses associated with deferred debt costs	$	500		$	—		$	—		$	500
Supplemental disclosures of cash flow information
Interest paid	$	17,999		$	—		$	6		$	18,005
Income taxes paid (received)	$	—		$	—		$	—		$	—

See accompanying notes to unaudited pro forma financial information.

P-8

NOTES TO UNAUDITED MAXIMUM PRO FORMA FINANCIAL INFORMATION

June 30, 2002 and December 31, 2001

1.    Method of Accounting for the Combination Transactions

In presentation of the accompanying pro forma financial information, Southwest accounted for the combination transactions as a reorganization of entities under common control in a manner similar to a pooling of interests.

Following is a description of the individual columns included in these unaudited pro forma combined financial statements:

Southwest Royalties, Inc.—Represents the consolidated balance sheet as of June 30, 2002, and the consolidated statement of cash flows and consolidated statement of operations (exclusive of extraordinary items) of Southwest Royalties, Inc. and subsidiaries for the six months ended June 30, 2002 and for the year ended December 31, 2001, respectively.

Combined Partnerships—Represents the combined balance sheets of the 21 limited partnerships as of June 30, 2002 and the combined statements of cash flows and the combined statements of operations of such limited partnerships for the six months ended June 30, 2002 and year ended December 31, 2001.

2.    Pro Forma Adjustments Related to the Combination Transactions

The unaudited pro forma balance sheet includes the following adjustments:

a)  This adjustment eliminates receivable and payable balances between Southwest and the partnerships.

b)  This adjustment restates equity for current period and historical proportionate consolidation of the partnerships’ earnings and distributions to Southwest from the partnerships.

c)  This adjustment reclassifies the current period distributions in transit and the first quarter distributions paid from the partnerships to Southwest.

d)  This adjustment records the $3.0 million estimated transaction costs related to Southwest and the partnerships. The transaction costs relate primarily to legal, printing costs and accounting fees.

e)  This adjustment records the tax effect of the earnings and all pro forma adjustments of the combined partnerships for the six months ended June 30, 2002, at a 34% statutory federal income tax rate.

f)  This adjustment records the $.01 par value of the 1,688,347 common shares of Southwest that will be outstanding after completing the combination transactions and reclassifies the partnerships’ equity to additional paid-in capital and accumulated deficit of Southwest.

g)  This adjustment decreases Southwest’s deferred income taxes for the tax effect of the differences between the financial carrying amounts and the tax bases of the partnerships’ assets and liabilities at June 30, 2002 using a statutory federal tax rate of 34%. The partnerships have not recorded deferred income taxes since any tax liabilities are the responsibility of the individual partners. The $327,000 has been excluded from the unaudited pro forma statements of operations as the amount will not recur and is directly attributable to the combination transactions. The deferred income taxes will be recorded as part of operations in the period in which the combination transactions are completed.

The unaudited pro forma statements of operations include the following adjustments:

h)  These adjustments eliminate duplicative amounts of the partnerships, which are also included in Southwest’s financial statements. Southwest manages and controls the operations of the partnerships and therefore consolidates their proportionate share of the partnerships’ revenues and expenses.

P-9

NOTES TO UNAUDITED MAXIMUM PRO FORMA FINANCIAL INFORMATION—(Continued)

June 30, 2002 and December 31, 2001

i)  These adjustments eliminate oil and gas administrative overhead charged to the partnerships as working interests owners in wells operated by Southwest. The overhead charges are recorded by Southwest as a reduction of general and administrative expenses.

j)  This adjustment records the tax effect of the combined partnerships net income and all pro forma adjustments at a 34% statutory federal rate. The adjustment includes income taxes for the applicable periods for the partnerships for which no income taxes have been previously recorded.

k)  This adjustment records estimated transaction costs related to Southwest and the partnerships. Total combination transaction costs are expected to be $3.0 million and primarily relate to legal, printing costs and accounting fees.

l)  To adjust the weighted average shares outstanding for the combination of the Combined Partnerships

The unaudited pro forma statements of cash flows include the following adjustments:

m)  These adjustments eliminate the cash flows of the partnerships, which are also included in Southwest’s financial statements. Southwest manages and controls the operation of the partnerships, and therefore consolidates their proportionate share of the partnerships’ cash flows.

n)  These adjustments reflect the net adjustments to the pro forma balance sheet and reflect pro forma adjustments affecting the reconciliation of net earnings to net cash provided by operating activities.

o)  This adjustment reflects the change in deferred income taxes, resulting from pro forma adjustments due to the calculation of income taxes for the partnerships. The adjustment includes income taxes for the applicable periods for the partnerships for which no income taxes have been previously recorded.

p)  This adjustment records estimated transaction costs related to Southwest and the partnerships. Total combination transaction costs are expected to be $3.0 million and primarily relate to legal, printing costs and accounting fees.

3.    Income Taxes

Southwest will account for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. In accordance therewith, Southwest will prepare separate tax calculations for each tax jurisdiction in which Southwest will be subject to income taxes. The amount of deferred income tax will be recorded on the balance sheet against accumulated deficit. The pro forma statements of income record the tax effect of the combined partnerships net income and all pro forma adjustments at a 34% statutory federal rate. The adjustment includes income taxes for the applicable periods for the partnerships for which no income taxes have been previously recorded. Accordingly, Southwest has recognized income tax expense in the accompanying unaudited pro forma combined statement of operations for the six months ended June 30, 2002 and for the year ended December 31, 2001.

4.    Pro Forma Outstanding Shares of Southwest

A total of 1,688,347 shares of Southwest common stock will be issued and outstanding after the combination transactions. The owners of each of the participating partnerships will receive shares of Southwest common stock in proportion to the “Merger Value” of each partnership to the total Merger Value of all Partnerships and Southwest combined. The Merger Value has been determined by Southwest and is based on a valuation of each partnership’s oil and gas reserves and other assets and liabilities.

P-10

NOTES TO UNAUDITED MAXIMUM PRO FORMA FINANCIAL INFORMATION—(Continued)

June 30, 2002 and December 31, 2001

The number of shares to be received by each participating partnership is reflected in the table on page 13 of the prospectus/proxy statement under the heading Aggregate Number of Shares of Southwest Common Stock Offered to Limited Partners.

5.    Pro Forma Information on Oil and Gas Operations

The pro forma reserve information set forth below assumes the combination transactions were completed on January 1, 2002. There are many uncertainties inherent in estimating reserve quantities, and in projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, estimates are subject to change as additional information becomes available.

Proved oil and natural gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic conditions. Proved developed oil and natural gas reserves are those reserves expected to be recovered through existing equipment and operating methods.

All reserves are located in the United States.

Changes in Pro Forma Proved Reserves

	Southwest Royalties, Inc. Historical		Combined Partnerships Historical		Pro Forma Adjustments		Pro Forma
	(In thousands)
Oil (MBbls):
Proved reserves, December 31, 2001	19,937		3,466		(772	)	22,631
Purchase of minerals-in-place	265		89		(17	)	337
Sales of minerals-in-place	(61	)	—		—		(61	)
Revisions of previous estimates	904		915		(216	)	1,603
Production	(561	)	(205	)	45		(721	)
Proved reserves, June 30, 2002	20,484		4,265		(960	)	23,789
Proved developed reserves, June 30, 2002	15,001		3,767		(848	)	17,920
Natural Gas (MMcf):
Proved reserves, December 31, 2001	74,783		20,355		(5,289	)	89,849
Purchase of minerals-in-place	2,893		—		—		2,893
Sales of minerals-in-place	(55	)	—		—		(55	)
Revisions of previous estimates	2,777		1,187		(185	)	3,779
Production	(2,381	)	(744	)	195		(2,930	)
Proved reserves, June 30, 2002	78,017		20,798		(5,279	)	93,536
Proved developed reserves, June 30, 2002	50,503		15,192		(4,117	)	61,578

P-11

NOTES TO UNAUDITED MAXIMUM PRO FORMA FINANCIAL INFORMATION—(Continued)

June 30, 2002 and December 31, 2001

Pro Forma Standardized Measure of Discounted Future Net Cash Flows—June 30, 2002

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Pro Forma
	(In thousands)
Future cash inflows	$	745,262		$	167,753		$	(39,690	)	$	873,325
Future production and development costs		(307,955	)		(74,866	)		16,967			(365,854	)
Future net cash flows before income taxes		437,307			92,887			(22,723	)		507,471
Future income tax expense		(125,783	)		(6,287	)		(17,477	)		(149,547	)
Future net cash flows		311,524			86,600			(40,200	)		357,924
10% annual discount for estimated timing of cash flows		(158,951	)		(40,595	)		10,280			(189,266	)
Standardized measure of discounted future net cash flows	$	152,573		$	46,005		$	(29,920	)	$	168,658

Pro Forma Changes in Standardized Measure of Discounted Future Net Cash Flows

	Southwest Royalties, Inc. Historical			Combined Partnerships Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
	(In thousands)
Balance at December 31, 2001	$	118,066		$	26,302		$	(6,648	)	$	137,720
Sales of oil and gas produced, net of production costs		(11,721	)		(1,879	)		452			(13,148	)
Net change in sales prices net of production costs		66,050			15,845			(3,703	)		78,192
Extensions and discoveries, net of future production and development costs		—			—			—			—
Revisions to estimated future development costs		60			32			(6	)		86
Purchases of minerals-in-place		4,759			382			(74	)		5,067
Revisions of previous quantity estimates		10,218			7,097			(1,611	)		15,704
Accretion of discount		14,346			2,812			(700	)		16,458
Net change in income taxes		(40,562	)		(1,710	)		(18,365	)		(60,637	)
Sales of minerals-in-place		(112	)		—			—			(112	)
Changes in production rates, timing and other		(8,531	)		(2,876	)		735			(10,672	)
Balance at June 30, 2002	$	152,573		$	46,005		$	(29,920	)	$	168,658

The pro forma adjustment to standardized measure and changes in standardized measure of discounted future net cash flows reflects the future income tax expense impact on Southwest’s standardized measure and changes in standardized measure of discounted future net cash flows using a federal tax rate of 34%. Future income tax expense has been excluded from the partnerships’ historical standardized measure and changes in standardized measure of discounted future net cash flows since any tax liabilities are the responsibility of the individual partners.

P-12

UNAUDITED MINIMUM PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma financial information has been prepared to assist in the analysis of the financial effects of the combination transaction involving Southwest and Southwest Royalties, Inc. Income Fund VI. This pro forma information is based on the historical financial statements of the entities participating in the combination transaction.

The information was prepared based on the following:

• After completion of the combination transaction, 1,000,901 Southwest common shares are assumed to be outstanding.

• Both Southwest and Income Fund VI utilize the full cost method of accounting for their oil and gas activities.

• The combination transaction is completed by June 30, 2002.

• The combination transaction is accounted for as a reorganization of interests under common control in a manner similar to a pooling of interests.

• The unaudited pro forma balance sheet has been prepared as if the combination transaction occurred on June 30, 2002. The unaudited pro forma statements of operations and cash flows have been prepared as if the combination transaction occurred on January 1, 2001.

• Targeted annual general and administrative expense savings from the combination transaction has not been reflected as an adjustment to the historical data.

• Costs of the combination transaction incurred are estimated to be $3.0 million. Costs related to the combination transaction with Income Fund VI will be expensed by Southwest in the period the combination transaction is completed.

The unaudited pro forma financial statements and related notes are presented for illustrative purposes only. If the combination transaction had occurred in the past, Southwest’s financial position or operating results might have been different from those presented in the unaudited pro forma information. The unaudited pro forma information should not be relied on as an indication of the financial position or operating results that Southwest would have achieved if the combination transaction had occurred as of June 30, 2002 or January 1, 2001. The unaudited pro forma information also should not be relied on as an indication of the future results that Southwest will achieve after the completion of the combination transaction.

P-13

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA BALANCE SHEET

As of June 30, 2002

(in thousands, except share data)

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
ASSETS
Current assets
Cash and cash equivalents	$	6,901		$	117		$	(44	)(b)	$	6,974
Restricted cash		598			—			—			598
Accounts receivable, net		6,734			152			(232	)(a)		6,697
								43	(b)
Other current assets		671			—			—			671
Total current assets		14,904			269			(233	)		14,940
Oil and gas properties, using the full cost method of accounting, net		86,464			1,487			51	(b)		88,002
Other property and equipment, net		4,124			—			—			4,124
Other assets, net		4,562			—			—			4,562
Total assets	$	110,054		$	1,756		$	(182	)	$	111,628
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	18,204		$	—		$	—		$	18,204
Accounts payable and accrued expenses		7,308			185			(232	)(a)		10,149
								(112	)(b)
								3,000	(d)
Total current liabilities		25,512			185			2,656			28,353
Long-term debt		121,900			—			—			121,900
Other long-term liabilities		521			—			—			521
Deferred income taxes payable		2,501			—			(24	)(e)		2,804
								327	(g)
Stockholders’ equity
Preferred stock—$1 par value		—			—			—			—
Common stock—$.01 par value		1			—			—			1
Class A common stock—$.01 par value		9			—			—			9
Additional paid-in capital		38,917			—			(8,254	)(f)		30,663
Accumulated deficit		(79,307	)		—			162	(b)		(72,623	)
								24	(e)
								(3,000	)(d)
								9,825	(f)
								(327	)(g)
General partners equity		—			(697	)		697	(f)		—
Limited partners equity		—			2,268			(2,268	)(f)		—
Total stockholders’ deficit		(40,380	)		1,571			(3,141	)		(41,950	)
Total liabilities and stockholders’ equity	$	110,054		$	1,756		$	(182	)	$	111,628
Book value per share	$	(40.38	)							$	(41.91	)
Common shares outstanding		1,000,000									1,000,901

See accompanying notes to unaudited pro forma financial information.

P-14

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA STATEMENT OF OPERATIONS

Six months ended June 30, 2002

(in thousands, except per share data)

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Operating revenues
Oil and gas	$	18,775		$	674		$	(254	)(h)	$	19,195
Other		165			—			—			165
Total operating revenues		18,940			674			(254	)		19,360
Operating expenses
Oil and gas production		7,054			664			(49	)(i)		7,439
								(230	)(h)
General and administrative, net		2,001			75			49	(i)		2,077
								(48	)(h)
Depreciation, depletion and amortization		3,478			51			(19	)(h)		3,510
Other		119			—			—			119
Total operating expenses		12,652			790			(297	)		13,145
Operating income (loss)		6,288			(116	)		43			6,215
Other income (expense)
Interest and dividend income		117			1			—			118
Miscellaneous income		—			1			—			1
Interest expense		(6,918	)		—			—			(6,918	)
Other		(522	)		—			—			(522	)
		(7,323	)		2			—			(7,321	)
Income (loss) before income taxes and transaction expenses		(1,035	)		(114	)		43			(1,106	)
Income tax (expense) benefit		—			—			24	(j)		24
Income (loss) before transaction expenses		(1,035	)		(114	)		67			(1,082	)
Transaction expenses		—			—			3,000	(k)		3,000
Net income (loss) after transaction expenses	$	(1,035	)	$	(114	)	$	(2,933	)	$	(4,082	)
Net income (loss) per common share outstanding—Basic:
Before transaction expenses	$	(2.26	)							$	(2.36	)
After transaction expenses	$	(2.26	)							$	(8.89	)
Weighted average common shares outstanding—Basic		458,011						901	(l)		458,912

See accompanying notes to unaudited pro forma financial information.

P-15

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA STATEMENT OF CASH FLOWS

Six months ended June 30, 2002

(in thousands)

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from operating activities
Net income (loss)	$	3,821		$	(114	)	$	67	(m)	$	774
								(3,000	)(p)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		3,478			51			(19	)(m)		3,510
Noncash interest expense		676			—			—			676
Noncash reclassification of unrealized gain		(81	)		—			—			(81	)
Noncash interest income		(36	)		—			—			(36	)
Noncash unrealized loss on oil and gas hedges		415			—			—			415
Noncash unrealized loss on investments		1,222			—			—			1,222
Extraordinary loss from early extinguishment of debt		2,132			—			—			2,132
Extraordinary gain from exchange transaction		(9,489	)		—			—			(9,489	)
Gain on sale of assets		(2	)		—			—			(2	)
Bad debt expense		51			—			—			51
Deferred income taxes		2,501			—			(24	)(o)		2,477
Changes in operating assets and liabilities—
Accounts receivable		(962	)		18			197	(n)		(747	)
Other current assets		(315	)		—			—			(315	)
Accounts payable and accrued expenses		(1,078	)		30			(344	)(n)		1,608
								3,000	(p)
Accrued interest payable		332			—			—			332
Restricted cash		42			—			—			42
Net cash provided by operating activities		2,707			(15	)		(123	)		2,569
Cash flows from investing activities
Proceeds from sale of oil and gas properties		294			—			—			294
Investment in oil and gas properties		(2,150	)		—			(32	)(m)		(2,182	)
Proceeds from sale of other property and equipment		2			—			—			2
Purchase of other property and equipment		(35	)		—			—			(35	)
Purchase of other assets		(51	)		—			—			(51	)
Net cash used in investing activities		(1,940	)		—			(32	)		(1,972	)

(continued)

See accompanying notes to unaudited pro forma financial information.

P-16

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA STATEMENT OF CASH FLOWS—(Continued)

Six months ended June 30, 2002

(in thousands)

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from financing activities
Distribution to partners	$	—		$	—		$	—		$	—
Proceeds from borrowings		55,113			—			—			55,113
Payments on debt		(50,068	)		—			—			(50,068	)
Additions to debt issue costs		(1,790	)		—			—			(1,790	)
Change in other long-term liabilities		(6	)		—			—			(6	)
Prepayment penalty on early extinguishment of debt		(1,000	)		—			—			(1,000	)
Offering costs associated with exchange transaction		(2,584	)		—			—			(2,584	)
Other		—			—			119	(m)		119
Net cash provided by (used in) financing activities		(335	)		—			119			(216	)
Net (decrease) increase in unrestricted cash and cash equivalents		432			(15	)		(36	)		381
Unrestricted cash and cash equivalents—
beginning of period		6,469			132			(8	)		6,593
Unrestricted cash and cash equivalents—
end of period	$	6,901		$	117		$	(44	)	$	6,974
Non-cash investing and financing activities
Extinguishment of $114.2 million of debt, net of a $0.6 million unamortized discount as part of the exchange transaction	$	(114,187	)	$	—		$	—		$	(114,187	)
Issuance of $60.0 million face value variable interest senior notes as part of the exchange transaction plus $15.1 million of future interest costs in accordance with SFAS No. 15	$	75,088		$	—		$	—		$	75,088
Issuance of 900,000 shares of Southwest stock with a fair market value of $29.6 million as part of the exchange transaction	$	29,586		$	—		$	—		$	29,586
Exchange of note receivable from stockholder for stock in privately held company, which collateralized the note	$	1,584		$	—		$	—		$	1,584
Supplemental disclosures of cash flow information
Interest paid	$	5,909		$	—		$	—		$	5,909
Income taxes paid (received)	$	—		$	—		$	—		$	—

See accompanying notes to unaudited pro forma financial information.

P-17

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA STATEMENT OF OPERATIONS

Year ended December 31, 2001

(in thousands, except per share data)

	Southwest Royalties, Inc. Historical			Partnership Historical		Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Operating revenues
Oil and gas	$	50,991		$	2,138	$	(718	)(h)	$	52,411
Other		249			—		—			249
Total operating revenues		51,240			2,138		(718	)		52,660
Operating expenses
Oil and gas production		17,798			1,183		(105	)(i)		18,514
							(362	)(h)
General and administrative, net		3,133			152		105	(i)		3,297
							(93	)(h)
Depreciation, depletion and amortization		10,249			240		(69	)(h)		10,420
Other		238			—		—			238
Total operating expenses		31,418			1,575		(524	)		32,469
Operating income (loss)		19,822			563		(194	)		20,191
Other income (expense)
Interest and dividend income		813			9		(3	)(h)		819
Interest expense		(19,579	)		—		—			(19,579	)
Other		(890	)		—		—			(890	)
		(19,656	)		9		(3	)		(19,650	)
Income (loss) before income taxes and transaction expenses		166			572		(197	)		541
Income tax (expense) benefit		(6,000	)		—		(128	)(j)		(6,128	)
Income (loss) before transaction expenses		(5,834	)		572		(325	)		(5,587	)
Transaction expenses		—			—		3,000	(k)		3,000
Net income (loss) after transaction expenses	$	(5,834	)	$	572	$	(3,325	)	$	(8,587	)
Net income (loss) per common share outstanding— Basic:
Before transaction expenses	$	(58.34	)						$	(55.37	)
After transaction expenses	$	(58.34	)						$	(85.10	)
Weighted average common shares outstanding—Basic		100,000					901	(l)		100,901

See accompanying notes to unaudited pro forma financial information.

P-18

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA STATEMENT OF CASH FLOWS

Year ended December 31, 2001

(in thousands)

	Southwest Royalties, Inc. Historical			Partnership Historical		Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from operating activities
Net income (loss)	$	(5,834	)	$	572	$	(325	)(m)	$	(8,587	)
							(3,000	)(p)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		10,249			240		(69	)(m)		10,420
Noncash interest expense		1,662			—		—			1,662
Noncash reclassification of unrealized gain		(949	)		—		—			(949	)
Noncash loss on oil and gas commodity option contract		1,003			—		—			1,003
Gain on sale of assets		(15	)		—		—			(15	)
Bad debt expense		566			—		—			566
Deferred income taxes		6,000			—		128	(o)		6,128
Changes in operating assets and liabilities—
Accounts receivable		2,915			282		1	(n)		3,198
Other current assets		2,817			—		—			2,817
Accounts payable and accrued expenses		(2,454	)		—		(158	)(n)		388
							3,000	(p)
Accrued interest payable		(82	)		—		—			(82	)
Restricted cash		119			—		—			119
Net cash provided by (used in) operating activities		15,997			1,094		(423	)		16,668
Cash flows from investing activities
Proceeds from sale of oil and gas properties		65			—		—			65
Investment in oil and gas properties		(23,918	)		—		(81	)(m)		(23,999	)
Proceeds from sale of other property and equipment		18			—		—			18
Purchase of other property and equipment		(320	)		—		—			(320	)
Proceeds from sale of other assets		20			—		—			20
Purchase of other assets		(605	)		—		—			(605	)
Other		32			—		—			32
Net cash used in investing activities		(24,708	)		—		(81	)		(24,789	)

(continued)

See accompanying notes to unaudited pro forma financial information.

P-19

SOUTHWEST ROYALTIES, INC. AND SUBSIDIARIES

UNAUDITED MINIMUM PRO FORMA STATEMENT OF CASH FLOWS—(Continued)

Year ended December 31, 2001

(in thousands)

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
Cash flows from financing activities
Distribution to partners	$	—		$	(1,126	)	$	388	(m)	$	(738	)
Proceeds from borrowings		178			—			—			178
Payments on debt		(155	)		—			—			(155	)
Change in other long-term liabilities		(222	)		—			—			(222	)
Deferred debt costs		(216	)		—			—			(216	)
Other		—			—			(3	)(m)		(3	)
Net cash provided by (used in) financing activities		(415	)		(1,126	)		385			(1,156	)
Net decrease in unrestricted cash and cash equivalents		(9,126	)		(32	)		(119	)		(9,277	)
Unrestricted cash and cash equivalents—
beginning of period		15,595			164			111			15,870
Unrestricted cash and cash equivalents—
end of period	$	6,469		$	132		$	(8	)	$	6,593
Non-cash investing and financing activities
Unrealized gain on oil and gas commodity option contracts—taken to other comprehensive income	$	1,030		$	—		$	—		$	1,030
Decrease in other long-term liabilities associated with deferred debt costs	$	(500	)	$	—		$	—		$	(500	)
Increase in accrued expenses associated with deferred debt costs	$	500		$	—		$	—		$	500
Supplemental disclosures of cash flow information Interest paid	$	17,999		$	—		$	—		$	17,999
Income taxes paid (received)	$	—		$	—		$	—		$	—

See accompanying notes to unaudited pro forma financial information.

P-20

NOTES TO UNAUDITED MINIMUM PRO FORMA FINANCIAL INFORMATION

June 30, 2002 and December 31, 2001

1.    Method of Accounting for the Combination Transaction

In presentation of the accompanying pro forma financial information, Southwest accounted for the combination transaction as a reorganization of entities under common control in a manner similar to a pooling of interests.

Following is a description of the individual columns included in these unaudited pro forma combined financial statements:

Southwest Royalties, Inc.—Represents the consolidated balance sheet as of June 30, 2002, and the consolidated statement of cash flow and consolidated statement of operations (exclusive of extraordinary items) of Southwest Royalties, Inc. and subsidiaries for the six months ended June 30, 2002 and for the year ended December 31, 2001, respectively.

Partnership—Represents the balance sheet of Income Fund VI as of June 30, 2002 and the statement of cash flows and the statement of operations of Income Fund VI for the six months ended June 30, 2002 and year ended December 31, 2001.

2.    Pro Forma Adjustments Related to the Combination Transaction

The unaudited pro forma balance sheet includes the following adjustments:

a)  This adjustment eliminates receivable and payable balances between Southwest and Income  Fund VI.

b)  This adjustment restates equity for current period and historical proportionate consolidation of Income Fund VI’s earnings and distributions to Southwest from Income Fund VI.

c)  This adjustment reclassifies the current period distributions in transit and the first quarter distributions paid from Income Fund VI to Southwest.

d)  This adjustment records the $3.0 million estimated transaction costs related to Southwest and Income Fund VI. The transaction costs relate primarily to legal, printing costs and accounting fees.

e)  This adjustment records the tax effect of the earnings and all pro forma adjustments of Income  Fund VI for the six months ended June 30, 2002 at a 34% statutory federal income tax rate.

f)  This adjustment records the $.01 par value of the 1,000,901 common shares of Southwest that will be outstanding after completing the combination transaction and reclassifies Income Fund VI’s equity to additional paid-in capital and accumulated deficit of Southwest.

g)  This adjustment decreases Southwest’s deferred income taxes for the tax effect of the differences between the financial carrying amounts and the tax bases of Income Fund VI’s assets and liabilities at June 30, 2002 using a statutory federal tax rate of 34%. Income Fund VI has not recorded deferred income taxes since any tax liabilities are the responsibility of the individual partners. The $327,000 has been excluded from the unaudited pro forma statements of operations as the amount will not recur and is directly attributable to the combination transaction. The deferred income taxes will be recorded as part of operations in the period in which the combination transaction is completed.

The unaudited pro forma statements of operations include the following adjustments:

h)  These adjustments eliminate duplicative amounts of Income Fund VI, which are also included in Southwest’s financial statements. Southwest manages and controls the operations of Income Fund VI and therefore consolidates their proportionate share of Income Fund VI’s revenues and expenses.

P-21

NOTES TO UNAUDITED MINIMUM PRO FORMA FINANCIAL INFORMATION—(Continued)

June 30, 2002 and December 31, 2001

i)  These adjustments eliminate oil and gas administrative overhead charged to Income Fund VI as working interests owners in wells operated by Southwest. The overhead charges are recorded by Southwest as a reduction of general and administrative expenses.

j)  This adjustment records the tax effect of Income Fund VI’s net income and all pro forma adjustments at a 34% statutory federal rate. The adjustment includes income taxes for the applicable periods for Income Fund VI for which no income taxes have been previously recorded.

k)  This adjustment records estimated transaction costs related to Southwest and Income Fund VI. Total combination transaction costs are expected to be $3.0 million and primarily relate to legal, printing costs and accounting fees.

l)  To adjust the weighted average shares outstanding for the combination of Income Fund VI.

The unaudited pro forma statements of cash flows include the following adjustments:

m)  These adjustments eliminate the cash flows of Income Fund VI, which are also included in Southwest’s financial statements. Southwest manages and controls the operation of Income Fund VI, and therefore consolidates their proportionate share of Income Fund VI’s cash flows.

n)  These adjustments reflect the net adjustments to the pro forma balance sheet and reflect pro forma adjustments affecting the reconciliation of net earnings to net cash provided by operating activities.

o)  This adjustment reflects the change in deferred income taxes, resulting from pro forma adjustments due to the calculation of income taxes for Income Fund VI. The adjustment includes income taxes for the applicable periods for Income Fund VI for which no income taxes have been previously recorded.

p)  This adjustment records estimated transaction costs related to Southwest and Income Fund VI. Total combination transaction costs are expected to be $3.0 million and primarily relate to legal, printing costs and accounting fees.

3.    Income Taxes

Southwest will account for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. In accordance therewith, Southwest will prepare separate tax calculations for each tax jurisdiction in which Southwest will be subject to income taxes. The amount of deferred income tax will be recorded on the balance sheet against accumulated deficit. The pro forma statements of income record the tax effect of Income Fund VI’s net income and all pro forma adjustments at a 34% statutory federal rate. The adjustment includes income taxes for the applicable periods for Income Fund VI for which no income taxes have been previously recorded. Accordingly, Southwest has recognized income tax expense in the accompanying unaudited pro forma combined statement of operations for the six months ended June 30, 2002 and for the year ended December 31, 2001.

4.    Pro Forma Outstanding Shares of Southwest

A total of 1,000,901 shares of Southwest common stock will be issued and outstanding after the combination transaction. The owners of Income Fund VI will receive shares of Southwest common stock in proportion to the “Merger Value” of Income Fund VI to the total Merger Value of Income Fund VI and Southwest combined. The Merger Value has been determined by Southwest and is based on a valuation of Income Fund VI’s oil and gas reserves and other assets and liabilities.

P-22

NOTES TO UNAUDITED MINIMUM PRO FORMA FINANCIAL INFORMATION—(Continued)

June 30, 2002 and December 31, 2001

5.    Pro Forma Information on Oil and Gas Operations

The pro forma reserve information set forth below assumes the combination transaction was completed on January 1, 2002. There are many uncertainties inherent in estimating reserve quantities, and in projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, estimates are subject to change as additional information becomes available.

Proved oil and natural gas reserves are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic conditions. Proved developed oil and natural gas reserves are those reserves expected to be recovered through existing equipment and operating methods.

All reserves are located in the United States.

Changes in Pro Forma Proved Reserves

	Southwest Royalties, Inc. Historical		Partnership Historical		Pro Forma Adjustments		Pro Forma
	(In thousands)
Oil (MBbls):
Proved reserves, December 31, 2001	19,937		138		(58	)	20,017
Purchase of minerals-in-place	265		—		—		265
Sales of minerals-in-place	(61	)	—		—		(61	)
Revisions of previous estimates	904		60		(25	)	939
Production	(561	)	(13	)	5		(569	)
Proved reserves, June 30, 2002	20,484		185		(78	)	20,591
Proved developed reserves, June 30, 2002	15,001		143		(60	)	15,084
Natural Gas (MMcf):
Proved reserves, December 31, 2001	74,783		5,368		(2,245	)	77,906
Purchase of minerals-in-place	2,893		—		—		2,893
Sales of minerals-in-place	(55	)	—		—		(55	)
Revisions of previous estimates	2,777		(273	)	114		2,618
Production	(2,381	)	(147	)	61		(2,467	)
Proved reserves, June 30, 2002	78,017		4,948		(2,070	)	80,895
Proved developed reserves, June 30, 2002	50,503		4,595		(1,922	)	53,176

P-23

NOTES TO UNAUDITED MINIMUM PRO FORMA FINANCIAL INFORMATION—(Continued)

June 30, 2002 and December 31, 2001

Pro Forma Standardized Measure of Discounted Future Net Cash Flows—June 30, 2002

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Pro Forma
	(In thousands)
Future cash inflows	$	745,262		$	19,211		$	(8,036	)	$	756,437
Future production and development costs		(307,955	)		(6,039	)		2,526			(311,468	)
Future net cash flows before income taxes		437,307			13,172			(5,510	)		444,969
Future income tax expense		(125,783	)		—			(2,605	)		(128,388	)
Future net cash flows		311,524			13,172			(8,115	)		316,581
10% annual discount for estimated timing of cash flows		(158,951	)		(7,219	)		3,020			(163,150	)
Standardized measure of discounted future net cash flows	$	152,573		$	5,953		$	(5,095	)	$	153,431

Pro Forma Changes in Standardized Measure of Discounted Future Net Cash Flows

	Southwest Royalties, Inc. Historical			Partnership Historical			Pro Forma Adjustments			Southwest Royalties, Inc. Pro Forma
	(In thousands)
Balance at December 31, 2001	$	118,066		$	4,531		$	(1,895	)	$	120,702
Sales of oil and gas produced, net of production costs		(11,721	)		(10	)		4			(11,727	)
Net change in sales prices net of production costs		66,050			1,459			(610	)		66,899
Extensions and discoveries, net of future production and development costs		—			—			—			—
Revisions to estimated future development costs		60			—			—			60
Purchases of minerals-in-place		4,759			—			—			4,759
Revisions of previous quantity estimates		10,218			86			(37	)		10,267
Accretion of discount		14,346			453			(189	)		14,610
Net change in income taxes		(40,562	)		—			(2,605	)		(43,167	)
Sales of minerals-in-place		(112	)		—			—			(112	)
Changes in production rates, timing and other		(8,531	)		(566	)		237			(8,860	)
Balance at June 30, 2002	$	152,573		$	5,953		$	(5,095	)	$	153,431

The pro forma adjustment to standardized measure and changes in standardized measure of discounted future net cash flows reflects the future income tax expense impact on Southwest’s standardized measure and changes in standardized measure of discounted future net cash flows using a federal tax rate of 34%. Future income tax expense has been excluded from Income Fund VI’s historical standardized measure and changes in standardized measure of discounted future net cash flows since any tax liabilities are the responsibility of the individual partners.

P-24

APPENDIX A

GENERAL INFORMATION RELATING TO EACH LIMITED PARTNERSHIP

TABLE 1

JURISDICTION OF ORGANIZATION, INITIAL SUBSCRIPTION PRICE FOR EACH UNIT, INITIAL INVESTMENT BY LIMITED PARTNERS AND NUMBER OF LIMITED PARTNERS

AS OF JUNE 30, 2002

PARTNERSHIP	JURISDICTION OF ORGANIZATION	INITIAL SUBSCRIPTION PRICE OF EACH UNIT	INITIAL INVESTMENT BY LIMITED PARTNERS	NUMBER OF LIMITED PARTNERS AS OF JUNE 30, 2002
Southwest Royalties, Inc. Income Fund V, L.P.	Tennessee	$1,000	$  7,499,139	559
Southwest Royalties, Inc. Income Fund VI, L.P.	Tennessee	$   500	$10,000,000	669
Southwest Oil & Gas Income Fund VII-A, L.P.	Delaware	$   500	$  7,500,000	566
Southwest Royalties Institutional Income Fund VII-B, L.P.	Delaware	$   500	$  7,500,000	718
Southeast Oil & Gas Income Fund VIII-A, L.P.	Delaware	$   500	$  6,798,000	518
Southwest Royalties Institutional Income Fund VIII-B, L.P.	Delaware	$   500	$  5,073,500	520
Southwest Oil & Gas Income Fund IX-A, L.P.	Delaware	$   500	$  5,226,500	562
Southwest Royalties Institutional Income Fund IX-B, L.P.	Delaware	$   500	$  4,891,000	610
Southwest Oil & Gas Income Fund X-A, L.P.	Delaware	$   500	$  5,242,000	569
Southwest Royalties Institutional Income Fund X-A, L.P.	Delaware	$   500	$  5,658,000	580
Southwest Oil & Gas Income Fund X-B, L.P.	Delaware	$   500	$  5,444,500	527
Southwest Royalties Institutional Income Fund X-B, L.P.	Delaware	$   500	$  5,590,500	593
Southwest Oil & Gas Income Fund X-C, L.P.	Delaware	$   500	$  3,123,000	291
Southwest Royalties Institutional Income Fund X-C, L.P.	Delaware	$   500	$  2,991,500	334
Southwest Developmental Drilling Fund 91-A, L.P.	Delaware	$1,000	$  1,144,500	102
Southwest Developmental Drilling Fund 92-A, L.P.	Delaware	$    1,000	$1,407,000	105
Southwest Partners, L.P.	Delaware	$100,000	$4,350,000	84
Southwest Combination Income/Drilling Program 1988, L.P.	Delaware	$       500	$1,754,500	174
Southwest Developmental Drilling Fund 1990, L.P.	Delaware	$  10,000	$1,735,000	94
Southwest Developmental Drilling Fund 1993, L.P.	Delaware	$    1,000	$2,078,000	102
Southwest Developmental Drilling Fund 1994, L.P.	Delaware	$    1,000	$2,235,000	113
TOTAL				8,390

A-1

TABLE 2

AGGREGATE MERGER VALUE ATTRIBUTABLE

TO SOUTHWEST ROYALTIES, INC.

AND TO THE LIMITED PARTNERS (IN THOUSANDS) ($)

PARTNERSHIP	SOUTHWEST ROYALTIES, INC.’S GENERAL PARTNER INTEREST		SOUTHWEST ROYALTIES, INC.’S LIMITED PARTNER INTERESTS		ALL OTHER LIMITED PARTNERS		TOTAL
Southwest Royalties, Inc. Income Fund V, L.P.	$	96	$	329	$	538	$	963
Southwest Royalties, Inc. Income Fund VI, L.P.	$	588	$	1,872	$	3,422	$	5,882
Southwest Oil & Gas Income Fund VII-A, L.P.	$	237	$	668	$	1,468	$	2,373
Southwest Royalties Institutional Income Fund VII-B, L.P.	$	398	$	1,043	$	2,539	$	3,980
Southeast Oil & Gas Income Fund VIII-A, L.P.	$	221	$	481	$	1,505	$	2,207
Southwest Royalties Institutional Income Fund VIII-B, L.P.	$	236	$	445	$	1,682	$	2,363
Southwest Oil & Gas Income Fund IX-A, L.P.	$	250	$	97	$	2,152	$	2,499
Southwest Royalties Institutional Income Fund IX-B, L.P.	$	234	$	69	$	2,039	$	2,342
Southwest Oil & Gas Income Fund X-A, L.P.	$	71	$	10	$	626	$	707
Southwest Royalties Institutional Income Fund X-A, L.P.	$	139	$	31	$	1,219	$	1,389
Southwest Oil & Gas Income Fund X-B, L.P.	$	114	$	19	$	1,006	$	1,139
Southwest Royalties Institutional Income Fund X-B, L.P.	$	160	$	64	$	1,375	$	1,599
Southwest Oil & Gas Income Fund X-C, L.P.	$	83	$	25	$	721	$	829
Southwest Royalties Institutional Income Fund X-C, L.P.	$	68	$	11	$	598	$	677
Southwest Developmental Drilling Fund 91-A, L.P.	$	23	$	4	$	184	$	211
Southwest Developmental Drilling Fund 92-A, L.P.	$	89	$	3	$	718	$	810
Southwest Partners, L.P.	$	1,499	$	440	$	8,057	$	9,996
Southwest Combination Income/Drilling Program 1988, L.P.	$	12	$	3	$	64	$	79
Southwest Developmental Drilling Fund 1990, L.P.	$	80	$	—	$	454	$	534
Southwest Developmental Drilling Fund 1993, L.P.	$	139	$	2	$	1,122	$	1,263
Southwest Developmental Drilling Fund 1994, L.P.	$	64	$	—	$	515	$	579

A-2

TABLE 3

MERGER VALUE ATTRIBUTABLE TO PARTNERSHIP INTERESTS

OF LIMITED PARTNERS PER $500 INVESTMENT

PARTNERSHIP	MERGER VALUE PER $500 LIMITED PARTNER INVESTMENT AS OF JUNE 30, 2002
Southwest Royalties, Inc. Income Fund V, L.P.	$  57.79
Southwest Royalties, Inc. Income Fund VI, L.P.	$264.71
Southwest Oil & Gas Income Fund VII-A, L.P.	$142.38
Southwest Royalties Institutional Income Fund VII-B, L.P.	$238.84
Southeast Oil & Gas Income Fund VIII-A, L.P.	$146.09
Southwest Royalties Institutional Income Fund VIII-B, L.P.	$209.65
Southwest Oil & Gas Income Fund IX-A, L.P.	$215.15
Southwest Royalties Institutional Income Fund IX-B, L.P.	$215.49
Southwest Oil & Gas Income Fund X-A, L.P.	$  60.72
Southwest Royalties Institutional Income Fund X-A, L.P.	$110.48
Southwest Oil & Gas Income Fund X-B, L.P.	$  94.18
Southwest Royalties Institutional Income Fund X-B, L.P.	$128.69
Southwest Oil & Gas Income Fund X-C, L.P.	$119.52
Southwest Royalties Institutional Income Fund X-C, L.P.	$101.79
Southwest Developmental Drilling Fund 91-A, L.P.	$  81.81
Southwest Developmental Drilling Fund 92-A, L.P.	$256.10
Southwest Partners, L.P.	$976.64
Southwest Combination Income/Drilling Program 1988, L.P.	$  19.01
Southwest Developmental Drilling Fund 1990, L.P.	$130.77
Southwest Developmental Drilling Fund 1993, L.P.	$270.45
Southwest Developmental Drilling Fund 1994, L.P.	$115.16

A-3

TABLE 4

OWNERSHIP PERCENTAGE OF SOUTHWEST’S GENERAL PARTNER INTEREST OF EACH PARTNERSHIP AND VOTING PERCENTAGE OF SOUTHWEST IN ITS CAPACITY

AS A LIMITED PARTNER OF EACH PARTNERSHIP AS OF JUNE 30, 2002

PARTNERSHIP	OWNERSHIP PERCENTAGE OF SOUTHWEST ROYALTIES, INC. (as General Partner)		SOUTHWEST ROYALTIES, INC. VOTING PERCENTAGE (as a Limited Partner)
Southwest Royalties, Inc. Income Fund V, L.P.	10	%	34.18	%
Southwest Royalties, Inc. Income Fund VI, L.P.	10	%	31.83	%
Southwest Oil & Gas Income Fund VII-A, L.P.	10	%	28.12	%
Southwest Royalties Institutional Income Fund VII-B, L.P.	10	%	26.21	%
Southeast Oil & Gas Income Fund VIII-A, L.P.	10	%	21.81	%
Southwest Royalties Institutional Income Fund VIII-B, L.P.	10	%	18.83	%
Southwest Oil & Gas Income Fund IX-A, L.P.	10	%(1)	3.90	%
Southwest Royalties Institutional Income Fund IX-B, L.P.	10	%(1)	2.93	%
Southwest Oil & Gas Income Fund X-A, L.P.	10	%(1)	1.47	%
Southwest Royalties Institutional Income Fund X-A, L.P.	10	%(1)	2.20	%
Southwest Oil & Gas Income Fund X-B, L.P.	10	%(1)	1.69	%
Southwest Royalties Institutional Income Fund X-B, L.P.	10	%(1)	3.99	%
Southwest Oil & Gas Income Fund X-C, L.P.	10	%(1)	3.05	%
Southwest Royalties Institutional Income Fund X-C, L.P.	10	%(1)	1.57	%
Southwest Developmental Drilling Fund 91-A, L.P.	11	%	1.71	%
Southwest Developmental Drilling Fund 92-A, L.P.	11	%	0.32	%
Southwest Partners, L.P.	15	%	4.40	%
Southwest Combination Income/Drilling Program 1988, L.P.	15	%(1)	3.68	%
Southwest Developmental Drilling Fund 1990, L.P.	15	%	0.00	%
Southwest Developmental Drilling Fund 1993, L.P.	11	%	0.13	%
Southwest Developmental Drilling Fund 1994, L.P.	11	%	0.00	%

⁽¹⁾ Immediately prior to the merger, H.H. Wommack, III will transfer his 1% general partner interest, which he holds pursuant to his position as an additional general partner, to Southwest. Southwest’s general partner ownership percentage includes Mr. Wommack’s general partner ownership percentage.

A-4

TABLE 5

HISTORICAL QUARTERLY PARTNERSHIP DISTRIBUTIONS TO THE LIMITED PARTNERS

PER $500 INVESTMENT

FROM INCEPTION THROUGH JUNE 30, 2002

	QUARTERLY DISTRIBUTIONS TO LIMITED PARTNERS PER $500 INVESTMENT (A)
	INCEPTION TO 12/31/99	QUARTER ENDED 3/31/00	QUARTER ENDED 6/30/00	QUARTER ENDED 9/30/00	QUARTER ENDED 12/31/00	QUARTER ENDED 3/31/01	QUARTER ENDED 6/30/01
Southwest Royalties, Inc. Income Fund V, L.P.	442.28	3.00	3.00	3.90	5.10	7.50	6.00
Southwest Royalties, Inc. Income Fund VI, L.P.	682.59	10.13	11.25	15.75	15.75	18.12	18.00
Southwest Oil & Gas Income Fund VII-A, L.P.	597.84	5.10	6.00	7.50	7.50	9.00	7.50
Southwest Royalties Institutional Income Fund VII-B, L.P.	569.82	5.10	6.00	12.00	12.13	15.00	13.50
Southwest Oil & Gas Income Fund VIII-A, L.P.	478.81	6.62	7.94	11.25	14.92	18.20	9.93
Southwest Royalties Institutional Income Fund VIII-B, L.P.	513.05	8.87	11.09	17.74	19.98	22.17	11.53
Southwest Oil & Gas Income Fund IX-A, L.P.	537.61	9.84	10.76	15.07	18.33	20.23	17.22
Southwest Royalties Institutional Income Fund IX-B, L.P.	544.13	10.86	11.50	16.10	16.80	18.40	13.80
Southwest Oil & Gas Income Fund X-A, L.P.	236.06	—	—	2.51	4.53	3.86	1.29
Southwest Royalties Institutional Income Fund X-A, L.P.	245.51	4.42	1.77	2.96	4.04	7.95	5.17
Southwest Oil & Gas Income Fund X-B, L.P.	386.29	6.20	6.61	8.27	12.53	12.56	8.27
Southwest Royalties Institutional Income Fund X-B, L.P.	393.31	4.43	3.22	5.63	8.99	10.06	8.05
Southwest Oil & Gas Income Fund X-C, L.P.	440.63	7.20	7.20	11.53	14.02	18.01	14.41
Southwest Royalties Institutional Income Fund X-C, L.P.	400.47	8.27	8.27	12.03	14.45	18.05	15.04

A-5

	QUARTERLY DISTRIBUTIONS TO LIMITED PARTNERS PER $500 INVESTMENT (A)
	INCEPTION TO 12/31/99	QUARTER ENDED 3/31/00	QUARTER ENDED 6/30/00	QUARTER ENDED 9/30/00	QUARTER ENDED 12/31/00	QUARTER ENDED 3/31/01	QUARTER ENDED 6/30/01
Southwest Developmental Drilling Fund 91-A, L.P.	472.37	15.55	11.66	11.66	8.18	11.66	4.86
Southwest Developmental Drilling Fund 92-A, L.P.	364.77	12.65	15.81	18.98	23.61	25.30	15.81
Southwest Partners, L.P.	0.71	—	—	12.21	12.77	12.21	—
Southwest Combination Income/Drilling Program 1988, L.P.	251.72	—	—	—	0.03	—	1.21
Southwest Developmental Drilling Fund 1990, L.P.	257.31	2.57	2.69	4.90	4.90	—	3.67
Southwest Developmental Drilling Fund 1993, L.P.	357.54	14.99	14.99	19.27	24.91	25.70	16.06
Southwest Developmental Drilling Fund 1994, L.P.	66.91	5.97	5.97	7.96	9.86	9.96	7.47

	QUARTERLY DISTRIBUTIONS TO LIMITED PARTNERS PER $500 INVESTMENT (A)
	QUARTER ENDED 9/30/01	QUARTER ENDED 12/31/01	QUARTER ENDED 3/31/02	QUARTER ENDED 6/30/02	INCEPTION TO 6/30/02
Southwest Royalties, Inc. Income Fund V, L.P.	—	—	—	—	470.78
Southwest Royalties, Inc. Income Fund VI, L.P.	10.13	4.50	—	—	786.21
Southwest Oil & Gas Income Fund VII-A, L.P.	6.00	3.03	2.64	5.40	657.51
Southwest Royalties Institutional Income Fund VII-B, L.P.	9.00	6.10	9.00	9.00	666.65
Southwest Oil & Gas Income Fund VIII-A, L.P.	7.94	4.97	2.12	—	562.72
Southwest Royalties Institutional Income Fund VIII-B, L.P.	13.30	8.01	6.21	3.10	635.05
Southwest Oil & Gas Income Fund IX-A, L.P.	10.76	7.42	4.30	4.30	655.86
Southwest Royalties Institutional Income Fund IX-B, L.P.	11.50	6.21	4.60	4.14	658.04
Southwest Oil & Gas Income Fund X-A, L.P.	—	—	—	—	248.24
Southwest Royalties Institutional Income Fund X-A, L.P.	2.78	0.01	—	—	274.61
Southwest Oil & Gas Income Fund X-B, L.P.	6.20	4.33	—	—	451.26
Southwest Royalties Institutional Income Fund X-B, L.P.	8.05	6.18	4.02	—	451.95
Southwest Oil & Gas Income Fund X-C, L.P.	14.41	5.26	—	—	532.67
Southwest Royalties Institutional Income Fund X-C, L.P.	13.54	3.10	—	—	493.23
Southwest Developmental Drilling Fund 91-A, L.P.	3.50	4.17	—	3.89	547.51
Southwest Developmental Drilling Fund 92-A, L.P.	15.81	9.11	9.49	9.49	520.84
Southwest Partners, L.P.	—	0.22	—	—	38.12
Southwest Combination Income/Drilling Program 1988, L.P.	1.45	—	—	—	254.42
Southwest Developmental Drilling Fund 1990, L.P.	3.18	1.96	2.20	2.20	285.61
Southwest Developmental Drilling Fund 1993, L.P.	16.06	13.27	10.71	10.71	524.21
Southwest Developmental Drilling Fund 1994, L.P.	3.98	3.55	3.98	2.79	128.41

(a) Past cash distributions to limited partners are not necessarily indicative of future cash distributions. Limited partners should not assume that any nonparticipating partnership will continue to make cash distributions at levels similar to those shown above. See “RISK FACTORS—Risks of Participating in the Merger.”

A-6

APPENDIX B-1

February 19, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 650 reserve determinations and are located in the states of Alabama, Kansas, Louisiana, Montana, North Dakota, New Mexico, Oklahoma, Texas and Wyoming.

The net reserves attributable to the properties that we reviewed account for 94.4 percent of the total net remaining liquid hydrocarbon reserves and 89.1 percent of the total net remaining gas reserves. The properties that we reviewed represent 94.8 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to Southwest Royalties’ interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

Southwest Royalties, Inc.

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		12,276,930		1,501,471		5,017,051		18,795,452
Plant Products—Barrels		445,936		0		0		445,936
Gas—MMCF		39,384		5,249		19,587		64,220
Income Data
Future Gross Revenue	$	309,693,000	$	38,190,870	$	128,797,900	$	476,681,770
Deductions		139,755,500		10,663,020		56,624,010		207,042,530
Future Net Income (FNI)	$	169,937,500	$	27,527,850	$	72,173,890	$	269,639,240
Discounted FNI @ 10%	$	88,849,020	$	15,648,470	$	31,555,710	$	136,053,200

The sum of the producing, non-producing and undeveloped proved categories shown above may differ from the cashflow summary due to rounding characteristics of the ARIES program.

Southwest Royalties, Inc.

February 19, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		415,666		80,278		645,997		1,141,941
Plant Products—Barrels		0		0		0		0
Gas—MMCF		2,207		736		4,945		7,888
Income Data
Future Gross Revenue	$	11,131,590	$	3,059,419	$	21,924,670	$	36,115,679
Deductions		6,187,659		1,478,395		12,946,250		20,612,304
Future Net Income (FNI)	$	4,943,931	$	1,581,024	$	8,978,420	$	15,503,375
Discounted FNI @10%	$	3,129,032	$	860,775	$	3,412,285	$	7,402,092
Total Net Reserves
Oil/Condensate—Barrels		12,692,596		1,581,749		5,663,048		19,937,393
Plant Products—Barrels		445,936		0		0		445,936
Gas—MMCF		41,591		5,985		24,532		72,108
Income Data
Future Gross Revenue	$	320,824,590	$	41,250,289	$	150,722,570	$	512,797,449
Deductions		145,943,159		12,141,415		69,570,260		227,654,834
Future Net Income (FNI)	$	174,881,431	$	29,108,874	$	81,152,310	$	285,142,615
Discounted FNI @10%	$	91,978,052	$	16,509,245	$	34,967,995	$	143,455,292

The sum of the producing, non-producing and undeveloped proved categories shown above may differ from the cashflow summary due to rounding characteristics of the ARIES program.

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

February 19, 2002

Page 3

(B) the immediately adjoining not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.     Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.     Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

February 19, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interest owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in the evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

February 19, 2002

Page 5

estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by Southwest Royalties.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of Southwest Royalties which we did not review. The reserves attributable to the other properties account for 5.6 percent of the total net remaining liquid hydrocarbon reserves and 10.9 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

February 19, 2002

Page 6

This report was prepared for the exclusive use of Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

/s/    LARRY P. CONNOR

Larry P. Connor, P.E.

Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	657.
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:06

REVIEWED BY RYDER SCOTT

TOTAL PROVED

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	151460.100
FINAL								10.0000	136053.100
								12.0000	123330.000.
								15.0000	107930.300.
								20.0000	88944.820.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas     MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbls	Gas $/MCF
12-02	2147.	8283605.	750433.	48836690.	1237435.	23065.	5989018.	18.34	2.47
12-03	2255.	8463282.	688159.	47525060.	1453080.	21799.	6931659.	18.36	2.45
12-04	2239.	8047118.	632552.	41970170.	1599886.	20634.	5852885.	18.32	2.42
12-05	1927.	7138922.	582819.	36836800.	1488612.	19559.	4959825.	18.31	2.39
12-06	1886.	6500326.	538263.	32940540.	1305522.	18564.	4106558.	18.32	2.39
12-07	1853.	5979513.	498273.	29974220.	1167058.	17643.	3516290.	18.33	2.38
12-08	1798.	5524705.	462314.	27299160.	1048627.	16786.	3047630.	18.36	2.37
12-09	1663.	5078820.	429915.	24735970.	923687.	15989.	2692910.	18.47	2.37
12-10	1595.	4747426.	400665.	22842430.	850376.	15245.	2430074.	18.49	2.37
12-11	1507.	4416750.	374201.	21143440.	779215.	14550.	2181907.	18.50	2.36
12-12	1481.	4133651.	350207.	19554720.	719265.	13898.	1943423.	18.51	2.34
12-13	1384.	3788009.	328402.	18046770.	657479.	13286.	1746067.	18.55	2.33
12-14	1340.	3525870.	308541.	16717540.	606081.	12711.	1594663.	18.56	2.32
12-15	1308.	3294824.	290410.	15552010.	556201.	12169.	1441669.	18.59	2.32
12-16	1263.	3036096.	273819.	14501540.	479730.	11657.	1318024.	18.61	2.31
Sub	1710.	81958910.	6908973.	418477100.	14872250.	247555.	49752600.	18.41	2.39
Remain	338.	36862630.	3991552.	206227800.	3923202.	198381.	14467580.	18.73	2.29
Total	641.	118821500.	10900520.	624704800.	18795450.	445936.	64220180.	18.47	2.37
Cumulative		434619000.	0.	1595882000.
Ultimate		553440600.	10900520.	2220586000.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	22700020.	320145.	14815950.	0.	37836130.	1134947.	1106985.	35594200.
12-03	26678830.	302572.	16948150.	0.	43929560.	1341174.	1267157.	41321220.
12-04	29308320.	286396.	14141560.	0.	43736280.	1467389.	1059083.	41209820.
12-05	27250420.	271473.	11864210.	0.	39386100.	1374005.	889337.	37122760.
12-06	23915510.	257672.	9795160.	0.	33968340.	1207768.	733463.	32027100.
12-07	21393190.	244880.	8356834.	0.	29994900.	1081564.	625490.	28287850.
12-08	19255710.	232995.	7229319.	0.	26718030.	974668.	541238.	25202110.
12-09	17064270.	221930.	6394509.	0.	23680710.	855932.	478711.	22346070.
12-10	15725550.	211605.	5749903.	0.	21687040.	786990.	430981.	20469080.
12-11	14414190.	201950.	5143377.	0.	19759520.	720264.	385570.	18653680.
12-12	13313760.	192904.	4554850.	0.	18061510.	664987.	341496.	17055030.
12-13	12198310.	184412.	4068441.	0.	16451160.	607656.	304569.	15538930.
12-14	11249880.	176425.	3703693.	0.	15130000.	560215.	277189.	14292600.
12-15	10341190.	168900.	3341311.	0.	13851400.	514998.	250083.	13086320.
12-16	8929877.	161799.	3046968.	0.	12138650.	447267.	228118.	11463260.
Sub	273739000.	3436058.	119154200.	0.	396329300.	13739820.	8919468.	373670100.
Remain	73483620.	2753534.	33063080.	0.	109300200.	3804613.	2483957.	103011700.
Total	347222700.	6189592.	152217300.	0.	505629600.	17544440.	11403420.	476681800.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	8279987.	946571.	15003120.	0.	24229670.	11364520.	11364520.	10601290.
12-03	8805750.	1088917.	10912150.	0.	20806810.	20514410.	31878930.	17561060.
12-04	8812456.	1091306.	11839660.	0.	21743420.	19466400.	51345330.	15192310.
12-05	8451720.	977142.	0.	0.	9428862.	27693900.	79039230.	19878490.
12-06	8298142.	842136.	8858.	0.	9149136.	22877970.	101917200.	14924260.
12-07	8026266.	742633.	0.	0.	8768898.	19518950.	121436200.	11573840.
12-08	7721022.	659354.	0.	0.	8380376.	16821740.	138257900.	9067326.
12-09	6942831.	590888.	0.	0.	7533719.	14812350.	153070200.	7256548.
12-10	6709278.	544360.	0.	0.	7253638.	13215440.	166285700.	5885636.
12-11	6429172.	498759.	0.	0.	6927931.	11725750.	178011400.	4747901.
12-12	6239606.	456359.	0.	0.	6695965.	10359060.	188370500.	3812901.
12-13	5929176.	418206.	8858.	0.	6356240.	9182689.	197553200.	3072799.
12-14	5772009.	384882.	0.	0.	6156891.	8135705.	205688900.	2474938.
12-15	5557704.	352180.	0.	0.	5909884.	7176436.	212865300.	1984656.
12-16	5057455.	306593.	0.	0.	5364048.	6099209.	218964500.	1533762.
Sub	107032600.	9900284.	37772640.	0.	154705500.	218964500.	218964500.	129567700.
Remain	49681340.	2646864.	8858.	0.	52337060.	50674600.	269639100.	6485472.
Total	156713900.	12547150.	37781500.	0.	207042600.	269639100.	269639100.	136053200.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	422.
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:20:49

REVIEWED BY RYDER SCOTT

PROVED PRODUCING

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	97751.850
FINAL								10.0000	88848.960
								12.0000	81581.300.
								15.0000	72876.180.
								20.0000	62251.550.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	2079.	7741627.	750433.	44700760.	1007944.	23065.	3932376.	18.32	2.40
12-03	2077.	7183517.	688159.	40077180.	936621.	21799.	3300935.	18.32	2.39
12-04	1984.	6459629.	632552.	35699630.	859849.	20634.	2807120.	18.37	2.39
12-05	1662.	5694954.	582819.	31774420.	787185.	19559.	2460644.	18.45	2.37
12-06	1626.	5326639.	538263.	29023890.	739974.	18564.	2175235.	18.46	2.36
12-07	1596.	4995326.	498273.	26758950.	693628.	17643.	1941469.	18.47	2.35
12-08	1545.	4684149.	462314.	24627730.	643642.	16786.	1757091.	18.52	2.35
12-09	1416.	4345569.	429915.	22429590.	568782.	15989.	1576347.	18.71	2.36
12-10	1354.	4100145.	400665.	20867730.	533996.	15245.	1444355.	18.73	2.36
12-11	1280.	3852380.	374201.	19448300.	500010.	14550.	1333713.	18.75	2.35
12-12	1264.	3638422.	350207.	18133230.	473781.	13898.	1227522.	18.75	2.35
12-13	1185.	3339529.	328402.	16785840.	440982.	13286.	1122852.	18.79	2.34
12-14	1150.	3138755.	308541.	15595900.	417178.	12711.	1043357.	18.80	2.34
12-15	1129.	2961131.	290410.	14582790.	391772.	12169.	962314.	18.82	2.34
12-16	1099.	2781631.	273819.	13633720.	353419.	11657.	887420.	18.82	2.34
Sub	1496.	70243400.	6908973.	374139600.	9348765.	247555.	27972750.	18.55	2.37
Remain	309.	35217110.	3991552.	200296600.	2928169.	198381.	11410860.	19.11	2.30
Total	571.	105460500.	10900520.	574436200.	12276930.	445936.	39383610.	18.68	2.35
Cumulative		434578300.	0.	1594833000.
Ultimate		540038800.	10900520.	2169269000.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	18464510.	320145.	9449691.	0.	28234370.	930081.	704263.	26600020.
12-03	17160370.	302572.	7879865.	0.	25342820.	863619.	587517.	23891670.
12-04	15793240.	286396.	6696110.	0.	22775750.	795096.	499382.	21481280.
12-05	14520720.	271473.	5843806.	0.	20636000.	731978.	436042.	19467970.
12-06	13656720.	257672.	5138154.	0.	19052550.	687697.	382509.	17982340.
12-07	12811510.	244880.	4566027.	0.	17622410.	644767.	339767.	16637880.
12-08	11920850.	232995.	4131341.	0.	16285190.	600324.	307691.	15377170.
12-09	10642590.	221930.	3724583.	0.	14589110.	527797.	277439.	13783880.
12-10	10002860.	211605.	3402954.	0.	13617400.	494076.	253937.	12869400.
12-11	9374195.	201950.	3137702.	0.	12713850.	461956.	234414.	12017480.
12-12	8884373.	192904.	2878676.	0.	11955950.	437136.	215149.	11303670.
12-13	8287469.	184412.	2624777.	0.	11096660.	404309.	195678.	10496670.
12-14	7841470.	176425.	2437575.	0.	10455470.	381959.	181689.	9891821.
12-15	7373914.	168900.	2252138.	0.	9794951.	358448.	167907.	9268598.
12-16	6650491.	161799.	2078607.	0.	8890899.	323769.	155058.	8412068.
Sub	173385300.	3436058.	66242000.	0.	243063400.	8643010.	4938442.	229481900.
Remain	55944550.	2753534.	26202090.	0.	84900170.	2723061.	1966073.	80211040.
Total	229329900.	6189592.	92444100.	0.	327963600.	11366070.	6904515.	309693000.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END-     MO-YR						Annual $	Cumulative $
12-02	7962400.	685450.	0.	0.	8647850.	17952160.	17952160.	17148330.
12-03	7922142.	616542.	0.	0.	8538683.	15352990.	33305160.	13327060.
12-04	7422838.	554540.	0.	0.	7977378.	13503900.	46809060.	10655010.
12-05	6933649.	503193.	0.	0.	7436842.	12031130.	58840190.	8629322.
12-06	6812765.	467155.	0.	0.	7279919.	10702430.	69542620.	6978219.
12-07	6564746.	433043.	0.	0.	6997789.	9640093.	79182710.	5713966.
12-08	6302268.	399243.	0.	0.	6701511.	8675667.	87858380.	4675118.
12-09	5584339.	364348.	0.	0.	5948687.	7835187.	95693560.	3837903.
12-10	5408733.	343214.	0.	0.	5751947.	7117449.	102811000.	3169421.
12-11	5226988.	322873.	0.	0.	5549861.	6467616.	109278600.	2618217.
12-12	5130367.	304831.	0.	0.	5435198.	5868468.	115147100.	2159750.
12-13	4901606.	287377.	0.	0.	5188983.	5307684.	120454800.	1775785.
12-14	4819276.	271490.	0.	0.	5090767.	4801055.	125255800.	1460295.
12-15	4683419.	254985.	0.	0.	4938405.	4330193.	129586000.	1197364.
12-16	4288207.	231100.	0.	0.	4519307.	3892760.	133478800.	978574.
Sub	89963740.	6039384.	0.	0.	96003140.	133478800.	133478800.	84324340.
Remain	41564440.	2187958.	0.	0.	43752400.	36458640.	169937400.	4524678.
Total	131528200.	8227342.	0.	0.	139755500.	169937400.	169937400.	88849020.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	510.
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:20:56

REVIEWED BY RYDER SCOTT

PROVED NON-PRODUCING

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	17261.130
FINAL								10.0000	15648.470
								12.0000	14265.570.
								15.0000	12528.420.
								20.0000	10287.740.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	33.	157417.	0.	571203.	87637.	0.	224396.	19.23	2.09
12-03	87.	406250.	0.	2199352.	211640.	0.	873616.	18.63	2.41
12-04	102.	379583.	0.	1810584.	208040.	0.	728647.	18.54	2.40
12-05	102.	302410.	0.	1321401.	171448.	0.	555964.	18.59	2.38
12-06	99.	237354.	0.	1011146.	137822.	0.	440577.	18.64	2.37
12-07	97.	190486.	0.	819930.	112924.	0.	362740.	18.67	2.36
12-08	94.	153074.	0.	663330.	92142.	0.	296599.	18.70	2.36
12-09	90.	122189.	0.	536378.	74587.	0.	242324.	18.74	2.35
12-10	86.	98680.	0.	397315.	61840.	0.	206451.	18.81	2.34
12-11	78.	79162.	0.	314724.	51794.	0.	166913.	18.81	2.35
12-12	74.	68980.	0.	281639.	44634.	0.	149515.	18.87	2.35
12-13	65.	75509.	0.	267955.	40403.	0.	137696.	19.03	2.38
12-14	63.	59224.	0.	236349.	34874.	0.	124301.	19.10	2.37
12-15	59.	48588.	0.	212766.	29299.	0.	113346.	19.25	2.36
12-16	58.	43933.	0.	191742.	27226.	0.	103736.	19.24	2.36
Sub	79.	2422840.	0.	10835810.	1386308.	0.	4726820.	18.74	2.36
Remain	20.	192453.	0.	1096606.	115162.	0.	522470.	19.41	2.18
Total	45.	2615293.	0.	11932420.	1501471.	0.	5249290.	18.79	2.35
Cumulative		195.	0.	219030.
Ultimate		2615488.	0.	12151450.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	1685564.	0.	469594.	0.	2155158.	85844.	35372.	2033942.
12-03	3943742.	0.	2104731.	0.	6048473.	202753.	155840.	5689881.
12-04	3856642.	0.	1746287.	0.	5602929.	197400.	130779.	5274750.
12-05	3187793.	0.	1322643.	0.	4510437.	163276.	99664.	4247497.
12-06	2568329.	0.	1043668.	0.	3611996.	130512.	78872.	3402613.
12-07	2108026.	0.	857518.	0.	2965545.	106111.	64782.	2794651.
12-08	1722994.	0.	698620.	0.	2421614.	85623.	52754.	2283237.
12-09	1397750.	0.	568298.	0.	1966047.	68478.	42893.	1854676.
12-10	1163403.	0.	483182.	0.	1646585.	56579.	36595.	1553410.
12-11	974401.	0.	391709.	0.	1366110.	46644.	29550.	1289916.
12-12	842250.	0.	351965.	0.	1194215.	39683.	26525.	1128007.
12-13	769050.	0.	328392.	0.	1097442.	36979.	24775.	1035687.
12-14	666020.	0.	294406.	0.	960426.	31485.	22186.	906755.
12-15	563900.	0.	267803.	0.	831704.	26515.	20168.	785020.
12-16	523921.	0.	245263.	0.	769174.	24531.	18456.	726188.
Sub	25973770.	0.	11174080.	0.	37147850.	1302412.	839212.	35006230.
Remain	2235104.	0.	1141376.	0.	3376480.	105954.	85880.	3184646.
Total	28208880.	0.	12315460.	0.	40524330.	1408366.	925092.	38190870.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	87757.	54020.	2974763.	0.	3116540.	-1082598.	-1082598.	-1094829.
12-03	306966.	140060.	1965713.	0.	2412739.	3277143.	2194545.	2783427.
12-04	389553.	132334.	200877.	0.	722764.	4551986.	6746530.	3590827.
12-05	390674.	107369.	0.	0.	498044.	3749453.	10495980.	2692277.
12-06	371896.	87443.	8858.	0.	468198.	2934415.	13430400.	1915110.
12-07	358881.	72900.	0.	0.	431781.	2362870.	15793270.	1401611.
12-08	331069.	60653.	0.	0.	391722.	1891515.	17684780.	1020573.
12-09	272338.	50231.	0.	0.	322569.	1532107.	19216890.	750897.
12-10	230074.	42829.	0.	0.	272903.	1280508.	20497400.	570594.
12-11	190498.	36653.	0.	0.	227151.	1062765.	21560170.	430431.
12-12	172908.	32642.	0.	0.	205550.	922456.	22482620.	339632.
12-13	158740.	29292.	8858.	0.	196891.	838797.	23321420.	280618.
12-14	146116.	26157.	0.	0.	172273.	734482.	24055900.	223555.
12-15	135297.	22798.	0.	0.	158095.	626925.	24682820.	173349.
12-16	133931.	21227.	0.	0.	155157.	571030.	25253850.	143530.
Sub	3676700.	916609.	5159069.	0.	9752376.	25253850.	25253850.	15221600.
Remain	809701.	92088.	8858.	0.	910647.	2273999.	27527850.	426868.
Total	4486401.	1008697.	5167927.	0.	10663020.	27527850.	27527850.	15648470.

PROJECT LIFE (YEARS)    35.33

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	653.
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:06

REVIEWED BY RYDER SCOTT

PROVED UNDEVELOPED

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	36447.120
FINAL								10.0000	31555.710
								12.0000	27483.180.
								15.0000	22525.750.
								20.0000	16405.540.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant/Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $MCF
12-02	35.	384561.	0.	3564724.	141855.	0.	1832246.	17.98	2.67
12-03	91.	873515.	0.	5248529.	304818.	0.	2757109.	18.29	2.53
12-04	153.	1207906.	0.	4459955.	531996.	0.	2317118.	18.16	2.46
12-05	163.	1141559.	0.	3740975.	529979.	0.	1943217.	18.00	2.42
12-06	162.	936332.	0.	2905502.	427726.	0.	1490746.	17.98	2.42
12-07	161.	793701.	0.	2395341.	360506.	0.	1212081.	17.96	2.42
12-08	158.	687482.	0.	2008099.	312843.	0.	993940.	17.94	2.41
12-09	157.	611062.	0.	1770000.	280318.	0.	874239.	17.92	2.40
12-10	155.	548601.	0.	1577383.	254540.	0.	779268.	17.91	2.39
12-11	150.	485207.	0.	1380420.	227411.	0.	681282.	17.88	2.37
12-12	142.	426248.	0.	1139856.	200850.	0.	566387.	17.86	2.34
12-13	134.	372971.	0.	992979.	176094.	0.	485518.	17.84	2.30
12-14	127.	327892.	0.	885295.	154028.	0.	427004.	17.80	2.28
12-15	120.	285105.	0.	756460.	135130.	0.	366010.	17.79	2.24
12-16	105.	210532.	0.	676076.	99086.	0.	326867.	17.72	2.21
Sub	134.	9292674.	0.	33501590.	4137180.	0.	17053030.	17.98	2.45
Remain	22.	1453072.	0.	4834529.	879871.	0.	2534248.	17.39	2.26
Total	47.	10745750.	0.	38336120.	5017051.	0.	19587280.	17.88	2.42
Cumulative		40518.	0.	829587.
Ultimate		10786260.	0.	39165710.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	2549942.	0.	4896668.	0.	7446609.	119022.	367351.	6960237.
12-03	5574723.	0.	6963551.	0.	12538270.	274803.	523779.	11739670.
12-04	9658438.	0.	5699162.	0.	15357600.	474894.	428921.	14453780.
12-05	9541908.	0.	4697760.	0.	14239670.	478750.	353630.	13407290.
12-06	7690458.	0.	3613338.	0.	11303800.	389560.	272083.	10642150.
12-07	6473653.	0.	2933289.	0.	9406941.	330686.	220941.	8855315.
12-08	5611862.	0.	2399359.	0.	8011220.	288722.	180793.	7541707.
12-09	5023925.	0.	2101628.	0.	7125552.	259657.	158379.	6707519.
12-10	4559285.	0.	1863767.	0.	6423051.	236335.	140448.	6046268.
12-11	4065593.	0.	1613966.	0.	5679560.	211664.	121606.	5346287.
12-12	3587135.	0.	1324209.	0.	4911342.	188167.	99823.	4623354.
12-13	3141787.	0.	1115272.	0.	4257060.	166368.	84115.	4006577.
12-14	2742394.	0.	971711.	0.	3714106.	146772.	73314.	3494020.
12-15	2403375.	0.	821370.	0.	3224744.	130035.	62007.	3032704.
12-16	1755475.	0.	723098.	0.	2478574.	98967.	54604.	2325004.
Sub	74379940.	0.	41738150.	0.	116118100.	3794401.	3141815.	109181900.
Remain	15303960.	0.	5719614.	0.	21023570.	975598.	432003.	19615970.
Total	89683900.	0.	47457760.	0.	137141700.	4769999.	3573818.	128797900.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	229830.	207101.	12028350.	0.	12465290.	-5505048	-5505048.	-5452212.
12-03	576643.	332315.	8946434.	0.	9855391.	1884280.	-3620768.	1450579.
12-04	1000065.	404432.	11638780.	0.	13043280.	1410508.	-2210260.	946466.
12-05	1127397.	366580.	0.	0.	1493976.	11913310.	9703052.	8556892.
12-06	1113481.	287537.	0.	0.	1401018.	9241131.	18944180.	6030932.
12-07	1102639.	236689.	0.	0.	1339328.	7515987.	26460170.	4458264.
12-08	1087685.	199459.	0.	0.	1287143.	6254561.	32714730.	3371636.
12-09	1086155.	176309.	0.	0.	1262464.	5445053.	38159780.	2667749.
12-10	1070471.	158317.	0.	0.	1228788.	4817480.	42977260.	2145621.
12-11	1011686.	139232.	0.	0.	1150918.	4195369.	47172630.	1699254.
12-12	936330.	118886.	0.	0.	1055216.	3568137.	50740770.	1313519.
12-13	868830.	101537.	0.	0.	970367.	3036208.	53776980.	1016396.
12-14	806616.	87235.	0.	0.	893851.	2600168.	56377140.	791088.
12-15	738988.	74396.	0.	0.	813384.	2219319.	58596460.	613943.
12-16	635318.	54267.	0.	0.	689585.	1635418.	60231880.	411659.
Sub	13392130.	2944293.	32613570.	0.	48950000.	60231880.	60231880.	30021780.
Remain	7307190.	366819.	0.	0.	7674010.	11941970.	72173860.	1533925.
Total	20699320.	3311112.	32613570.	0.	56624010.	72173850.	72173860.	31555710.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:55

NOT REVIEWED BY RYDER SCOTT

TOTAL PROVED

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	8432.888
FINAL								10.0000	7402.090
								12.0000	6541.801.
								15.0000	5497.412.
								20.0000	4223.027.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	4640.	23488930.	0.	51891040.	103732.	0.	420026.	17.64	2.19
12-03	4412.	20554290.	0.	48642410.	118269.	0.	655483.	17.45	2.33
12-04	4323.	18395770.	0.	45620240.	134724.	0.	776402.	17.63	2.35
12-05	3854.	15486730.	0.	43304920.	148695.	0.	771292.	18.05	2.29
12-06	3510.	13633100.	0.	40737540.	113721.	0.	678182.	17.98	2.28
12-07	3453.	12745490.	0.	38116320.	88193.	0.	589600.	17.91	2.27
12-08	3370.	11927150.	0.	35861820.	71775.	0.	529583.	17.90	2.27
12-09	3088.	10896220.	0.	33649930.	59593.	0.	476485.	17.93	2.28
12-10	2836.	9924648.	0.	31520630.	49975.	0.	414339.	17.97	2.29
12-11	2663.	9143829.	0.	29664530.	42500.	0.	360988.	17.98	2.30
12-12	2615.	8576278.	0.	27990270.	35537.	0.	323263.	18.04	2.30
12-13	2547.	7983390.	0.	26432380.	30804.	0.	293514.	18.06	2.31
12-14	2474.	7400313.	0.	24961210.	26516.	0.	266715.	18.08	2.31
12-15	2438.	6942071.	0.	23592930.	23187.	0.	242975.	18.06	2.31
12-16	2306.	6364768.	0.	22091640.	20070.	0.	217213.	18.05	2.31
Sub	3235.	183463000.	0.	524077900.	1067291.	0.	7016060.	17.85	2.29
Remain	639.	64210680.	0.	313391100.	74650.	0.	871608.	17.98	2.40
Total	1211.	247673600.	0.	837468900.	1141941.	0.	7887668.	17.86	2.31
Cumulative		3339587000.	0.	2934328000.
Ultimate		3587260000.	0.	3771796000.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP &	FGR AFTER PROD TAX. $
12-02	1829633.	0.	921383.	0.	2751020.	101499.	68944.	2580578.
12-03	2063430.	0.	1525942.	0.	3589372.	119692.	114930.	3354751.
12-04	2374933.	0.	1826011.	0.	4200945.	133554.	137308.	3930083.
12-05	2684421.	0.	1768406.	0.	4452827.	141324.	132778.	4178725.
12-06	2045136.	0.	1543708.	0.	3588846.	105879.	115836.	3367132.
12-07	1579390.	0.	1337191.	0.	2916582.	82162.	100320.	2734100.
12-08	1284450.	0.	1203868.	0.	2488319.	67130.	90348.	2330840.
12-09	1068437.	0.	1084224.	0.	2152661.	55884.	81335.	2015442.
12-10	897912.	0.	947943.	0.	1845856.	46631.	71007.	1728217.
12-11	764242.	0.	828692.	0.	1592933.	39656.	61996.	1491281.
12-12	640998.	0.	744718.	0.	1385716.	33416.	55816.	1296483.
12-13	556245.	0.	678260.	0.	1234505.	28733.	50838.	1154933.
12-14	479475.	0.	615853.	0.	1095329.	24496.	46153.	1024679.
12-15	418684.	0.	562130.	0.	980814.	21449.	42119.	917246.
12-16	362204.	0.	502577.	0.	864781.	18618.	37669.	808494.
Sub	19049590.	0.	16090910.	0.	35140500.	1020124.	1207397.	32912980.
Remain	1342353.	0.	2092858.	0.	3435210.	75711.	156813.	3202687.
Total	20391950.	0.	18183760.	0.	38575700.	1095835.	1364209.	36115670.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	1306060.	59752.	337107.	0.	1702918.	877660.	877660.	827397.
12-03	1076052.	75623.	3046507.	0.	4198182.	-843432.	34229.	-742945.
12-04	919635.	94344.	1809130.	0.	2823109.	1106974.	1141203.	854091.
12-05	900767.	108191.	3240000.	0.	4248957.	-70233.	1070970.	-102197.
12-06	723922.	88962.	0.	0.	812884.	2554246.	3625215.	1667837.
12-07	681020.	72123.	0.	0.	753143.	1980956.	5606171.	1175259.
12-08	641545.	61380.	0.	0.	702925.	1627916.	7234087.	877710.
12-09	600349.	53372.	0.	0.	653721.	1361721.	8595808.	667514.
12-10	550545.	46430.	0.	0.	596975.	1131242.	9727050.	504028.
12-11	491434.	40338.	0.	0.	531772.	959509.	10686560.	388618.
12-12	433564.	34698.	0.	0.	468263.	828221.	11514780.	304912.
12-13	406840.	30985.	0.	0.	437825.	717108.	12231890.	240009.
12-14	378645.	27581.	0.	0.	406226.	618453.	12850340.	188186.
12-15	363033.	24702.	0.	0.	387735.	529511.	13379850.	146482.
12-16	338895.	21824.	0.	0.	360719.	447774.	13827630.	112614.
Sub	9812305.	840304.	8432744.	0.	19085350.	13827630.	13827630.	7109514.
Remain	1447476.	79474.	0.	0.	1526950.	1675737.	15503360.	292579.
Total	11259780.	919778.	8432744.	0.	20612300.	15503360.	15503360.	7402093.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:51

NOT REVIEWED BY RYDER SCOTT

PROVED PRODUCING

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	3357.274
FINAL								10.0000	3129.032
								12.0000	2935.554	.
								15.0000	2694.397	.
								20.0000	2384.365	.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	4637.	23456990.	0.	51815150.	85938.	0.	367999.	17.79	2.13
12-03	4398.	20475000.	0.	48035490.	64384.	0.	288894.	17.84	2.10
12-04	4294.	18255870.	0.	44693560.	48742.	0.	223564.	17.82	2.05
12-05	3803.	15180390.	0.	41907540.	39874.	0.	190522.	17.78	2.04
12-06	3453.	13388720.	0.	39396640.	27436.	0.	156049.	17.52	2.00
12-07	3396.	12572070.	0.	36938110.	24157.	0.	134402.	17.48	1.97
12-08	3313.	11792060.	0.	34783430.	20499.	0.	118261.	17.53	1.99
12-09	3031.	10786010.	0.	32676920.	17101.	0.	106902.	17.67	1.99
12-10	2781.	9833515.	0.	30680960.	14934.	0.	90331.	17.71	1.99
12-11	2609.	9065366.	0.	28932150.	12046.	0.	72628.	17.74	1.97
12-12	2562.	8509493.	0.	27335330.	9980.	0.	62562.	17.75	1.97
12-13	2494.	7924295.	0.	25842640.	8044.	0.	55903.	17.82	1.97
12-14	2421.	7348009.	0.	24429700.	6240.	0.	49908.	17.92	1.92
12-15	2385.	6895766.	0.	23113500.	5116.	0.	44944.	17.83	1.91
12-16	2253.	6323991.	0.	21662510.	4140.	0.	38924.	17.76	1.89
Sub	3189.	181807500.	0.	512243600.	388630.	0.	2001795.	17.74	2.03
Remain	634.	64088240.	0.	311942700.	27036.	0.	205250.	17.73	2.21
Total	1198.	245895700.	0.	824186400.	415666.	0.	2207045.	17.74	2.05
Cumulative		3339587000.	0.	2932807000.
Ultimate		3585482000.	0.	3756994000.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	1529244.	0.	782676.	0.	2311920.	87680.	58541.	2165699.
12-03	1148812.	0.	606127.	0.	1754939.	66735.	45361.	1642845.
12-04	868678.	0.	458258.	0.	1326937.	50858.	34124.	1241955.
12-05	708933.	0.	387778.	0.	1096711.	41606.	28832.	1026274.
12-06	480549.	0.	312779.	0.	793328.	27576.	23237.	742515.
12-07	422167.	0.	264317.	0.	686484.	24201.	19654.	642629.
12-08	359406.	0.	235635.	0.	595041.	20909.	17583.	556549.
12-09	302111.	0.	212854.	0.	514964.	17819.	15876.	481269.
12-10	264514.	0.	179608.	0.	444122.	15713.	13330.	415080.
12-11	213721.	0.	143011.	0.	356732.	12740.	10525.	333467.
12-12	177148.	0.	123034.	0.	300182.	10631.	9149.	280401.
12-13	143364.	0.	109995.	0.	253359.	8423.	8181.	236756.
12-14	111827.	0.	95834.	0.	207661.	6383.	7117.	194161.
12-15	91189.	0.	85765.	0.	176953.	5289.	6360.	165304.
12-16	73542.	0.	73546.	0.	147087.	4339.	5463.	137285.
Sub	6895206.	0.	4071215.	0.	10966420.	400903.	303333.	10262190.
Remain	479303.	0.	454369.	0.	933672.	30514.	33760.	869397.
Total	7374509.	0.	4525584.	0.	11900090.	431417.	337093.	11131590.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	1249870.	47305.	0.	0.	1297175.	868524.	868524.	830363.
12-03	951246.	34847.	0.	0.	986093.	656751.	1525275.	570614.
12-04	696519.	26307.	0.	0.	722825.	519129.	2044404.	409901.
12-05	582092.	21941.	0.	0.	604033.	422240.	2466644.	303093.
12-06	377168.	16156.	0.	0.	393324.	349191.	2815835.	227777.
12-07	334266.	13781.	0.	0.	348046.	294583.	3110418.	174698.
12-08	294791.	11540.	0.	0.	306330.	250219.	3360637.	134886.
12-09	257049.	9917.	0.	0.	266966.	214304.	3574940.	105019.
12-10	225017.	8610.	0.	0.	233627.	181452.	3756393.	80867.
12-11	175478.	7003.	0.	0.	182481.	150986.	3907378.	61167.
12-12	145975.	5489.	0.	0.	151464.	128938.	4036316.	47466.
12-13	119251.	4599.	0.	0.	123849.	112906.	4149223.	37782.
12-14	91056.	3723.	0.	0.	94778.	99382.	4248605.	30238.
12-15	75443.	3108.	0.	0.	78551.	86753.	4335358.	23996.
12-16	61306.	2569.	0.	0.	63875.	73410.	4408768.	18457.
Sub	5636525.	216894.	0.	0.	5853420.	4408768.	4408768.	3056325.
Remain	319895.	14344.	0.	0.	334240.	535157.	4943926.	72708.
Total	5956421.	231238.	0.	0.	6187659.	4943926.	4943926.	3129032.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:52

NOT REVIEWED BY RYDER SCOTT

PROVED NON-PRODUCING

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	959.906
FINAL								10.0000	860.775
								12.0000	775.657.
								15.0000	668.811.
								20.0000	531.710.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	2.	12832.	0.	60604.	6415.	0.	42923.	17.17	2.73
12-03	5.	8095.	0.	191685.	4615.	0.	97665.	17.32	2.58
12-04	9.	15356.	0.	210643.	8550.	0.	103788.	17.59	2.54
12-05	9.	10460.	0.	152992.	5955.	0.	77432.	17.60	2.56
12-06	9.	12809.	0.	124695.	6726.	0.	64280.	17.42	2.56
12-07	9.	10365.	0.	102449.	5668.	0.	54002.	17.42	2.57
12-08	9.	8857.	0.	86762.	4996.	0.	46553.	17.42	2.57
12-09	9.	7687.	0.	74915.	4468.	0.	40780.	17.41	2.57
12-10	9.	6635.	0.	65163.	4014.	0.	36058.	17.40	2.58
12-11	8.	5588.	0.	56621.	3587.	0.	32030.	17.39	2.58
12-12	8.	5028.	0.	50845.	3263.	0.	28819.	17.40	2.58
12-13	8.	4533.	0.	45933.	2973.	0.	26053.	17.40	2.57
12-14	8.	4094.	0.	41704.	2713.	0.	23647.	17.41	2.57
12-15	8.	3705.	0.	38024.	2479.	0.	21535.	17.42	2.57
12-16	8.	3132.	0.	31116.	2086.	0.	16898.	17.43	2.53
Sub	8.	119177.	0.	1334151.	68509.	0.	712465.	17.42	2.58
Remain	2.	17352.	0.	39646.	11769.	0.	23054.	17.47	2.18
Total	6.	136529.	0.	1373796.	80278.	0.	735518.	17.43	2.56
Cumulative		0.	0.	53341.
Ultimate		136529.	0.	1427137.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	110128.	0.	117313.	0.	227441.	5066.	8798.	213576.
12-03	79945.	0.	252350.	0.	332295.	4047.	18940.	309308.
12-04	150381.	0.	263158.	0.	413538.	9440.	19841.	384257.
12-05	104782.	0.	198384.	0.	303167.	6481.	14948.	281738.
12-06	117182.	0.	164385.	0.	281567.	6731.	12383.	262454.
12-07	98753.	0.	138626.	0.	237379.	5692.	10441.	221245.
12-08	87007.	0.	119737.	0.	206744.	5022.	9018.	192703.
12-09	77800.	0.	104999.	0.	182799.	4511.	7908.	170380.
12-10	69870.	0.	92886.	0.	162756.	4071.	6996.	151689.
12-11	62371.	0.	82528.	0.	144898.	3647.	6214.	135037.
12-12	56768.	0.	74238.	0.	131006.	3342.	5591.	122073.
12-13	51747.	0.	67083.	0.	118829.	3068.	5053.	110709.
12-14	47239.	0.	60847.	0.	108086.	2819.	4584.	100683.
12-15	43185.	0.	55366.	0.	98552.	2594.	4172.	91786.
12-16	36355.	0.	42743.	0.	79098.	2243.	3224.	73631.
Sub	1193513.	0.	1834642.	0.	3028155.	68773.	138111.	2821272.
Remain	205564.	0.	50239.	0.	255803.	13752.	3903.	238147.
Total	1399077.	0.	1884881.	0.	3283958.	82525.	142014.	3059419.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	31110.	6407.	153107.	0.	190625.	22952.	22952.	15503.
12-03	36710.	8941.	369012.	0.	414664.	-105356.	-82404.	-96153.
12-04	52594.	9191.	0.	0.	61784.	322473.	240069.	255189.
12-05	52594.	6910.	0.	0.	59504.	222234.	462303.	159623.
12-06	52594.	6636.	0.	0.	59230.	203224.	665527.	132653.
12-07	52594.	5583.	0.	0.	58176.	163069.	828597.	96725.
12-08	52594.	4851.	0.	0.	57445.	135259.	963855.	72928.
12-09	52594.	4266.	0.	0.	56860.	113520.	1077376.	55637.
12-10	52094.	3779.	0.	0.	55873.	95816.	1173192.	42692.
12-11	50597.	3358.	0.	0.	53955.	81083.	1254274.	32842.
12-12	50597.	3011.	0.	0.	53607.	68465.	1322739.	25211.
12-13	50597.	2709.	0.	0.	53306.	57403.	1380143.	19218.
12-14	50597.	2445.	0.	0.	53042.	47642.	1427785.	14501.
12-15	50597.	2213.	0.	0.	52809.	38977.	1466762.	10787.
12-16	40597.	1700.	0.	0.	42297.	31334.	1498096.	7883.
Sub	729056.	72001.	522119.	0.	1323176.	1498096.	1498096.	845239.
Remain	151902.	3317.	0.	0.	155219.	82928.	1581024.	15536.
Total	880958.	75318.	522119.	0.	1478395.	1581025.	1581024.	860775.

PROJECT LIFE (YEARS)    25.58

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:55

NOT REVIEWED BY RYDER SCOTT

PROVED UNDEVELOPED

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	4115.708
FINAL								10.0000	3412.284
								12.0000	2830.590.
								15.0000	2134.203.
								20.0000	1306.953.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	1.	19112.	0.	15289.	11380.	0.	9104.	16.72	2.35
12-03	8.	71194.	0.	415237.	49269.	0.	268925.	16.94	2.48
12-04	21.	124552.	0.	716038.	77431.	0.	449050.	17.51	2.46
12-05	42.	295882.	0.	1244397.	102866.	0.	503338.	18.19	2.35
12-06	48.	231567.	0.	1216205.	79559.	0.	457853.	18.19	2.33
12-07	48.	163051.	0.	1075755.	58368.	0.	401195.	18.13	2.33
12-08	48.	126233.	0.	991628.	46280.	0.	364768.	18.11	2.33
12-09	48.	102523.	0.	898100.	38024.	0.	328803.	18.11	2.33
12-10	47.	84498.	0.	774509.	31027.	0.	287949.	18.16	2.35
12-11	46.	72875.	0.	675759.	26867.	0.	256330.	18.17	2.35
12-12	45.	61757.	0.	604088.	22294.	0.	231882.	18.26	2.36
12-13	45.	54562.	0.	543808.	19787.	0.	211557.	18.25	2.37
12-14	45.	48210.	0.	489804.	17564.	0.	193159.	18.24	2.38
12-15	45.	42600.	0.	441405.	15592.	0.	176495.	18.23	2.39
12-16	45.	37645.	0.	398016.	13844.	0.	161391.	18.23	2.39
Sub	39.	1536261.	0.	10500040.	610152.	0.	4301800.	17.96	2.37
Remain	30.	105080.	0.	1408734.	35845.	0.	643304.	18.34	2.47
Total	36.	1641341.	0.	11908770.	645997.	0.	4945104.	17.99	2.38
Cumulative		0.	0.	1467173.
Ultimate		1641341.	0.	13375950.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	190266.	0.	21394.	0.	211660.	8752.	1605.	201303.
12-03	834674.	0.	667465.	0.	1502138.	48911.	50629.	1402599.
12-04	1355874.	0.	1104596.	0.	2460470.	73255.	83343.	2303871.
12-05	1870705.	0.	1182244.	0.	3052950.	93237.	88998.	2870713.
12-06	1447404.	0.	1066545.	0.	2513950.	71573.	80216.	2362162.
12-07	1058470.	0.	934249.	0.	1992718.	52269.	70224.	1870225.
12-08	838038.	0.	848496.	0.	1686534.	41198.	63748.	1581588.
12-09	688526.	0.	766371.	0.	1454897.	33554.	57550.	1363793.
12-10	563529.	0.	675449.	0.	1238978.	26848.	50682.	1161449.
12-11	488150.	0.	603153.	0.	1091303.	23269.	45257.	1022777.
12-12	407082.	0.	547446.	0.	954528.	19442.	41076.	894009.
12-13	361134.	0.	501182.	0.	862316.	17243.	37604.	807468.
12-14	320409.	0.	459172.	0.	779581.	15294.	34452.	729835.
12-15	284310.	0.	420999.	0.	705309.	13567.	31587.	660155.
12-16	252307.	0.	386289.	0.	638596.	12036.	28982.	597578.
Sub	10960880.	0.	10185050.	0.	21145920.	550448.	765953.	19829520.
Remain	657485.	0.	1588251.	0.	2245736.	31445.	119149.	2095142.
Total	11618360.	0.	11773300.	0.	23391660.	581893.	885102.	21924670.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	25079.	6039.	184000.	0.	215118.	-13816.	-13816.	-18469.
12-03	88096.	31834.	2677495.	0.	2797426.	-1394827.	-1408643.	-1217406.
12-04	170523.	58846.	1809130.	0.	2038499.	265372.	-1143271.	189002.
12-05	266081.	79339.	3240000.	0.	3585420.	-714707.	-1857978.	-564912.
12-06	294161.	66169.	0.	0.	360330.	2001830.	143853.	1307407.
12-07	294161.	52759.	0.	0.	346920.	1523304.	1667157.	903836.
12-08	294161.	44989.	0.	0.	339150.	1242438.	2909595.	669895.
12-09	290706.	39189.	0.	0.	329896.	1033897.	3943492.	506858.
12-10	273434.	34041.	0.	0.	307475.	853974.	4797466.	380469.
12-11	265359.	29977.	0.	0.	295336.	727441.	5524907.	294609.
12-12	236993.	26199.	0.	0.	263192.	630818.	6155725.	232234.
12-13	236993.	23677.	0.	0.	260670.	546798.	6702523.	183009.
12-14	236993.	21414.	0.	0.	258407.	471429.	7173952.	143446.
12-15	236993.	19381.	0.	0.	256374.	403781.	7577733.	111699.
12-16	236993.	17555.	0.	0.	254547.	343030.	7920763.	86273.
Sub	3446726.	551409.	7910625.	0.	11908760.	7920763.	7920763.	3207950.
Remain	975678.	61813.	0.	0.	1037492.	1057651.	8978415.	204335.
Total	4422404.	613222.	7910625.	0.	12946250.	8978414.	8978415.	3412285.

PROJECT LIFE (YEARS)    21.42

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:56

ALL PROPERTIES

TOTAL PROVED

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	159893.000
FINAL								10.0000	143455.000
								12.0000	129871.800.
								15.0000	113427.800.
								20.0000	93167.840.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	6787.	31772540.	750433.	100727700.	1341167.	23065.	6409044.	18.29	2.46
12-03	6666.	29017570.	688159.	96167470.	1571348.	21799.	7587143.	18.29	2.43
12-04	6562.	26442890.	632552.	87590410.	1734609.	20634.	6629287.	18.27	2.41
12-05	5781.	22625650.	582819.	80141720.	1637307.	19559.	5731117.	18.28	2.38
12-06	5396.	20133420.	538263.	73678070.	1419243.	18564.	4784741.	18.29	2.37
12-07	5306.	18725000.	498273.	68090530.	1255251.	17643.	4105890.	18.30	2.36
12-08	5167.	17451860.	462314.	63160980.	1120402.	16786.	3577213.	18.33	2.36
12-09	4751.	15975040.	429915.	58385900.	983281.	15989.	3169395.	18.44	2.36
12-10	4432.	14672070.	400665.	54363060.	900351.	15245.	2844412.	18.46	2.35
12-11	4170.	13560580.	374201.	50807980.	821715.	14550.	2542895.	18.47	2.35
12-12	4096.	12709930.	350207.	47544980.	754802.	13898.	2266686.	18.49	2.34
12-13	3931.	11771400.	328402.	44479150.	688282.	13286.	2039581.	18.53	2.33
12-14	3813.	10926180.	308541.	41678750.	632597.	12711.	1861378.	18.54	2.32
12-15	3746.	10236900.	290410.	39144940.	579388.	12169.	1684644.	18.57	2.32
12-16	3568.	9400864.	273819.	36593180.	499800.	11657.	1535236.	18.59	2.31
Sub	4945.	265421900.	6908973.	942554900.	15939540.	247555.	56768650.	18.37	2.38
Remain	977.	101073300.	3991552.	519618900.	3997853.	198381.	15339190.	18.72	2.29
Total	1852.	366495200.	10900520.	1462174000.	19937400.	445936.	72107840.	18.44	2.36
Cumulative		3774206000.	0.	4530209000.
Ultimate		4140701000.	10900520.	5992383000.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	24529660.	320145.	15737340.	0.	40587150.	1236446.	1175929.	38174780.
12-03	28742260.	302572.	18474090.	0.	47518930.	1460866.	1382086.	44675980.
12-04	31683260.	286396.	15967570.	0.	47937220.	1600943.	1196390.	45139900.
12-05	29934840.	271473.	13632620.	0.	43838930.	1515329.	1022115.	41301480.
12-06	25960650.	257672.	11338870.	0.	37557180.	1313647.	849299.	35394230.
12-07	22972580.	244880.	9694025.	0.	32911480.	1163726.	725809.	31021950.
12-08	20540160.	232995.	8433187.	0.	29206350.	1041798.	631586.	27532950.
12-09	18132700.	221930.	7478733.	0.	25833370.	911816.	560046.	24361510.
12-10	16623460.	211605.	6697846.	0.	23532900.	833622.	501988.	22197300.
12-11	15178430.	201950.	5972069.	0.	21352450.	759919.	447566.	20144970.
12-12	13954760.	192904.	5299567.	0.	19447220.	698402.	397313.	18351510.
12-13	12754550.	184412.	4746701.	0.	17685660.	636389.	355407.	16693870.
12-14	11729360.	176425.	4319546.	0.	16225330.	584711.	323342.	15317280.
12-15	10759870.	168900.	3903441.	0.	14832210.	536447.	292201.	14003570.
12-16	9292081.	161799.	3549545.	0.	13003430.	465885.	265787.	12271750.
Sub	292788600.	3436058.	135245200.	0.	431469800.	14759950.	10126860.	406583000.
Remain	74825980.	2753534.	35155940.	0.	112735400.	3880324.	2640769.	106214400.
Total	367614600.	6189592.	170401100.	0.	544205200.	18640270.	12767630.	512797300.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	9586046.	1006322.	15340220.	0.	25932590.	12242180.	12242180.	11428680.
12-03	9881802.	1164540.	13958650.	0.	25005000.	19670980.	31913160.	16818120.
12-04	9732091.	1185649.	13648790.	0.	24566530.	20573370.	52486530.	16046400.
12-05	9352486.	1085332.	3240000.	0.	13677820.	27623670.	80110200.	19776300.
12-06	9022064.	931097.	8858.	0.	9962019.	25432220.	105542400.	16592100.
12-07	8707286.	814755.	0.	0.	9522041.	21499910.	127042300.	12749100.
12-08	8362567.	720734.	0.	0.	9083300.	18449660.	145492000.	9945036.
12-09	7543180.	644260.	0.	0.	8187440.	16174070.	161666000.	7924062.
12-10	7259823.	590790.	0.	0.	7850613.	14346680.	176012700.	6389664.
12-11	6920606.	539097.	0.	0.	7459703.	12685260.	188698000.	5136519.
12-12	6673170.	491057.	0.	0.	7164227.	11187280.	199885300.	4117812.
12-13	6336016.	449191.	8858.	0.	6794065.	9899797.	209785100.	3312808.
12-14	6150654.	412464.	0.	0.	6563117.	8754158.	218539200.	2663124.
12-15	5920737.	376882.	0.	0.	6297619.	7705947.	226245200.	2131138.
12-16	5396350.	328418.	0.	0.	5724768.	6546984.	232792100.	1646376.
Sub	116844900.	10740590.	46205380.	0.	173790800.	232792100.	232792100.	136677200.
Remain	51128800.	2726339.	8858.	0.	53864000.	52350340.	285142400.	6778052.
Total	167973700.	13466930.	46214240.	0.	227654800.	285142500.	285142400.	143455300.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:55

ALL PROPERTIES

PROVED PRODUCING

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	101109.100
FINAL								10.0000	91977.990
								12.0000	84516.850.
								15.0000	75570.580.
								20.0000	64635.910.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	6716.	31198620.	750433.	96515910.	1093881.	23065.	4300375.	18.28	2.38
12-03	6475.	27658520.	688159.	88112670.	1001006.	21799.	3589828.	18.29	2.36
12-04	6278.	24715500.	632552.	80393180.	908591.	20634.	3030684.	18.34	2.36
12-05	5466.	20875340.	582819.	73681960.	827060.	19559.	2651166.	18.41	2.35
12-06	5079.	18715360.	538263.	68420530.	767410.	18564.	2331285.	18.42	2.34
12-07	4991.	17567400.	498273.	63697060.	717785.	17643.	2075872.	18.44	2.33
12-08	4858.	16476210.	462314.	59411160.	664141.	16786.	1875352.	18.49	2.33
12-09	4447.	15131580.	429915.	55106500.	585884.	15989.	1683249.	18.68	2.34
12-10	4135.	13933660.	400665.	51548690.	548930.	15245.	1534686.	18.70	2.33
12-11	3889.	12917750.	374201.	48380450.	512056.	14550.	1406341.	18.72	2.33
12-12	3826.	12147920.	350207.	45468560.	483761.	13898.	1290084.	18.73	2.33
12-13	3680.	11263820.	328402.	42628480.	449026.	13286.	1178756.	18.78	2.32
12-14	3570.	10486760.	308541.	40025600.	423417.	12711.	1093266.	18.78	2.32
12-15	3514.	9856897.	290410.	37696290.	396888.	12169.	1007258.	18.81	2.32
12-16	3352.	9105622.	273819.	35296230.	357559.	11657.	926344.	18.81	2.32
Sub	4685.	252050900.	6908973.	886383200.	9737394.	247555.	29974550.	18.51	2.35
Remain	943.	99305360.	3991552.	512239300.	2955205.	198381.	11616110.	19.09	2.29
Total	1769.	351356300.	10900520.	1398622000.	12692600.	445936.	41590660.	18.65	2.33
Cumulative		3774165000.	0.	4527640000.
Ultimate		4125521000.	10900520.	5926263000.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	19993760.	320145.	10232370.	0.	30546290.	1017762.	762804.	28765720.
12-03	18309180.	302572.	8485992.	0.	27097760.	930354.	632878.	25534520.
12-04	16661920.	286396.	7154368.	0.	24102690.	845954.	533506.	22723240.
12-05	15229650.	271473.	6231584.	0.	21732710.	773584.	464874.	20494250.
12-06	14137270.	257672.	5450933.	0.	19845870.	715272.	405746.	18724850.
12-07	13233670.	244880.	4830344.	0.	18308900.	668968.	359420.	17280510.
12-08	12280260.	232995.	4366976.	0.	16880230.	621233.	325273.	15933720.
12-09	10944700.	221930.	3937436.	0.	15104080.	545616.	293315.	14265150.
12-10	10267370.	211605.	3582562.	0.	14061530.	509789.	267267.	13284480.
12-11	9587916.	201950.	3280713.	0.	13070580.	474695.	244939.	12350950.
12-12	9061521.	192904.	3001710.	0.	12256130.	447767.	224298.	11584070.
12-13	8430833.	184412.	2734772.	0.	11350020.	412732.	203859.	10733420.
12-14	7953297.	176425.	2533409.	0.	10663130.	388342.	188806.	10085980.
12-15	7465103.	168900.	2337902.	0.	9971904.	363737.	174267.	9433902.
12-16	6724033.	161799.	2152152.	0.	9037986.	328108.	160521.	8549353.
Sub	180280500.	3436058.	70313220.	0.	254029800.	9043914.	5241775.	239744100.
Remain	56423860.	2753534.	26656460.	0.	85833840.	2753575.	1999833.	81080450.
Total	236704300.	6189592.	96969670.	0.	339863600.	11797490.	7241608.	320824600.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	9212270.	732755.	0.	0.	9945025.	18820690.	18820690.	17978690.
12-03	8873387.	651389.	0.	0.	9524776.	16009740.	34830430.	13897670.
12-04	8119357.	580846.	0.	0.	8700203.	14023030.	48853460.	11064910.
12-05	7515741.	525134.	0.	0.	8040875.	12453370.	61306840.	8932415.
12-06	7189932.	483311.	0.	0.	7673243.	11051620.	72358460.	7205996.
12-07	6899011.	446824.	0.	0.	7345835.	9934676.	82293140.	5888664.
12-08	6597058.	410782.	0.	0.	7007841.	8925886.	91219020.	4810004.
12-09	5841388.	374264.	0.	0.	6215653.	8049490.	99268510.	3942922.
12-10	5633750.	351824.	0.	0.	5985575.	7298901.	106567400.	3250289.
12-11	5402466.	329876.	0.	0.	5732343.	6618601.	113186000.	2679383.
12-12	5276342.	310319.	0.	0.	5586661.	5997406.	119183400.	2207216.
12-13	5020857.	291975.	0.	0.	5312832.	5420590.	124604000.	1813567.
12-14	4910332.	275213.	0.	0.	5185545.	4900438.	129504500.	1490533.
12-15	4758863.	258093.	0.	0.	5016956.	4416946.	133921400.	1221360.
12-16	4349512.	233669.	0.	0.	4583182.	3966170.	137887600.	997031.
Sub	95600260.	6256278.	0.	0.	101856500.	137887600.	137887600.	87380660.
Remain	41884330.	2202303.	0.	0.	44086640.	36993790.	174881300.	4597386.
Total	137484600.	8458580.	0.	0.	145943200.	174881400.	174881300.	91978040.

PROJECT LIFE (YEARS)    68.00

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:56

ALL PROPERTIES

PROVED NON-PRODUCING

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	18221.040
FINAL								10.0000	16509.240
								12.0000	15041.230.
								15.0000	13197.230.
								20.0000	10819.450.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	35.	170249.	0.	631807.	94052.	0.	267319.	19.09	2.20
12-03	93.	414345.	0.	2391036.	216255.	0.	971281.	18.61	2.43
12-04	111.	394939.	0.	2021227.	216591.	0.	832435.	18.50	2.41
12-05	111.	312870.	0.	1474393.	177402.	0.	633396.	18.56	2.40
12-06	108.	250164.	0.	1135841.	144548.	0.	504857.	18.58	2.39
12-07	106.	200851.	0.	922379.	118591.	0.	416742.	18.61	2.39
12-08	103.	161931.	0.	750092.	97138.	0.	343152.	18.63	2.38
12-09	99.	129876.	0.	611292.	79055.	0.	283104.	18.66	2.38
12-10	94.	105314.	0.	462478.	65854.	0.	242510.	18.73	2.38
12-11	86.	84751.	0.	371345.	55381.	0.	198943.	18.72	2.38
12-12	82.	74008.	0.	332484.	47897.	0.	178334.	18.77	2.39
12-13	73.	80042.	0.	313887.	43376.	0.	163750.	18.92	2.42
12-14	71.	63318.	0.	278053.	37587.	0.	147948.	18.98	2.40
12-15	67.	52293.	0.	250790.	31778.	0.	134881.	19.10	2.40
12-16	66.	47065.	0.	222858.	29312.	0.	120634.	19.11	2.39
Sub	87.	2542017.	0.	12169960.	1454817.	0.	5439285.	18.67	2.39
Remain	21.	209805.	0.	1136251.	126931.	0.	545524.	19.23	2.18
Total	49.	2751822.	0.	13306210.	1581748.	0.	5984809.	18.72	2.37
Cumulative		195.	0.	272371.
Ultimate		2752016.	0.	13578580.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	1795692.	0.	586906.	0.	2382598.	90910.	44170.	2247518.
12-03	4023687.	0.	2357081.	0.	6380768.	206799.	174780.	5999189.
12-04	4007023.	0.	2009445.	0.	6016467.	206840.	150620.	5659008.
12-05	3292575.	0.	1521027.	0.	4813603.	169757.	114613.	4529235.
12-06	2685511.	0.	1208053.	0.	3893564.	137242.	91255.	3665067.
12-07	2206779.	0.	996144.	0.	3202924.	111803.	75224.	3015896.
12-08	1810001.	0.	818357.	0.	2628358.	90645.	61772.	2475941.
12-09	1475550.	0.	673297.	0.	2148847.	72989.	50802.	2025057.
12-10	1233273.	0.	576068.	0.	1809341.	60650.	43591.	1705100.
12-11	1036772.	0.	474237.	0.	1511009.	50290.	35764.	1424954.
12-12	899018.	0.	426203.	0.	1325221.	43026.	32116.	1250079.
12-13	820797.	0.	395475.	0.	1216271.	40047.	29828.	1146396.
12-14	713259.	0.	355253.	0.	1068512.	34304.	26770.	1007439.
12-15	607086.	0.	323170.	0.	930255.	29109.	24340.	876806.
12-16	560266.	0.	288006.	0.	848272.	26774.	21680.	799819.
Sub	27167280.	0.	13008720.	0.	40176010.	1371185.	977323.	37827500.
Remain	2440668.	0.	1191615.	0.	3632282.	119706.	89783.	3422793.
Total	29607950.	0.	14200340.	0.	43808290.	1490891.	1067106.	41250300.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	118867.	60427.	3127870.	0.	3307165.	-1059646.	-1059646.	-1079326.
12-03	343676.	149002.	2334725.	0.	2827402.	3171787.	2112141.	2687274.
12-04	442147.	141525.	200877.	0.	784548.	4874459.	6986599.	3846016.
12-05	443268.	114279.	0.	0.	557547.	3971687.	10958290.	2851900.
12-06	424490.	94079.	8858.	0.	527428.	3137639.	14095930.	2047763.
12-07	411475.	78483.	0.	0.	489957.	2525939.	16621860.	1498335.
12-08	383663.	65504.	0.	0.	449167.	2026774.	18648640.	1093501.
12-09	324931.	54497.	0.	0.	379429.	1645628.	20294270.	806534.
12-10	282169.	46608.	0.	0.	328776.	1376324.	21670590.	613286.
12-11	241095.	40012.	0.	0.	281106.	1143848.	22814440.	463273.
12-12	223504.	35653.	0.	0.	259158.	990922.	23805360.	364844.
12-13	209337.	32001.	8858.	0.	250196.	896200.	24701560.	299835.
12-14	196712.	28602.	0.	0.	225315.	782124.	25483680.	238056.
12-15	185894.	25011.	0.	0.	210905.	665902.	26149590.	184136.
12-16	174527.	22927.	0.	0.	197454.	602364.	26751950.	151413.
Sub	4405756.	988610.	5681188.	0.	11075550.	26751950.	26751950.	16066840.
Remain	961603.	95404.	8858.	0.	1065866.	2356928.	29108880.	442404.
Total	5367359.	1084014.	5690046.	0.	12141420.	29108880.	29108880.	16509240.

PROJECT LIFE (YEARS)    35.33

SOUTHWEST ROYALTIES, INC.
CERTAIN PRODUCING LEASEHOLD AND ROYALTY INTERESTS	Table:	****
FORECAST OF INCOME, PRODUCTION & NET REVENUE	Run Date:	02/15/02
As of 1/02	Run Time:	18:21:56

ALL PROPERTIES

PROVED UNDEVELOPED

$19.84/BO AND $2.57/MCF    NYMEX

	REVENUE INTERESTS				PRODUCT PRICES			DISCOUNTED Future Net Income Compounded Monthly-$
	Expense Interest	Oil/ Cond.	Plant Products	Gas	Oil/Cond $/Bbl	Plt. Prod. $/Bbl	Gas $/Mcf
INITIAL								8.0000	40562.830
FINAL								10.0000	34968.000
								12.0000	30313.770.
								15.0000	24659.960.
								20.0000	17712.490.

		GROSS PRODUCTION			COMPANY NET PRODUCTION			AVERAGE PRICES
-END- MO-YR	Well Count	Oil/Cond bbls	Plant Prod. bbls	Gas MCF	Oil/Cond bbls	Plant Prod bbls	Sales Gas MCF	Oil/Cond $/bbl	Gas $/MCF
12-02	36.	403673.	0.	3580014.	153234.	0.	1841350.	17.88	2.67
12-03	99.	944709.	0.	5663767.	354088.	0.	3026034.	18.10	2.52
12-04	173.	1332458.	0.	5175993.	609428.	0.	2766168.	18.07	2.46
12-05	205.	1437440.	0.	4985373.	632845.	0.	2446555.	18.03	2.40
12-06	210.	1167899.	0.	4121707.	507285.	0.	1948599.	18.01	2.40
12-07	209.	956752.	0.	3471096.	418874.	0.	1613276.	17.98	2.40
12-08	206.	813715.	0.	2999727.	359123.	0.	1358708.	17.96	2.39
12-09	205.	713585.	0.	2668100.	318342.	0.	1203041.	17.94	2.38
12-10	202.	633100.	0.	2351892.	285567.	0.	1067217.	17.94	2.38
12-11	196.	558083.	0.	2056179.	254278.	0.	937612.	17.91	2.36
12-12	187.	488005.	0.	1743943.	223144.	0.	798269.	17.90	2.34
12-13	179.	427533.	0.	1536787.	195881.	0.	697076.	17.88	2.32
12-14	172.	376101.	0.	1375098.	171592.	0.	620163.	17.85	2.31
12-15	165.	327704.	0.	1197865.	150722.	0.	542505.	17.83	2.29
12-16	150.	248177.	0.	1074092.	112929.	0.	488259.	17.78	2.27
Sub	173.	10828930.	0.	44001630.	4747332.	0.	21354830.	17.98	2.43
Remain	26.	1558152.	0.	6243263.	915716.	0.	3177552.	17.43	2.30
Total	58.	12387090.	0.	50244900.	5663048.	0.	24532380.	17.89	2.41
Cumulative		40518.	0.	2296760.
Ultimate		12427600.	0.	52541650.

	COMPANY FUTURE GROSS REVENUE					SEVERANCE TAXES
-END- MO-YR	From Oil/Cond $	From Plt. Products $	From Gas $	Gas Tax Credit $	Total $	OIL/COND $	GAS/PP $	FGR AFTER PROD TAX. $
12-02	2740208.	0.	4918062.	0.	7658268.	127774.	368955.	7161540.
12-03	6409396.	0.	7631015.	0.	14040410.	323714.	574428.	13142270.
12-04	11014310.	0.	6803758.	0.	17818070.	548149.	512264.	16757660.
12-05	11412610.	0.	5880004.	0.	17292620.	571988.	442628.	16278000.
12-06	9137862.	0.	4679883.	0.	13817750.	461132.	352298.	13004320.
12-07	7532122.	0.	3867538.	0.	11399660.	382955.	291165.	10725540.
12-08	6449900.	0.	3247855.	0.	9697754.	329920.	244541.	9123295.
12-09	5712451.	0.	2867999.	0.	8580449.	293211.	215929.	8071312.
12-10	5122814.	0.	2539216.	0.	7662029.	263182.	191130.	7207716.
12-11	4553743.	0.	2217119.	0.	6770863.	234933.	166863.	6369064.
12-12	3994218.	0.	1871654.	0.	5865870.	207610.	140899.	5517364.
12-13	3502921.	0.	1616454.	0.	5119376.	183611.	121720.	4814045.
12-14	3062803.	0.	1430883.	0.	4493687.	162066.	107766.	4223855.
12-15	2687684.	0.	1242370.	0.	3930053.	143601.	93594.	3692859.
12-16	2007783.	0.	1109387.	0.	3117170.	111003.	83586.	2922581.
Sub	85340820.	0.	51923200.	0.	137264000.	4344850.	3907767.	129011400.
Remain	15961450.	0.	7307864.	0.	23269310.	1007043.	551152.	21711120.
Total	101302300.	0.	59231060.	0.	160533300.	5351892.	4458920.	150722500.

	DEDUCTIONS					FUTURE NET INCOME BEFORE INCOME TAXES
	Operating Costs $	Ad Valorem Taxes $	Development Costs $	Other $	Total $	Undiscounted		Discounted 10% $
-END- MO-YR						Annual $	Cumulative $
12-02	254909.	213140.	12212350.	0.	12680400.	-5518864.	-5518864.	-5470681.
12-03	664739.	364149.	11623930.	0.	12652820.	489453.	-5029411.	233173.
12-04	1170588.	463278.	13447910.	0.	15081780.	1675880.	-3353531.	1135468.
12-05	1393477.	445919.	3240000.	0.	5079396.	11198610.	7845075.	7991980.
12-06	1407642.	353707.	0.	0.	1761349.	11242960.	19088040.	7338339.
12-07	1396800.	289448.	0.	0.	1686249.	9039291.	28127330.	5362099.
12-08	1381845.	244448.	0.	0.	1626293.	7496999.	35624330.	4041531.
12-09	1376861.	215498.	0.	0.	1592359.	6478950.	42103280.	3174607.
12-10	1343904.	192358.	0.	0.	1536263.	5671453.	47774730.	2526090.
12-11	1277045.	169209.	0.	0.	1446254.	4922810.	52697540.	1993863.
12-12	1173323.	145085.	0.	0.	1318408.	4198955.	56896500.	1545752.
12-13	1105823.	125214.	0.	0.	1231037.	3583007.	60479510.	1199405.
12-14	1043609.	108648.	0.	0.	1152258.	3071597.	63551100.	934534.
12-15	975981.	93777.	0.	0.	1069758.	2623100.	66174200.	725642.
12-16	872311.	71821.	0.	0.	944132.	1978449.	68152660.	497932.
Sub	16838860.	3495701.	40524190.	0.	60858750.	68152660.	68152660.	33229730.
Remain	8282869.	428632.	0.	0.	8711502.	12999620.	81152280.	1738260.
Total	25121730.	3924333.	40524190.	0.	69570260.	81152270.	81152280.	34967990.

PROJECT LIFE (YEARS)    68.00

APPENDIX B2

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWRI Income Fund V (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 12 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 91.5 percent of the total net remaining liquid hydrocarbon reserves and 84.6 percent of the total net remaining gas reserves. The properties that we reviewed represent 92.5 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWRI Income Fund V

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		31,964		0		10,013		41,977
Gas—MMCF		268		0		40		308
Income Data
Future Gross Revenue	$	1,242,348	$	0	$	283,840	$	1,526,188
Deductions		881,816		0		46,449		928,265
Future Net Income (FNI)	$	360,532	$	0	$	237,391	$	597,923
Discounted FNI @ 10%	$	256,203	$	0	$	163,202	$	419,405

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		3,916		0		0		3,916
Gas—MMCF		56		0		0		56
Income Data
Future Gross Revenue	$	206,998	$	0	$	0	$	206,998
Deductions		163,970		0		0		163,970
Future Net Income (FNI)	$	43,028	$	0	$	0	$	43,028
Discounted FNI @ 10%	$	34,194	$	0	$	0	$	34,194
Total Net Reserves
Oil/Condensate—Barrels		35,880		0		10,013		45,893
Gas—MMCF		324		0		40		364
Income Data
Future Gross Revenue	$	1,449,346	$	0	$	283,840	$	1,733,186
Deductions		1,045,786		0		46,449		1,092,235
Future Net Income (FNI)	$	403,560	$	0	$	237,391	$	640,951
Discounted FNI @ 10%	$	290,397	$	0	$	163,202	$	453,599

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any: and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? …The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 8.5 percent of the total net remaining liquid hydrocarbon reserves and 15.4 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick Mclnturff, P.E. Petroleum Engineer

CPM/sw

Approved:
By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SWRI INCOME FUND V	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:15
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	9.8	10.265	94.083	.000	4.546	31.950	.000	18.70	2.71	85.011	86.570	171.581
12-03	9.0	8.612	82.748	.000	3.917	28.081	.000	18.71	2.69	73.301	75.510	148.811
12-04	9.0	8.102	77.711	.000	3.693	26.408	.000	18.71	2.69	69.120	71.009	140.128
12-05	9.0	7.631	73.157	.000	3.485	24.882	.000	18.72	2.69	65.230	66.895	132.124
12-06	9.0	7.195	69.005	.000	3.291	23.481	.000	18.72	2.69	61.600	63.105	124.706
12-07	9.0	6.790	65.189	.000	3.109	22.186	.000	18.72	2.69	58.208	59.594	117.802
12-08	9.0	6.412	61.650	.000	2.939	20.981	.000	18.72	2.68	55.026	56.321	111.347
12-09	9.0	6.056	58.316	.000	2.779	19.845	.000	18.72	2.68	52.024	53.237	105.261
12-10	8.1	4.472	50.353	.000	2.105	16.783	.000	18.81	2.64	39.599	44.330	83.930
12-11	6.0	1.552	38.790	.000	.739	11.887	.000	19.02	2.54	14.045	30.159	44.204
12-12	6.0	1.459	36.721	.000	.694	11.248	.000	19.02	2.53	13.202	28.512	41.714
12-13	5.3	1.000	31.986	.000	.370	8.532	.000	19.01	2.64	7.043	22.566	29.609
S TOT	1.0	69.546	739.709	.000	31.669	246.264	.000	18.74	2.67	593.408	657.808	1251.216
AFTER	1.0	1.063	103.715	.000	.296	22.016	.000	19.01	3.06	5.622	67.460	73.082
TOTAL	1.0	70.609	843.424	.000	31.964	268.280	.000	18.74	2.70	599.030	725.268	1324.298

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	3.911	6.493	4.773	90.765	65.640	10.73	.000	65.640	65.640	62.683
12-03	3.372	5.663	4.135	78.961	56.680	10.72	.000	56.680	122.320	111.887
12-04	3.180	5.326	3.894	78.961	48.768	11.29	.000	48.768	171.088	150.378
12-05	3.001	5.017	3.672	78.961	41.474	11.88	.000	41.474	212.562	180.138
12-06	2.834	4.733	3.466	78.961	34.712	12.49	.000	34.712	247.275	202.786
12-07	2.678	4.470	3.274	78.961	28.419	13.13	.000	28.419	275.694	219.646
12-08	2.531	4.224	3.095	78.961	22.536	13.80	.000	22.536	298.229	231.803
12-09	2.393	3.993	2.926	78.961	16.988	14.50	.000	16.988	315.218	240.139
12-10	1.822	3.325	2.326	64.575	11.883	14.70	.000	11.883	327.100	245.442
12-11	.646	2.262	1.203	31.294	8.798	13.02	.000	8.798	335.899	249.009
12-12	.607	2.138	1.136	31.294	6.539	13.69	.000	6.539	342.437	251.420
12-13	.324	1.692	.796	22.182	4.614	13.94	.000	4.614	347.051	252.966
S TOT	27.297	49.336	34.696	792.836	347.051	19.59	.000	347.051	347.051	252.966
AFTER	.259	5.059	1.937	52.346	13.480	19.59	.000	13.480	360.532	256.203
TOTAL	27.555	54.395	36.634	845.182	360.532	19.59	.000	360.532	360.532	256.203

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	8.0	4.0	LIFE, YRS.	24.67	8.00	271.788
GROSS ULT., MB &MMF	777.690	5738.322	DISCOUNT %	10.00	10.00	256.203
GROSS CUM., MB & MMF	707.081	4894.898	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	242.395
GROSS RES., MB & MMF	70.609	843.424	DISCOUNTED PAYOUT, YRS.	.00	15.00	224.422
NET RES., MB & MMF	31.964	268.280	UNDISCOUNTED NET/INVEST.	.00	20.00	200.108
NET REVENUE, M$	599.030	725.268	DISCOUNTED NET/INVEST.	.00	25.00	180.961
INITIAL PRICE, $	18.671	2.822	RATE-OF-RETURN, PCT.	100.00	35.00	152.829
INITIAL N.I., PCT.	46.532	34.384	INITIAL W.I., PCT.	50.120	50.00	125.510
					70.00	103.198
					100.00	83.644

SWRI INCOME FUND V	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:21
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER: RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.7	9.927	39.707	.000	1.086	4.343	.000	19.19	2.75	20.835	11.943	32.779
12-03	2.0	24.306	97.223	.000	1.757	7.027	.000	19.09	2.73	33.541	19.178	52.718
12-04	2.0	17.270	69.081	.000	1.276	5.104	.000	19.10	2.73	24.371	13.937	38.307
12-05	2.0	13.692	54.767	.000	1.022	4.088	.000	19.10	2.73	19.521	11.164	30.685
12-06	2.0	11.470	45.878	.000	.861	3.445	.000	19.10	2.73	16.450	9.408	25.859
12-07	2.0	9.937	39.747	.000	.749	2.996	.000	19.10	2.73	14.308	8.183	22.491
12-08	2.0	8.807	35.229	.000	.666	2.662	.000	19.11	2.73	12.717	7.273	19.990
12-09	2.0	7.936	31.744	.000	.601	2.404	.000	19.11	2.73	11.482	6.567	18.049
12-10	2.0	6.990	27.960	.000	.538	2.152	.000	19.11	2.73	10.283	5.882	16.165
12-11	2.0	6.381	25.523	.000	.493	1.971	.000	19.11	2.73	9.419	5.388	14.807
12-12	2.0	5.870	23.482	.000	.453	1.814	.000	19.11	2.73	8.665	4.957	13.622
12-13	1.9	5.187	20.749	.000	.408	1.631	.000	19.12	2.73	7.794	4.459	12.252
S TOT	1.0	127.773	511.091	.000	9.909	39.637	.000	19.11	2.73	189.385	108.339	297.724
AFTER	1.0	.948	3.792	.000	.104	.415	.000	19.19	2.75	1.990	1.141	3.130
TOTAL	1.0	128.721	514.883	.000	10.013	40.051	.000	19.11	2.73	191.375	109.480	300.854

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.958	.896	.928	1.500	28.497	2.37	.000	28.497	28.497	26.800
12-03	1.543	1.438	1.492	3.234	45.011	2.63	.000	45.011	73.507	65.959
12-04	1.121	1.045	1.084	3.234	31.823	3.05	.000	31.823	105.330	91.100
12-05	.898	.837	.868	3.234	24.847	3.43	.000	24.847	130.176	108.936
12-06	.757	.706	.732	3.234	20.430	3.78	.000	20.430	150.607	122.264
12-07	.658	.614	.637	3.234	17.348	4.12	.000	17.348	167.955	132.551
12-08	.585	.545	.566	3.234	15.059	4.44	.000	15.059	183.014	140.667
12-09	.528	.493	.511	3.234	13.283	4.76	.000	13.283	196.297	147.175
12-10	.473	.441	.458	3.234	11.559	5.14	.000	11.559	207.856	152.324
12-11	.433	.404	.419	3.234	10.316	5.47	.000	10.316	218.172	156.500
12-12	.399	.372	.386	3.234	9.232	5.81	.000	9.232	227.404	159.898
12-13	.359	.334	.347	3.152	8.060	6.17	.000	8.060	235.464	162.598
S TOT	8.712	8.125	8.427	36.996	235.464	6.96	.000	235.464	235.464	162.598
AFTER	.092	.086	.089	.938	1.927	6.96	.000	1.927	237.391	163.202
TOTAL	8.803	8.211	8.515	37.934	237.391	6.96	.000	237.391	237.391	163.202

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS	12.42	8.00	174.299
GROSS ULT., MB & MMF	128.721	570.296	DISCOUNT %	10.00	10.00	163.202
GROSS CUM., MB & MMF	.000	55.413	UNDISCOUNTED PAYOUT, YRS	.00	12.00	153.395
GROSS RES., MB & MMF	128.721	514.883	DISCOUNTED PAYOUT, YRS.	.00	15.00	140.683
NET RES., MB & MMF	10.013	40.051	UNDISCOUNTED NET/INVEST.	.00	20.00	123.622
NET REVENUE, M$	191.375	109.480	DISCOUNTED NET/INVEST.	.00	25.00	110.325
INITIAL PRICE, $	19.050	2.720	RATE-OF-RETURN, PCT.	100.00	35.00	91.049
INITIAL N.I., PCT.	7.678	7.678	INITIAL W.I., PCT.	9.015	50.00	72.622
					70.00	57.729
					100.00	44.723

SWRI INCOME FUND V	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:27
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER: RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	10.5	20.192	133.790	.000	5.632	36.293	.000	18.79	2.71	105.847	98.513	204.359
12-03	11.0	32.918	179.971	.000	5.674	35.108	.000	18.83	2.70	106.842	94.687	201.529
12-04	11.0	25.372	146.791	.000	4.969	31.512	.000	18.81	2.70	93.490	84.945	178.436
12-05	11.0	21.323	127.924	.000	4.507	28.970	.000	18.80	2.69	84.750	78.059	162.809
12-06	11.0	18.665	114.883	.000	4.152	26.925	.000	18.80	2.69	78.051	72.513	150.564
12-07	11.0	16.727	104.936	.000	3.858	25.181	.000	18.79	2.69	72.515	67.777	140.293
12-08	11.0	15.219	96.880	.000	3.605	23.643	.000	18.79	2.69	67.742	63.595	131.337
12-09	11.0	13.992	90.060	.000	3.380	22.249	.000	18.79	2.69	63.506	59.804	123.311
12-10	10.1	11.462	78.313	.000	2.643	18.935	.000	18.87	2.65	49.882	50.212	100.095
12-11	8.0	7.933	64.314	.000	1.231	13.859	.000	19.05	2.56	23.463	35.547	59.010
12-12	8.0	7.329	60.202	.000	1.148	13.061	.000	19.05	2.56	21.867	33.469	55.336
12-13	7.3	6.187	52.735	.000	.778	10.163	.000	19.07	2.66	14.837	27.025	41.861
S TOT	1.0	97.319	1250.800	.000	41.578	285.900	.000	18.83	2.68	782.793	766.147	1548.940
AFTER	1.0	2.011	107.507	.000	.399	22.431	.000	19.06	3.06	7.611	68.600	76.212
TOTAL	1.0	99.330	1358.307	.000	41.977	308.331	.000	18.83	2.71	790.405	834.747	1625.152

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	4.869	7.388	5.701	92.265	94.137	9.44	.000	94.137	94.137	89.483
12-03	4.915	7.102	5.627	82.195	101.691	8.66	.000	101.691	195.827	177.846
12-04	4.301	6.371	4.978	82.195	80.591	9.57	.000	80.591	276.418	241.477
12-05	3.899	5.854	4.540	82.195	66.321	10.34	.000	66.321	342.739	289.074
12-06	3.590	5.439	4.198	82.195	55.142	11.04	.000	55.142	397.881	325.050
12-07	3.336	5.083	3.911	82.195	45.767	11.73	.000	45.767	443.649	352.196
12-08	3.116	4.770	3.661	82.195	37.595	12.42	.000	37.595	481.243	372.470
12-09	2.921	4.485	3.437	82.195	30.272	13.13	.000	30.272	511.515	387.314
12-10	2.295	3.766	2.783	67.809	23.442	13.22	.000	23.442	534.957	397.766
12-11	1.079	2.666	1.623	34.528	19.114	11.27	.000	19.114	554.071	405.509
12-12	1.006	2.510	1.521	34.528	15.770	11.90	.000	15.770	569.841	411.318
12-13	.682	2.027	1.143	25.334	12.674	11.81	.000	12.674	582.516	415.563
S TOT	36.008	57.461	43.123	829.832	582.516	19.59	.000	582.516	582.516	415.563
AFTER	.350	5.145	2.026	53.283	15.408	19.59	.000	15.408	597.923	419.404
TOTAL	36.359	62.606	45.149	883.115	597.923	19.59	.000	597.923	597.923	419.404

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	10.0	4.0	LIFE, YRS.	24.67	8.00	446.087
GROSS ULT., MB & MMF	906.411	6308.618	DISCOUNT %	10.00	10.00	419.404
GROSS CUM., MB & MMF	707.081	4950.311	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	395.790
GROSS RES., MB & MMF	199.330	1358.307	DISCOUNTED PAYOUT, YRS.	.00	15.00	365.105
NET RES., MB & MMF	41.977	308.331	UNDISCOUNTED NET/INVEST.	.00	20.00	323.731
NET REVENUE, M$	790.405	834.747	DISCOUNTED NET/INVEST.	.00	25.00	291.286
INITIAL PRICE, $	18.957	2.762	RATE-OF-RETURN, PCT.	100.00	35.00	243.878
INITIAL N.I., PCT.	17.248	18.739	INITIAL W.I., PCT.	22.166	50.00	198.132
					70.00	160.927
					100.00	128.367

SWRI INCOME FUND V	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:08:45
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER: RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	7.9	144.205	80.511	.000	2.401	21.157	.000	19.16	2.37	45.993	50.239	96.232
12-03	7.0	5.012	55.028	.000	1.181	16.293	.000	18.88	2.33	22.304	37.994	60.298
12-04	4.3	2.908	31.528	.000	.133	4.136	.000	18.90	2.98	2.521	12.309	14.830
12-05	4.0	2.479	26.865	.000	.039	2.815	.000	18.94	3.27	.734	9.210	9.944
12-06	4.0	2.255	24.429	.000	.035	2.558	.000	18.94	3.27	.667	8.365	9.032
12-07	4.0	2.070	22.373	.000	.032	2.332	.000	18.94	3.27	.613	7.620	8.232
12-08	4.0	1.914	20.606	.000	.030	2.130	.000	18.94	3.26	.566	6.953	7.519
12-09	3.8	1.781	18.487	.000	.028	1.762	.000	18.94	3.23	.527	5.700	6.227
12-10	3.0	1.666	15.565	.000	.026	1.095	.000	18.94	3.10	.493	3.396	3.889
12-11	1.8	.664	7.717	.000	.010	.922	.000	18.94	3.27	.196	3.017	3.214
12-12	1.0	.000	2.273	.000	.000	.728	.000	.00	3.43	.000	2.495	2.495
12-13
S TOT	1.0	164.954	305.383	.000	3.916	55.928	.000	19.05	2.63	74.615	147.297	221.912
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	164.954	305.383	.000	3.916	55.928	.000	19.05	2.63	74.615	147.297	221.912

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.550	3.768	2.101	73.704	14.109	13.86	.000	14.109	14.109	13.523
12-03	1.026	2.850	1.594	46.534	8.295	13.35	.000	8.295	22.405	20.748
12-04	.116	.923	.325	8.287	5.179	11.73	.000	5.179	27.584	24.838
12-05	.034	.691	.196	4.810	4.214	11.28	.000	4.214	31.798	27.862
12-06	.031	.627	.178	4.810	3.387	12.23	.000	3.387	35.185	30.073
12-07	.028	.571	.162	4.810	2.661	13.23	.000	2.661	37.846	31.652
12-08	.026	.521	.148	4.810	2.014	14.30	.000	2.014	39.859	32.738
12-09	.024	.427	.124	4.206	1.445	14.87	.000	1.445	41.305	33.448
12-10	.023	.255	.080	2.395	1.137	13.20	.000	1.137	42.441	33.954
12-11	.009	.226	.063	2.395	.521	16.42	.000	.521	42.962	34.169
12-12	.000	.187	.046	2.196	.066	20.03	.000	.066	43.028	34.194
12-13
S TOT	3.867	11.047	5.016	158.954	43.028	20.03	.000	43.028	43.028	34.194
AFTER	.000	.000	.000	.000	.000	20.03	.000	.000	43.028	34.194
TOTAL	3.867	11.047	5.016	158.954	43.028	20.03	.000	43.028	43.028	34.194

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	43.0	2.0	LIFE, YRS.	10.92	8.00	35.615
GROSS ULT., MB & MMF	21326.570	41986.190	DISCOUNT %	10.00	10.00	34.194
GROSS CUM., MB & MMF	21161.620	41680.800	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	32.902
GROSS RES., MB & MMF	164.954	305.383	DISCOUNTED PAYOUT, YRS.	.00	15.00	31.173
NET RES., MB & MMF	3.916	55.928	UNDISCOUNTED NET/INVEST.	.00	20.00	28.742
NET REVENUE, M$	74.615	147.297	DISCOUNTED NET/INVEST.	.00	25.00	26.749
INITIAL PRICE, $	19.436	2.841	RATE-OF-RETURN, PCT.	100.00	35.00	23.682
INITIAL N.I., PCT.	2.002	17.909	INITIAL W.I., PCT.	4.179	50.00	20.522
					70.00	17.774
					100.00	15.205

SWRI INCOME FUND V	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:27
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER: RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	17.8	54.470	174.594	.000	6.947	53.107	.000	18.86	2.58	131.004	136.809	267.813
12-03	16.0	13.624	137.776	.000	5.098	44.375	.000	18.75	2.56	95.605	113.504	209.109
12-04	13.3	11.009	109.239	.000	3.827	30.544	.000	18.72	2.73	71.641	83.317	154.958
12-05	13.0	10.110	100.023	.000	3.524	27.698	.000	18.72	2.75	65.963	76.105	142.068
12-06	13.0	9.451	93.434	.000	3.326	26.039	.000	18.72	2.74	62.268	71.470	133.738
12-07	13.0	8.860	87.562	.000	3.142	24.517	.000	18.72	2.74	58.820	67.214	126.034
12-08	13.0	8.326	82.256	.000	2.969	23.110	.000	18.72	2.74	55.592	63.274	118.866
12-09	12.8	7.837	76.803	.000	2.806	21.607	.000	18.73	2.73	52.551	58.937	111.488
12-10	11.1	6.138	65.917	.000	2.131	17.878	.000	18.81	2.67	40.092	47.726	87.819
12-11	7.8	2.216	46.508	.000	.749	12.809	.000	19.02	2.59	14.241	33.176	47.417
12-12	6.9	1.459	38.994	.000	.694	11.975	.000	19.02	2.59	13.202	31.008	44.209
12-13	5.3	1.000	31.986	.000	.370	8.532	.000	19.01	2.64	7.043	22.566	29.609
S TOT	1.0	234.500	1045.092	.000	35.585	302.192	.000	18.77	2.66	668.023	805.105	1473.128
AFTER	1.0	1.063	103.715	.000	.296	22.016	.000	19.01	3.06	5.622	67.460	73.082
TOTAL	1.0	235.564	1148.807	.000	35.880	324.208	.000	18.77	2.69	673.645	872.565	1546.210

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	6.461	10.260	6.874	164.468	79.750	11.90	.000	79.750	79.750	76.206
12-03	4.398	8.513	5.729	125.495	64.975	11.54	.000	64.975	144.725	132.635
12-04	3.295	6.249	4.219	87.248	53.948	11.33	.000	53.948	198.673	175.215
12-05	3.034	5.708	3.868	83.771	45.688	11.84	.000	45.688	244.360	208.001
12-06	2.864	5.360	3.644	83.771	38.099	12.48	.000	38.099	282.459	232.859
12-07	2.706	5.041	3.436	83.771	31.080	13.14	.000	31.080	313.539	251.297
12-08	2.557	4.746	3.243	83.771	24.549	13.83	.000	24.549	338.089	264.542
12-09	2.417	4.420	3.050	83.167	18.434	14.52	.000	18.434	356.522	273.587
12-10	1.844	3.579	2.406	66.970	13.019	14.64	.000	13.019	369.542	279.397
12-11	.655	2.488	1.266	33.689	9.319	13.21	.000	9.319	378.861	283.178
12-12	.607	2.326	1.182	33.490	6.605	13.98	.000	6.605	385.466	285.613
12-13	.324	1.692	.796	22.182	4.614	13.94	.000	4.614	390.080	287.160
S TOT	31.163	60.383	39.712	951.790	390.080	19.59	.000	390.080	390.080	287.160
AFTER	.259	5.059	1.937	52.346	13.480	19.59	.000	13.480	403.560	290.396
TOTAL	31.422	65.442	41.650	1004.136	403.560	19.59	.000	403.560	403.560	290.396

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	51.0	6.0	LIFE, YRS.	24.67	8.00	307.403
GROSS ULT., MB & MMF	22104.270	47724.520	DISCOUNT %	10.00	10.00	290.396
GROSS CUM., MB & MMF	21868.700	46575.710	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	275.297
GROSS RES., MB & MMF	235.564	1148.807	DISCOUNTED PAYOUT, YRS.	.00	15.00	255.595
NET RES., MB & MMF	35.880	324.208	UNDISCOUNTED NET/INVEST.	.00	20.00	228.851
NET REVENUE, M$	673.645	872.565	DISCOUNTED NET/INVEST.	.00	25.00	207.710
INITIAL PRICE, $	19.415	2.836	RATE-OF-RETURN, PCT.	100.00	35.00	176.512
INITIAL N.I., PCT.	3.193	21.901	INITIAL W.I., PCT.	6.572	50.00	146.032
					70.00	120.972
					100.00	98.849

SWRI INCOME FUND V	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:31
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER: RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.7	9.927	39.707	.000	1.086	4.343	.000	19.19	2.75	20.835	11.943	32.779
12-03	2.0	24.306	97.223	.000	1.757	7.027	.000	19.09	2.73	33.541	19.178	52.718
12-04	2.0	17.270	69.081	.000	1.276	5.104	.000	19.10	2.73	24.371	13.937	38.307
12-05	2.0	13.692	54.767	.000	1.022	4.088	.000	19.10	2.73	19.521	11.164	30.685
12-06	2.0	11.470	45.878	.000	.861	3.445	.000	19.10	2.73	16.450	9.408	25.859
12-07	2.0	9.937	39.747	.000	.749	2.996	.000	19.10	2.73	14.308	8.183	22.491
12-08	2.0	8.807	35.229	.000	.666	2.662	.000	19.11	2.73	12.717	7.273	19.990
12-09	2.0	7.936	31.744	.000	.601	2.404	.000	19.11	2.73	11.482	6.567	18.049
12-10	2.0	6.990	27.960	.000	.538	2.152	.000	19.11	2.73	10.283	5.882	16.165
12-11	2.0	6.381	25.523	.000	.493	1.971	.000	19.11	2.73	9.419	5.388	14.807
12-12	2.0	5.870	23.482	.000	.453	1.814	.000	19.11	2.73	8.665	4.957	13.622
12-13	1.9	5.187	20.749	.000	.408	1.631	.000	19.12	2.73	7.794	4.459	12.252
S TOT	1.0	127.773	511.091	.000	9.909	39.637	.000	19.11	2.73	189.385	108.339	297.724
AFTER	1.0	.948	3.792	.000	.104	.415	.000	19.19	2.75	1.990	1.141	3.130
TOTAL	1.0	128.721	514.883	.000	10.013	40.051	.000	19.11	2.73	191.375	109.480	300.854

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	.958	.896	.928	1.500	28.497	2.37	.000	28.497	28.497	26.800
12-03	1.543	1.438	1.492	3.234	45.011	2.63	.000	45.011	73.507	65.959
12-04	1.121	1.045	1.084	3.234	31.823	3.05	.000	31.823	105.330	91.100
12-05	.898	.837	.868	3.234	24.847	3.43	.000	24.847	130.176	108.936
12-06	.757	.706	.732	3.234	20.430	3.78	.000	20.430	150.607	122.264
12-07	.658	.614	.637	3.234	17.348	4.12	.000	17.348	167.955	132.551
12-08	.585	.545	.566	3.234	15.059	4.44	.000	15.059	183.014	140.667
12-09	.528	.493	.511	3.234	13.283	4.76	.000	13.283	196.297	147.175
12-10	.473	.441	.458	3.234	11.559	5.14	.000	11.559	207.856	152.324
12-11	.433	.404	.419	3.234	10.316	5.47	.000	10.316	218.172	156.500
12-12	.399	.372	.386	3.234	9.232	5.81	.000	9.232	227.404	159.898
12-13	.359	.334	.347	3.152	8.060	6.17	.000	8.060	235.464	162.598
S TOT	8.712	8.125	8.427	36.996	235.464	6.96	.000	235.464	235.464	162.598
AFTER	.092	.086	.089	.938	1.927	6.96	.000	1.927	237.391	163.202
TOTAL	8.803	8.211	8.515	37.934	237.391	6.96	.000	237.391	237.391	163.202

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	12.42	8.00	174.299
GROSS ULT., MB & MMF	128.721	570.296	DISCOUNT %	10.00	10.00	163.202
GROSS CUM., MB & MMF	.000	55.413	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	153.395
GROSS RES., MB & MMF	128.721	514.883	DISCOUNTED PAYOUT, YRS.	.00	15.00	140.683
NET RES., MB & MMF	10.013	40.051	UNDISCOUNTED NET/INVEST.	.00	20.00	123.622
NET REVENUE, M$	191.375	109.480	DISCOUNTED NET/INVEST.	.00	25.00	110.325
INITIAL PRICE, $	19.050	2.720	RATE-OF-RETURN, PCT.	100.00	35.00	91.049
INITIAL N.I., PCT.	7.678	7.678	INITIAL W.I., PCT.	9.015	50.00	72.622
					70.00	57.729
					100.00	44.723

SWRI INCOME FUND V	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:38
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER: RSC0102  IFV

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	18.4	164.397	214.301	.000	8.033	57.450	.000	18.90	2.59	151.839	148.752	300.591
12-03	18.0	37.930	234.999	.000	6.855	51.402	.000	18.84	2.58	129.146	132.682	261.828
12-04	15.3	28.280	178.320	.000	5.103	35.649	.000	18.82	2.73	96.011	97.254	193.266
12-05	15.0	23.802	154.789	.000	4.546	31.786	.000	18.80	2.75	85.484	87.269	172.753
12-06	15.0	20.920	139.313	.000	4.187	29.483	.000	18.80	2.74	78.718	80.878	159.597
12-07	15.0	18.797	127.309	.000	3.891	27.513	.000	18.80	2.74	73.128	75.397	148.525
12-08	15.0	17.134	117.486	.000	3.635	25.773	.000	18.79	2.74	68.309	70.547	138.856
12-09	14.8	15.773	108.547	.000	3.407	24.011	.000	18.79	2.73	64.033	65.504	129.537
12-10	13.1	13.128	93.878	.000	2.669	20.031	.000	18.87	2.68	50.375	53.608	103.984
12-11	9.8	8.597	72.031	.000	1.242	14.780	.000	19.05	2.61	23.660	38.564	62.224
12-12	8.9	7.329	62.476	.000	1.148	13.789	.000	19.05	2.61	21.867	35.964	57.831
12-13	7.3	6.187	52.735	.000	.778	10.163	.000	19.07	2.66	14.837	27.025	41.861
S TOT	1.0	362.273	1556.183	.000	45.494	341.829	.000	18.85	2.67	857.408	913.444	1770.853
AFTER	1.0	2.011	107.507	.000	.399	22.431	.000	19.06	3.06	7.611	68.600	76.212
TOTAL	1.0	364.284	1663.689	.000	45.893	364.259	.000	18.85	2.70	865.020	982.045	1847.064

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-03	7.419	11.156	7.802	165.968	108.246	10.92	.000	108.246	108.246	103.006
12-03	5.941	9.951	7.221	128.729	109.986	9.85	.000	109.986	218.232	198.594
12-04	4.417	7.294	5.303	90.482	85.770	9.73	.000	85.770	304.002	266.315
12-05	3.932	6.545	4.736	87.005	70.534	10.38	.000	70.534	374.537	316.936
12-06	3.621	6.066	4.376	87.005	58.529	11.10	.000	58.529	433.066	355.123
12-07	3.364	5.655	4.073	87.005	48.428	11.81	.000	48.428	481.494	383.848
12-08	3.142	5.291	3.809	87.005	39.609	12.52	.000	39.609	521.103	405.209
12-09	2.946	4.913	3.561	86.401	31.717	13.20	.000	31.717	552.820	420.762
12-10	2.317	4.021	2.863	70.204	24.578	13.22	.000	24.578	577.398	431.720
12-11	1.088	2.892	1.685	36.924	19.635	11.49	.000	19.635	597.033	439.678
12-12	1.006	2.697	1.567	36.724	15.837	12.19	.000	15.837	612.870	445.511
12-13	.682	2.027	1.143	25.334	12.674	11.81	.000	12.674	625.544	449.757
S TOT	39.875	68.508	48.139	988.786	625.544	19.59	.000	625.544	625.544	449.757
AFTER	.350	5.145	2.026	53.283	15.408	19.59	.000	15.408	640.951	453.598
TOTAL	40.225	73.653	50.165	1042.069	640.952	19.59	.000	640.952	640.951	453.598

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	53.0	6.0	LIFE, YRS.	24.67	8.00	481.702
GROSS ULT., MB & MMF	22232.990	48294.810	DISCOUNT %	10.00	10.00	453.598
GROSS CUM., MB & MMF	21868.700	46631.120	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	428.692
GROSS RES., MB & MMF	364.284	1663.689	DISCOUNTED PAYOUT, YRS.	.00	15.00	396.278
NET RES., MB & MMF	45.893	364.259	UNDISCOUNTED NET/INVEST.	.00	20.00	352.473
NET REVENUE, M$	865.020	982.045	DISCOUNTED NET/INVEST.	.00	25.00	318.036
INITIAL PRICE, $	19.388	2.807	RATE-OF-RETURN, PCT.	100.00	35.00	267.561
INITIAL N.I., PCT.	3.533	18.270	INITIAL W.I ., PCT.	6.815	50.00	218.654
					70.00	178.701
					100.00	143.571

APPENDIX B3

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWRI Income Fund VI (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 48 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 92.0 percent of the total net remaining liquid hydrocarbon reserves and 99.1 percent of the total net remaining gas reserves. The properties that we reviewed represent 96.7 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWRI Income Fund VI

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		64,332		27,181		35,610		127,123
Gas—MMCF		4,907		67		347		5,321
Income Data
Future Gross Revenue	$	10,708,249	$	625,869	$	1,435,109	$	12,769,227
Deductions		2,693,791		298,183		238,333		3,230,307
Future Net Income (FNI)	$	8,014,458	$	327,686	$	1,196,776	$	9,538,920
Discounted FNI @ 10%	$	3,275,767	$	237,723	$	866,908	$	4,380,398

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		6,214		0		4,833		11,047
Gas—MMCF		43		0		4		47
Income Data
Future Gross Revenue	$	232,324	$	0	$	85,497	$	317,821
Deductions		54,040		0		33,842		87,882
Future Net Income (FNI)	$	178,284	$	0	$	51,655	$	229,939
Discounted FNI @ 10%	$	109,172	$	0	$	41,208	$	150,380
Total Net Reserves
Oil/Condensate—Barrels		70,546		27,181		40,443		138,170
Gas—MMCF		4,950		67		351		5,368
Income Data
Future Gross Revenue	$	10,940,573	$	625,869	$	1,520,606	$	13,087,048
Deductions		2,747,831		298,183		272,175		3,318,189
Future Net Income (FNI)	$	8,192,742	$	327,686	$	1,248,431	$	9,768,859
Discounted FNI @ 10%	$	3,384,939	$	237,723	$	908,116	$	4,530,778

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)    Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A)    that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B)    the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion?... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 8.0 percent of the total net remaining liquid hydrocarbon reserves and 0.9 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SWRI INCOME FUND VI	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:36
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	28.9	62.981	844.362	.000	13.429	302.924	.000	18.65	2.20	250.426	667.790	918.216
12-03	25.3	45.965	732.421	.000	9.048	272.978	.000	18.75	2.20	169.632	600.232	769.864
12-04	23.8	39.223	678.515	.000	7.430	255.136	.000	18.83	2.19	139.945	559.263	699.207
12-05	22.0	33.430	629.563	.000	5.868	238.511	.000	18.88	2.18	110.817	520.995	631.812
12-06	22.0	30.362	592.480	.000	5.404	225.429	.000	18.90	2.18	102.162	491.952	594.114
12-07	20.3	21.522	552.995	.000	4.629	212.974	.000	19.11	2.18	88.480	464.198	552.678
12-08	18.9	15.623	518.182	.000	4.004	201.398	.000	19.28	2.18	77.185	438.406	515.591
12-09	17.1	13.218	463.293	.000	3.206	181.836	.000	19.18	2.14	61.490	388.579	450.069
12-10	14.3	10.855	417.654	.000	2.706	169.150	.000	19.17	2.12	51.875	359.144	411.019
12-11	12.3	8.199	387.100	.000	1.955	158.710	.000	19.13	2.11	37.403	335.490	372.893
12-12	10.9	6.455	364.018	.000	1.468	148.631	.000	19.11	2.11	28.048	313.139	341.187
12-13	10.0	6.093	327.599	.000	1.311	124.140	.000	19.18	2.08	25.132	258.327	283.459
S TOT	1.7	293.925	6508.180	.000	60.459	2491.818	.000	18.90	2.17	1142.596	5397.513	6540.110
AFTER	1.7	13.786	6253.454	.000	3.873	2414.859	.000	18.97	2.04	73.456	4924.798	4998.254
TOTAL	1.7	307.712	12761.630	.000	64.332	4906.677	.000	18.90	2.10	1216.052	10322.310	11538.360

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	11.520	50.084	26.038	265.085	565.490	5.52	.000	565.490	565.490	539.872
12-03	7.803	45.017	21.811	187.409	507.824	4.80	.000	507.824	1073.313	980.538
12-04	6.437	41.945	19.789	167.895	463.141	4.73	.000	463.141	1536.455	1345.882
12-05	5.098	39.075	17.862	144.514	425.264	4.53	.000	425.264	1961.719	1650.836
12-06	4.699	36.896	16.780	144.514	391.224	4.72	.000	391.224	2352.944	1905.875
12-07	4.070	34.815	15.485	138.254	360.053	4.80	.000	360.053	2712.997	2119.253
12-08	3.551	32.880	14.364	132.579	332.217	4.88	.000	332.217	3045.214	2298.235
12-09	2.829	29.143	12.533	97.523	308.041	4.24	.000	308.041	3353.255	2449.092
12-10	2.386	26.936	11.441	82.382	287.874	3.99	.000	287.874	3641.129	2577.251
12-11	1.721	25.162	10.371	65.379	270.260	3.61	.000	270.260	3911.389	2686.627
12-12	1.290	23.485	9.484	55.331	251.597	3.41	.000	251.597	4162.985	2779.243
12-13	1.156	19.375	7.880	49.677	205.372	3.55	.000	205.372	4368.357	2847.933
S TOT	52.559	404.813	183.838	1530.541	4368.357	4.33	.000	4368.357	4368.357	2847.933
AFTER	3.379	369.360	138.742	840.670	3646.104	4.33	.000	3646.104	8014.462	3275.767
TOTAL	55.938	774.173	322.580	2371.211	8014.461	4.33	.000	8014.461	8014.462	3275.767

	OIL	GAS			P.W.  %	P.W., M$
GROSS WELLS	21.0	8.0	LIFE, YRS.	68.00	8.00	3679.057
GROSS ULT., MB & MMF	7827.998	49451.560	DISCOUNT %	10.00	10.00	3275.766
GROSS CUM., MB & MMF	7520.286	36689.920	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	2961.220
GROSS RES., MB & MMF	307.712	12761.630	DISCOUNTED PAYOUT, YRS.	.00	15.00	2599.471
NET RES., MB & MMF	64.332	4906.678	UNDISCOUNTED NET/INVEST.	.00	20.00	2176.736
NET REVENUE, M$	1216.051	10322.310	DISCOUNTED NET/INVEST.	.00	25.00	1885.439
INITIAL PRICE, $	18.096	2.294	RATE-OF-RETURN, PCT.	100.00	35.00	1507.864
INITIAL N.I., PCT.	21.362	35.789	INITIAL W.I., PCT.	34.786	50.00	1185.084
					70.00	945.799
					100.00	750.033

SWRI INCOME FUND VI	Date:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	Time:	16:47:42
PNP RESERVES	DBS File:	SWR0102
$19.84/BO AND $2.57/MCF    NYMEX	Setup File:	BASE0102
	Seq Number:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.915	4.110	.000	.089	.358	.000	18.07	2.60	1.610	.931	2.541
12-03	6.8	38.765	183.557	.000	5.529	15.169	.000	18.12	2.51	100.200	38.085	138.284
12-04	9.0	38.289	195.860	.000	6.245	15.717	.000	18.14	2.49	113.252	39.083	152.335
12-05	8.4	28.453	143.376	.000	4.897	11.695	.000	18.14	2.49	88.835	29.136	117.971
12-06	7.3	20.851	105.614	.000	3.811	8.743	.000	18.14	2.50	69.140	21.827	90.966
12-07	6.0	15.245	78.612	.000	2.924	6.515	.000	18.15	2.50	53.071	16.295	69.365
12-08	4.1	9.579	48.310	.000	2.213	4.293	.000	18.16	2.49	40.173	10.701	50.874
12-09	1.5	2.723	22.765	.000	.821	1.779	.000	18.18	2.42	14.932	4.297	19.229
12-10	.3	1.000	7.761	.000	.180	.954	.000	18.09	2.53	3.252	2.414	5.665
12-11	.0	.849	3.708	.000	.159	.695	.000	18.07	2.60	2.876	1.808	4.684
12-12	.0	.764	3.370	.000	.143	.632	.000	18.07	2.60	2.589	1.643	4.231
12-13	.0	.688	3.062	.000	.129	.574	.000	18.07	2.60	2.330	1.493	3.823
S TOT	.0	158.120	800.105	.000	27.141	67.123	.000	18.14	2.50	492.258	167.710	659.968
AFTER	.0	.214	.957	.000	.040	.179	.000	18.07	2.60	.724	.467	1.190
TOTAL	.0	158.334	801.063	.000	27.181	67.303	.000	18.14	.2.50	492.982	168.177	661.159

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.074	.070	.072	.502	1.824	4.82	.000	1.824	1.824	1.671
12-03	4.609	2.856	3.925	25.639	101.255	4.60	50.000	51.255	53.079	44.865
12-04	5.210	2.931	4.326	38.140	101.728	5.71	.000	101.728	154.807	125.279
12-05	4.086	2.185	3.351	37.471	70.877	6.88	.000	70.877	225.684	176.235
12-06	3.180	1.637	2.584	35.874	47.691	8.21	.000	47.691	273.374	207.441
12-07	2.441	1.222	1.971	33.445	30.286	9.75	.000	30.286	303.660	225.425
12-08	1.848	.803	1.447	30.406	16.370	11.78	.000	16.370	320.031	234.345
12-09	.687	.322	.547	14.514	3.159	14.38	.000	3.159	323.190	235.902
12-10	.150	.181	.160	3.416	1.758	11.53	.000	1.758	324.948	236.687
12-11	.132	.136	.132	3.000	1.284	12.36	.000	1.284	326.232	237.208
12-12	.119	.123	.120	3.000	.870	13.53	.000	.870	327.101	237.528
12-13	.107	.112	.108	3.000	.495	14.81	.000	.495	327.597	237.695
S TOT	22.644	12.578	18.742	228.407	377.597	15.75	50.000	327.597	327.597	237.695
AFTER	.033	.035	.034	1.000	.088	15.75	.000	.088	327.685	237.723
TOTAL	22.677	12.613	18.776	229.407	377.685	15.75	50.000	327.685	327.685	237.723

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	8.0	1.0	LIFE, YRS.	12.33	8.00	252.481
GROSS ULT., MB & MMF	158.334	867.748	DISCOUNT %	10.00	10.00	237.723
GROSS CUM., MB & MMF	.000	66.685	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	224.221
GROSS RES., MB & MMF	158.334	801.063	DISCOUNTED PAYOUT, YRS.	.00	15.00	206.027
NET RES., MB & MMF	27.181	67.303	UNDISCOUNTED NET/INVEST.	7.55	20.00	180.281
NET REVENUE, M$	492.982	168.177	DISCOUNTED NET/INVEST.	6.44	25.00	159.091
INITIAL PRICE, $	18.128	2.435	RATE-OF-RETURN, PCT.	100.00	35.00	126.601
INITIAL N.I., PCT.	14.938	8.111	INITIAL W.I., PCT.	14.681	50.00	93.882
					70.00	66.987
					100.00	44.253

SWRI INCOME FUND VI	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:49
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.9	19.372	502.359	.000	1.051	42.877	.000	18.57	2.42	19.520	103.896	123.416
12-03	13.3	146.449	1309.793	.000	7.445	89.277	.000	18.33	2.50	136.464	222.958	359.423
12-04	14.0	107.872	935.011	.000	5.528	61.666	.000	18.34	2.51	101.372	155.078	256.450
12-05	14.0	83.118	691.530	.000	4.252	43.688	.000	18.34	2.53	77.975	110.725	188.700
12-06	14.0	67.956	531.093	.000	3.476	32.046	.000	18.33	2.56	63.721	81.891	145.612
12-07	13.7	57.601	408.993	.000	2.946	23.034	.000	18.33	2.59	54.004	59.616	113.620
12-08	12.0	49.863	288.245	.000	2.539	13.147	.000	18.33	2.71	46.533	35.568	82.100
12-09	12.0	44.286	249.175	.000	2.262	11.472	.000	18.32	2.70	41.450	30.933	72.383
12-10	12.0	39.632	217.001	.000	2.040	10.123	.000	18.32	2.69	37.364	27.199	64.563
12-11	10.2	30.818	170.769	.000	1.473	7.486	.000	18.11	2.70	26.681	20.178	46.859
12-12	8.6	24.208	133.100	.000	1.058	5.464	.000	17.98	2.70	19.018	14.744	33.762
12-13	6.9	19.760	81.676	.000	.818	3.393	.000	18.10	2.60	14.807	8.832	23.639
S TOT	4.0	690.936	5518.747	.000	34.890	343.673	.000	18.31	2.54	638.908	871.618	1510.527
AFTER	4.0	15.752	63.117	.000	.720	2.884	.000	18.07	2.60	13.006	7.498	20.504
TOTAL	4.0	706.688	5581.863	.000	35.610	346.557	.000	18.31	2.54	651.914	879.116	1531.031

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.898	7.792	3.442	4.629	106.656	2.04	.000	106.656	106.656	99.214
12-03	6.277	16.722	10.093	19.137	307.194	2.34	.000	307.194	413.850	366.088
12-04	4.663	11.631	7.205	20.294	212.658	2.77	.000	212.658	626.507	534.208
12-05	3.587	8.304	5.304	20.294	151.211	3.25	.000	151.211	777.718	642.838
12-06	2.931	6.142	4.096	20.294	112.149	3.80	.000	112.149	889.867	716.062
12-07	2.484	4.471	3.200	19.810	83.655	4.42	.000	83.655	973.522	765.756
12-08	2.140	2.668	2.319	17.393	57.580	5.18	.000	57.580	1031.102	796.800
12-09	1.907	2.320	2.045	17.393	48.718	5.67	.000	48.718	1079.821	820.676
12-10	1.719	2.040	1.824	17.393	41.587	6.16	.000	41.587	1121.408	839.203
12-11	1.227	1.513	1.324	13.370	29.425	6.41	.000	29.425	1150.833	851.156
12-12	.875	1.106	.953	9.964	20.864	6.55	.000	20.864	1171.697	858.853
12-13	.681	.662	.669	7.665	13.962	6.99	.000	13.962	1185.658	863.526
S TOT	29.390	65.371	42.473	187.634	1185.658	11.30	.000	1185.658	1185.658	863.526
AFTER	.598	.562	.580	7.646	11.117	11.30	.000	11.117	1196.775	866.908
TOTAL	29.988	65.934	43.053	195.280	1196.775	11.30	.000	1196.775	1196.775	866.908

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	11.0	3.0	LIFE, YRS.	13.17	8.00	918.420
GROSS ULT., MB & MMF	714.880	5745.965	DISCOUNT %	10.00	10.00	866.908
GROSS CUM., MB & MMF	8.192	164.102	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	820.589
GROSS RES., MB & MMF	706.688	5581.863	DISCOUNTED PAYOUT, YRS.	.00	15.00	759.320
NET RES., MB & MMF	35.610	346.557	UNDISCOUNTED NET/INVEST.	.00	20.00	674.629
NET REVENUE, M$	651.914	879.116	DISCOUNTED NET/INVEST.	.00	25.00	606.414
INITIAL PRICE, $	18.299	2.583	RATE-OF-RETURN, PCT.	100.00	35.00	503.616
INITIAL N.I., PCT.	4.975	7.078	INITIAL W.I., PCT.	6.997	50.00	400.631
					70.00	314.108
					100.00	236.725

SWRI INCOME FUND VI	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:55
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE:  1/02

-END-   MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	31.9	83.269	1350.831	.000	14.569	346.159	.000	18.64	2.23	271.556	772.617	1044.174
12-03	45.5	231.179	2225.771	.000	22.022	377.423	.000	18.45	2.28	406.296	861.275	1267.571
12-04	46.8	185.384	1809.386	.000	19.203	332.519	.000	18.46	2.27	354.569	753.423	1107.992
12-05	44.4	145.001	1464.470	.000	15.018	293.894	.000	18.49	2.25	277.627	660.856	938.483
12-06	43.3	119.169	1229.187	.000	12.691	266.218	.000	18.52	2.24	235.023	595.670	830.693
12-07	39.9	94.368	1040.600	.000	10.500	242.524	.000	18.62	2.23	195.555	540.109	735.663
12-08	35.0	75.066	854.737	.000	8.756	218.837	.000	18.72	2.21	163.891	484.674	648.565
12-09	30.6	60.226	735.233	.000	6.290	195.087	.000	18.74	2.17	117.872	423.808	541.680
12-10	26.6	51.486	642.416	.000	4.926	180.227	.000	18.78	2.16	92.490	388.757	481.247
12-11	22.4	39.866	561.576	.000	3.587	166.892	.000	18.67	2.14	66.960	357.475	424.435
12-12	19.5	31.427	500.487	.000	2.669	154.727	.000	18.60	2.13	49.654	329.526	379.180
12-13	16.9	26.541	412.337	.000	2.258	128.108	.000	18.72	2.10	42.269	268.652	310.921
S  TOT	1.7	1142.982	12827.030	.000	122.489	2902.614	.000	18.56	2.22	2273.763	6436.842	8710.605
AFTER	1.7	29.752	6317.528	.000	4.633	2417.923	.000	18.82	2.04	87.185	4932.763	5019.948
TOTAL	1.7	1172.733	19144.560	.000	127.122	5320.536	.000	18.57	2.14	2360.948	11369.600	13730.550

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	12.492	57.946	29.552	270.215	673.969	5.12	.000	673.969	673.969	640.757
12-03	18.690	64.596	35.828	232.185	916.273	4.14	50.000	866.273	1540.242	1391.492
12-04	16.310	56.507	31.319	226.329	777.527	4.43	.000	777.527	2317.768	2005.368
12-05	12.771	49.564	26.517	202.278	647.352	4.55	.000	647.352	2965.120	2469.908
12-06	10.811	44.675	23.461	200.681	551.065	4.90	.000	551.065	3516.185	2829.379
12-07	8.996	40.508	20.656	191.510	473.994	5.14	.000	473.994	3990.178	3110.434
12-08	7.539	36.351	18.130	180.378	406.168	5.36	.000	406.168	4396.347	3329.379
12-09	5.422	31.786	15.124	129.429	359.919	4.68	.000	359.919	4756.265	3505.670
12-10	4.255	29.157	13.426	103.191	331.219	4.29	.000	331.219	5087.485	3653.141
12-11	3.080	26.811	11.827	81.749	300.968	3.93	.000	300.968	5388.453	3774.991
12-12	2.284	24.714	10.557	68.295	273.330	3.72	.000	273.330	5661.783	3875.624
12-13	1.944	20.149	8.657	60.342	219.829	3.86	.000	219.829	5881.612	3949.153
S TOT	104.593	482.763	245.054	1946.583	5931.612	4.33	50.000	5881.612	5881.612	3949.153
AFTER	4.011	369.957	139.356	849.316	3657.309	4.33	.000	3657.309	9538.920	4380.397
TOTAL	108.604	852.720	384.409	2795.899	9588.920	4.33	50.000	9538.920	9538.920	4380.397

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	40.0	12.0	LIFE, YRS.	68.00	8.00	4849.959
GROSS ULT., MB & MMF	8701.212	56065.260	DISCOUNT %	10.00	10.00	4380.397
GROSS CUM., MB & MMF	7528.478	36920.710	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	4006.029
GROSS RES., MB & MMF	1172.734	19144.560	DISCOUNTED PAYOUT, YRS.	.00	15.00	3564.818
NET RES., MB & MMF	127.122	5320.537	UNDISCOUNTED NET/INVEST.	191.78	20.00	3031.647
NET REVENUE, M$	2360.948	11369.600	DISCOUNTED NET/INVEST.	101.27	25.00	2650.944
INITIAL PRICE, $	18.223	2.481	RATE-OF-RETURN, PCT.	100.00	35.00	2138.080
INITIAL N.I., PCT.	10.379	15.792	INITIAL W.I., PCT.	14.972	50.00	1679.597
					70.00	1326.893
					100.00	1031.011

SWRI INCOME FUND VI	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:09:04
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	73.3	422.591	1650.458	.000	2.385	9.167	.000	17.52	2.82	41.779	25.883	67.662
12-03	68.8	218.811	1401.206	.000	.559	5.021	.000	18.96	2.97	10.605	14.895	25.501
12-04	67.2	184.309	1208.732	.000	.483	4.365	.000	18.94	2.98	9.144	12.994	22.138
12-05	64.2	155.817	1042.788	.000	.417	3.791	.000	18.92	2.99	7.892	11.325	19.216
12-06	58.9	130.829	891.237	.000	.358	3.276	.000	18.89	3.00	6.773	9.819	16.592
12-07	52.0	107.944	751.243	.000	.308	2.815	.000	18.86	3.01	5.816	8.483	14.299
12-08	48.3	90.956	652.512	.000	.262	2.471	.000	18.83	3.03	4.938	7.481	12.419
12-09	45.6	76.824	569.412	.000	.229	2.135	.000	18.80	3.03	4.306	6.463	10.769
12-10	40.3	61.311	479.579	.000	.189	1.685	.000	18.77	3.00	3.544	5.055	8.600
12-11	38.2	52.517	418.978	.000	.156	1.403	.000	18.72	3.11	2.924	4.368	7.292
12-12	29.8	41.372	343.829	.000	.124	1.107	.000	18.63	3.23	2.313	3.575	5.889
12-13	24.2	34.745	285.461	.000	.104	.686	.000	18.54	3.27	1.931	2.246	4.177
S TOT	1.8	1578.026	9695.436	.000	5.576	37.923	.000	18.29	2.97	101.965	112.589	214.553
AFTER	1.8	202.627	2443.219	.000	.638	5.499	.000	18.46	3.88	11.775	21.324	33.099
TOTAL	1.8	1780.653	12138.660	.000	6.214	43.421	.000	18.30	3.08	113.740	133.912	247.653

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	1.984	1.939	1.797	36.000	25.942	10.66	.000	25.942	25.942	24.793
12-03	.490	1.115	.672	1.576	21.647	2.76	.000	21.647	47.589	43.587
12-04	.423	.972	.582	1.565	18.596	2.93	.000	18.596	66.185	58.263
12-05	.365	.847	.503	1.469	16.032	3.04	.000	16.032	82.216	69.765
12-06	.314	.735	.432	1.394	13.718	3.18	.000	13.718	95.934	78.714
12-07	.269	.635	.375	1.243	11.777	3.24	.000	11.777	107.711	85.696
12-08	.229	.560	.324	1.233	10.074	3.48	.000	10.074	117.785	91.125
12-09	.199	.484	.281	1.082	8.723	3.50	.000	8.723	126.508	95.401
12-10	.164	.378	.226	.629	7.202	2.97	.000	7.202	133.711	98.609
12-11	.136	.327	.190	.629	6.011	3.29	.000	6.011	139.722	101.046
12-12	.107	.267	.152	.579	4.783	3.58	.000	4.783	144.505	102.808
12-13	.090	.167	.110	.030	3.779	1.82	.000	3.779	148.284	104.073
S TOT	4.770	8.425	5.644	47.430	148.284	2.72	.000	148.284	148.284	104.073
AFTER	.553	1.580	.785	.182	29.999	2.72	.000	29.999	178.284	109.172
TOTAL	5.324	10.005	6.428	47.612	178.284	2.72	.000	178.284	178.284	109.172

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	100.0	5.0	LIFE, YRS.	68.00	8.00	117.692
GROSS ULT., MB & MMF	29198.180	100130.200	DISCOUNT    %	10.00	10.00	109.172
GROSS CUM., MB & MMF	27417.530	87991.520	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	101.958
GROSS RES., MB & MMF	1780.653	12138.660	DISCOUNTED PAYOUT, YRS.	.00	15.00	92.975
NET RES., MB & MMF	6.214	43.421	UNDISCOUNTED NET/INVEST.	.00	20.00	81.449
NET REVENUE, M$	113.740	133.912	DISCOUNTED NET/INVEST.	.00	25.00	72.799
INITIAL PRICE, $	19.270	3.090	RATE-OF-RETURN, PCT.	100.00	35.00	60.654
INITIAL N.I., PCT.	2.279	2.708	INITIAL W.I., PCT.	2.542	50.00	49.378
					70.00	40.457
					100.00	32.791

SWRI INCOME FUND VI	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:09:05
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.8	19.112	15.289	.000	1.108	.886	.000	16.72	2.35	18.527	2.083	20.610
12-03	1.0	13.014	10.411	.000	.755	.604	.000	16.72	2.35	12.615	1.418	14.034
12-04	1.0	10.730	8.584	.000	.622	.498	.000	16.72	2.35	10.402	1.170	11.571
12-05	1.0	9.121	7.297	.000	.529	.423	.000	16.72	2.35	8.842	.994	9.836
12-06	1.0	7.753	6.202	.000	.449	.360	.000	16.72	2.35	7.515	.845	8.360
12-07	1.0	6.590	5.272	.000	.382	.306	.000	16.72	2.35	6.388	.718	7.106
12-08	1.0	5.601	4.481	.000	.325	.260	.000	16.72	2.35	5.430	.611	6.040
12-09	1.0	4.761	3.809	.000	.276	.221	.000	16.72	2.35	4.615	.519	5.134
12-10	1.0	4.047	3.238	.000	.235	.188	.000	16.72	2.35	3.923	.441	4.364
12-11	1.0	2.632	2.105	.000	.153	.122	.000	16.72	2.35	2.551	.287	2.838
12-12
12-13
S TOT	1.0	83.359	66.688	.000	4.833	3.866	.000	16.72	2.35	80.808	9.086	89.895
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	83.359	66.688	.000	4.833	3.866	.000	16.72	2.35	80.808	9.086	89.895

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.852	.156	.588	2.469	16.544	3.24	.000	16.544	16.544	15.671
12-03	.580	.106	.400	3.292	9.654	5.12	.000	9.654	26.199	24.070
12-04	.478	.088	.330	3.292	7.383	5.94	.000	7.383	33.582	29.900
12-05	.407	.075	.281	3.292	5.782	6.76	.000	5.782	39.363	34.052
12-06	.346	.063	.239	3.292	4.420	7.73	.000	4.420	43.784	36.938
12-07	.294	.054	.203	3.292	3.264	8.87	.000	3.264	47.047	38.876
12-08	.250	.046	.172	3.292	2.280	10.22	.000	2.280	49.327	40.107
12-09	.212	.039	.146	3.292	1.444	11.80	.000	1.444	50.772	40.817
12-10	.180	.033	.125	3.292	.734	13.65	.000	.734	51.506	41.146
12-11	.117	.022	.081	2.469	.149	15.55	.000	.149	51.654	41.208
12-12
12-13
S TOT	3.717	.681	2.565	31.277	51.654	15.55	.000	51.654	51.654	41.208
AFTER	.000	.000	.000	.000	.000	15.55	.000	.000	51.654	41.208
TOTAL	3.717	.681	2.565	31.277	51.654	15.55	.000	51.654	51.654	41.208

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	9.75	8.00	42.920
GROSS ULT., MB & MMF	83.359	66.688	DISCOUNT %	10.00	10.00	41.208
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	39.640
GROSS RES., MB & MMF	83.359	66.688	DISCOUNTED PAYOUT, YRS.	.00	15.00	37.524
NET RES., MB & MMF	4.833	3.866	UNDISCOUNTED NET/INVEST.	.00	20.00	34.515
NET REVENUE, M$	80.808	9.086	DISCOUNTED NET/INVEST.	.00	25.00	32.016
INITIAL PRICE, $	16.720	2.350	RATE-OF-RETURN, PCT.	100.00	35.00	28.114
INITIAL N.I ., PCT.	5.798	5.798	INITIAL W.I., PCT.	6.261	50.00	24.023
					70.00	20.417
					100.00	17.012

SWRI INCOME FUND VI	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:09:11
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	74.0	441.702	1665.748	.000	3.493	10.054	.000	17.26	2.78	60.306	27.967	88.272
12-03	69.8	231.825	1411.617	.000	1.314	5.625	.000	17.67	2.90	23.221	16.314	39.534
12-04	68.2	195.040	1217.316	.000	1.105	4.863	.000	17.69	2.91	19.546	14.164	33.710
12-05	65.2	164.938	1050.085	.000	.946	4.214	.000	17.69	2.92	16.733	12.319	29.052
12-06	59.9	138.582	897.440	.000	.808	3.636	.000	17.68	2.93	14.288	10.664	24.953
12-07	53.0	114.534	756.515	.000	.690	3.120	.000	17.68	2.95	12.204	9.202	21.405
12-08	49.3	96.558	656.993	.000	.587	2.731	.000	17.66	2.96	10.368	8.092	18.459
12-09	46.6	81.585	573.221	.000	.505	2.356	.000	17.66	2.96	8.922	6.982	15.903
12-10	41.3	65.358	482.816	.000	.423	1.873	.000	17.63	2.93	7.467	5.496	12.964
12-11	38.9	55.149	421.083	.000	.309	1.525	.000	17.73	3.05	5.475	4.655	10.130
12-12	29.8	41.372	343.829	.000	.124	1.107	.000	18.63	3.23	2.313	3.575	5.889
12-13	24.2	34.745	285.461	.000	.104	.686	.000	18.54	3.27	1.931	2.246	4.177
S TOT	1.8	1661.385	9762.123	.000	10.409	41.789	.000	17.56	2.91	182.773	121.675	304.448
AFTER	1.8	202.627	2443.219	.000	.638	5.499	.000	18.46	3.88	11.775	21.324	33.099
TOTAL	1.8	1864.012	12205.340	.000	11.047	47.288	.000	17.61	3.02	194.549	142.999	337.547

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.836	2.095	2.385	38.470	42.486	8.86	.000	42.486	42.486	40.464
12-03	1.071	1.221	1.073	4.868	31.301	3.66	.000	31.301	73.788	67.656
12-04	.901	1.060	.912	4.858	25.979	4.04	.000	25.979	99.766	88.163
12-05	.772	.922	.784	4.761	21.813	4.39	.000	21.813	121.579	103.816
12-06	.659	.798	.671	4.686	18.139	4.82	.000	18.139	139.718	115.652
12-07	.563	.689	.577	4.536	15.040	5.26	.000	15.040	154.758	124.572
12-08	.478	.606	.496	4.525	12.354	5.86	.000	12.354	167.112	131.233
12-09	.412	.522	.427	4.374	10.168	6.39	.000	10.168	177.280	136.218
12-10	.345	.411	.350	3.921	7.936	6.83	.000	7.936	185.216	139.755
12-11	.253	.348	.271	3.098	6.160	7.05	.000	6.160	191.376	142.254
12-12	.107	.267	.152	.579	4.783	3.58	.000	4.783	196.160	144.016
12-13	.090	.167	.110	.030	3.779	1.82	.000	3.779	199.939	145.281
S TOT	8.487	9.107	8.208	78.707	199.939	2.72	.000	199.939	199.939	145.281
AFTER	.553	1.580	.785	.182	29.999	2.72	.000	29.999	229.938	150.379
TOTAL	9.041	10.687	8.993	78.889	229.938	2.72	.000	229.938	229.938	150.379

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	101.0	5.0	LIFE, YRS.	68.00	8.00	160.612
GROSS ULT., MB & MMF	29281.540	100196.900	DISCOUNT %	10.00	10.00	150.379
GROSS CUM., MB & MMF	27417.530	87991.520	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	141.598
GROSS RES., MB & MMF	1864.012	12205.340	DISCOUNTED PAYOUT, YRS.	.00	15.00	130.499
NET RES., MB0 & MMF	11.047	47.288	UNDISCOUNTED NET/INVEST.	.00	20.00	115.963
NET REVENUE, M$	194.549	142.999	DISCOUNTED NET/INVEST.	.00	25.00	104.814
INITIAL PRICE, $	19.121	3.079	RATE-OF-RETURN, PCT.	100.00	35.00	88.767
INITIAL N.I., PCT.	2.484	2.752	INITIAL W.I., PCT.	2.680	50.00	73.401
					70.00	60.874
					100.00	49.803

SWRI INCOME FUND VI	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:54
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	102.2	485.572	2494.820	.000	15.814	312.091	.000	18.48	2.22	292.205	693.673	985.878
12-03	94.2	264.776	2133.628	.000	9.607	277.999	.000	18.76	2.21	180.238	615.127	795.365
12-04	90.9	223.532	1887.247	.000	7.913	259.501	.000	18.84	2.21	149.088	572.257	721.345
12-05	86.2	189.246	1672.352	.000	6.285	242.303	.000	18.89	2.20	118.709	532.319	651.028
12-06	80.9	161.191	1483.717	.000	5.763	228.705	.000	18.90	2.19	108.935	501.771	610.706
12-07	72.3	129.466	1304.238	.000	4.937	215.789	.000	19.10	2.19	94.296	472.681	566.977
12-08	67.2	106.580	1170.694	.000	4.267	203.869	.000	19.25	2.19	82.123	445.887	528.010
12-09	62.7	90.042	1032.704	.000	3.435	183.971	.000	19.15	2.15	65.796	395.041	460.838
12-10	54.6	72.166	897.232	.000	2.895	170.836	.000	19.14	2.13	55.419	364.200	419.619
12-11	50.4	60.716	806.077	.000	2.111	160.113	.000	19.10	2.12	40.327	339.858	380.185
12-12	40.8	47.827	707.847	.000	1.592	149.737	.000	19.07	2.12	30.361	316.714	347.075
12-13	34.2	40.838	613.060	.000	1.415	124.827	.000	19.13	2.09	27.063	260.573	287.636
S  TOT	3.5	1871.951	16203.620	.000	66.035	2529.740	.000	18.85	2.18	1244.561	5510.102	6754.663
AFTER	3.5	216.413	8696.671	.000	4.511	2420.358	.000	18.89	2.04	85.231	4946.122	5031.353
TOTAL	3.5	2088.364	24900.290	.000	70.545	4950.098	.000	18.85	2.11	1329.792	10456.220	11786.020

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	13.503	52.023	27.835	301.085	591.431	5.82	.000	591.431	591.431	564.665
12-03	8.293	46.132	22.483	188.985	529.471	4.75	.000	529.471	1120.902	1024.125
12-04	6.860	42.917	20.370	169.461	481.737	4.68	.000	481.737	1602.639	1404.145
12-05	5.463	39.922	18.365	145.982	441.296	4.49	.000	441.296	2043.936	1720.600
12-06	5.013	37.631	17.213	145.907	404.942	4.69	.000	404.942	2448.878	1984.589
12-07	4.339	35.450	15.860	139.498	371.830	4.77	.000	371.830	2820.708	2204.949
12-08	3.779	33.440	14.688	133.812	342.291	4.86	.000	342.291	3162.999	2389.360
12-09	3.028	29.627	12.814	98.604	316.764	4.23	.000	316.764	3479.764	2544.493
12-10	2.551	27.314	11.667	83.011	295.076	3.97	.000	295.076	3774.840	2675.859
12-11	1.856	25.488	10.561	66.008	276.271	3.61	.000	276.271	4051.111	2787.673
12-12	1.398	23.753	9.636	55.910	256.380	3.42	.000	256.380	4307.491	2882.050
12-13	1.246	19.542	7.990	49.707	209.151	3.53	.000	209.151	4516.642	2952.005
S TOT	57.330	413.239	189.482	1577.971	4516.642	4.33	.000	4516.642	4516.642	2952.005
AFTER	3.932	370.940	139.526	840.852	3676.103	4.33	.000	3676.103	8192.745	3384.938
TOTAL	61.262	784.179	329.008	2418.823	8192.745	4.33	.000	8192.745	8192.745	3384.938

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	121.0	13.0	LIFE, YRS.	68.00	8.00	3796.749
GROSS ULT., MB & MMF	37026.180	149581.700	DISCOUNT %	10.00	10.00	3384.937
GROSS CUM., MB & MMF	34937.810	124681.400	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	3063.178
GROSS RES., MB & MMF	2088.365	24900.290	DISCOUNTED PAYOUT, YRS.	.00	15.00	2692.445
NET RES., MB & MMF	70.545	4950.098	UNDISCOUNTED NET/INVEST.	.00	20.00	2258.186
NET REVENUE, M$	1329.792	10456.220	DISCOUNTED NET/INVEST.	.00	25.00	1958.238
INITIAL PRICE, $	19.145	2.841	RATE-OF-RETURN, PCT.	100.00	35.00	1568.517
INITIAL N.I., PCT.	4.300	13.051	INITIAL W.I., PCT.	7.723	50.00	1234.461
					70.00	986.256
					100.00	782.824

SWRI INCOME FUND VI	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:55
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.915	4.110	.000	.089	.358	.000	18.07	2.60	1.610	.931	2.541
12-03	6.8	38.765	183.557	.000	5.529	15.169	.000	18.12	2.51	100.200	38.085	138.284
12-04	9.0	38.289	195.860	.000	6.245	15.717	.000	18.14	2.49	113.252	39.083	152.335
12-05	8.4	28.453	143.376	.000	4.897	11.695	.000	18.14	2.49	88.835	29.136	117.971
12-06	7.3	20.851	105.614	.000	3.811	8.743	.000	18.14	2.50	69.140	21.827	90.966
12-07	6.0	15.245	78.612	.000	2.924	6.515	.000	18.15	2.50	53.071	16.295	69.365
12-08	4.1	9.579	48.310	.000	2.213	4.293	.000	18.16	2.49	40.173	10.701	50.874
12-09	1.5	2.723	22.765	.000	.821	1.779	.000	18.18	2.42	14.932	4.297	19.229
12-10	.3	1.000	7.761	.000	.180	.954	.000	18.09	2.53	3.252	2.414	5.665
12-11	.0	.849	3.708	.000	.159	.695	.000	18.07	2.60	2.876	1.808	4.684
12-12	.0	.764	3.370	.000	.143	.632	.000	18.07	2.60	2.589	1.643	4.231
12-13	.0	.688	3.062	.000	.129	.574	.000	18.07	2.60	2.330	1.493	3.823
S TOT	.0	158.120	800.105	.000	27.141	67.123	.000	18.14	2.50	492.258	167.710	659.968
AFTER	.0	.214	.957	.000	.040	.179	.000	18.07	2.60	.724	.467	1.190
TOTAL	.0	158.334	801.063	.000	27.181	67.303	.000	18.14	2.50	492.982	168.177	661.159

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.074	.070	.072	.502	1.824	4.82	.000	1.824	1.824	1.671
12-03	4.609	2.856	3.925	25.639	101.255	4.60	50.000	51.255	53.079	44.865
12-04	5.210	2.931	4.326	38.140	101.728	5.71	.000	101.728	154.807	125.279
12-05	4.086	2.185	3.351	37.471	70.877	6.88	.000	70.877	225.684	176.235
12-06	3.180	1.637	2.584	35.874	47.691	8.21	.000	47.691	273.374	207.441
12-07	2.441	1.222	1.971	33.445	30.286	9.75	.000	30.286	303.660	225.425
12-08	1.848	.803	1.447	30.406	16.370	11.78	.000	16.370	320.031	234.345
12-09	.687	.322	.547	14.514	3.159	14.38	.000	3.159	323.190	235.902
12-10	.150	.181	.160	3.416	1.758	11.53	.000	1.758	324.948	236.687
12-11	.132	.136	.132	3.000	1.284	12.36	.000	1.284	326.232	237.208
12-12	.119	.123	.120	3.000	.870	13.53		.870	327.101	237.528
12-13	.107	.112	.108	3.000	.495	14.81		.495	327.597	237.695
S  TOT	22.644	12.578	18.742	228.407	377.597	15.75	50.000	327.597	327.597	237.695
AFTER	.033	.035	.034	1.000	.088	15.75	.000	.088	327.685	237.723
TOTAL	22.677	12.613	18.776	229.407	377.685	15.75	50.000	327.685	327.685	237.723

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	8.0	1.0	LIFE, YRS.	12.33	8.00	252.481
GROSS ULT., MB & MMF	158.334	867.748	DISCOUNT %	10.00	10.00	237.723
GROSS CUM., MB & MMF	.000	66.685	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	224.221
GROSS RES., MB & MMF	158.334	801.063	DISCOUNTED PAYOUT, YRS.	.00	15.00	206.027
NET RES., MB & MMF	27.181	67.303	UNDISCOUNTED NET/INVEST.	7.55	20.00	180.281
NET REVENUE, M$	492.982	168.177	DISCOUNTED NET/INVEST.	6.44	25.00	159.091
INITIAL PRICE, $	18.128	2.435	RATE-OF-RETURN, PCT.	100.00	35.00	126.601
INITIAL N.I., PCT.	14.938	8.111	INITIAL W.I., PCT.	14.681	50.00	93.882
					70.00	66.987
					100.00	44.253

SWRI INCOME FUND VI	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:59
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	3.7	38.484	517.648	.000	2.159	43.764	.000	17.62	2.42	38.047	105.980	144.027
12-03	14.3	159.462	1320.204	.000	8.200	89.880	.000	18.18	2.50	149.080	224.377	373.456
12-04	15.0	118.602	943.595	.000	6.150	62.164	.000	18.17	2.51	111.774	156.247	268.021
12-05	15.0	92.239	698.827	.000	4.781	44.111	.000	18.16	2.53	86.816	111.719	198.536
12-06	15.0	75.709	537.295	.000	3.925	32.406	.000	18.15	2.55	71.237	82.736	153.973
12-07	14.7	64.191	414.265	.000	3.328	23.339	.000	18.14	2.59	60.392	60.335	120.727
12-08	13.0	55.464	292.726	.000	2.864	13.406	.000	18.14	2.70	51.962	36.178	88.140
12-09	13.0	49.047	252.984	.000	2.539	11.693	.000	18.15	2.69	46.065	31.452	77.517
12-10	13.0	43.679	220.239	.000	2.275	10.311	.000	18.15	2.68	41.287	27.640	68.927
12-11	10.9	33.450	172.874	.000	1.626	7.608	.000	17.98	2.69	29.232	20.464	49.697
12-12	8.6	24.208	133.100	.000	1.058	5.464	.000	17.98	2.70	19.018	14.744	33.762
12-13	6.9	19.760	81.676	.000	.818	3.393	.000	18.10	2.60	14.807	8.832	23.639
S TOT	4.0	774.295	5585.433	.000	39.723	347.540	.000	18.12	2.53	719.717	880.704	1600.421
AFTER	4.0	15.752	63.117	.000	.720	2.884	.000	18.07	2.60	13.006	7.498	20.504
TOTAL	4.0	790.047	5648.550	.000	40.443	350.424	.000	18.12	2.53	732.723	888.202	1620.925

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	1.750	7.948	4.030	7.098	123.200	2.20	.000	123.200	123.200	114.885
12-03	6.858	16.828	10.493	22.429	316.848	2.44	.000	316.848	440.049	390.158
12-04	5.142	11.719	7.535	23.586	220.040	2.91	.000	220.040	660.089	564.108
12-05	3.994	8.379	5.585	23.586	156.992	3.42	.000	156.992	817.081	676.890
12-06	3.277	6.205	4.335	23.586	116.570	4.01	.000	116.570	933.651	753.001
12-07	2.778	4.525	3.403	23.103	86.918	4.68	.000	86.918	1020.569	804.632
12-08	2.390	2.713	2.491	20.685	59.861	5.55	.000	59.861	1080.430	836.907
12-09	2.119	2.359	2.191	20.685	50.163	6.10	.000	50.163	1130.593	861.493
12-10	1.899	2.073	1.949	20.685	42.321	6.66	.000	42.321	1172.914	880.349
12-11	1.345	1.535	1.405	15.839	29.573	6.95	.000	29.573	1202.487	892.364
12-12	.875	1.106	.953	9.964	20.864	6.55	.000	20.864	1223.351	900.061
12-13	.681	.662	.669	7.665	13.962	6.99	.000	13.962	1237.313	904.734
S TOT	33.107	66.053	45.038	218.911	1237.313	11.30	.000	1237.313	1237.313	904.734
AFTER	.598	.562	.580	7.646	11.117	11.30	.000	11.117	1248.430	908.115
TOTAL	33.705	66.615	45.618	226.557	1248.430	11.30	.000	1248.430	1248.430	908.115

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	12.0	3.0	LIFE, YRS.	13.17	8.00	961.340
GROSS ULT., MB & MMF	798.239	5812.652	DISCOUNT %	10.00	10.00	908.115
GROSS CUM., MB & MMF	8.192	164.102	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	860.229
GROSS RES., MB & MMF	790.047	5648.550	DISCOUNTED PAYOUT, YRS.	.00	15.00	796.844
NET RES., MB & MMF	40.443	350.424	UNDISCOUNTED NET/INVEST.	.00	20.00	709.144
NET REVENUE, M$	732.723	888.202	DISCOUNTED NET/INVEST.	.00	25.00	638.430
INITIAL PRICE, $	18.049	2.580	RATE-OF-RETURN, PCT.	100.00	35.00	531.729
INITIAL N.I., PCT.	5.105	7.058	INITIAL W.I., PCT.	6.941	50.00	424.654
					70.00	334.525
					100.00	253.737

SWRI INCOME FUND VI	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:41:05
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IFVI

EFFECTIVE DATE:  1/02

-END - MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	105.9	524.971	3016.579	.000	18.062	356.213	.000	18.37	2.25	331.862	800.584	1132.446
12-03	115.3	463.004	3637.388	.000	23.336	383.048	.000	18.41	2.29	429.517	877.588	1307.106
12-04	114.9	380.423	3026.703	.000	20.308	337.382	.000	18.42	2.28	374.114	767.587	1141.701
12-05	109.6	309.938	2514.555	.000	15.964	298.108	.000	18.44	2.26	294.360	673.175	967.535
12-06	103.3	257.751	2126.627	.000	13.499	269.853	.000	18.47	2.25	249.311	606.334	855.645
12-07	92.9	208.902	1797.115	.000	11.190	245.644	.000	18.57	2.24	207.759	549.310	757.069
12-08	84.3	171.623	1511.730	.000	9.343	221.568	.000	18.65	2.22	174.258	492.766	667.024
12-09	77.2	141.811	1308.453	.000	6.795	197.443	.000	18.66	2.18	126.794	430.789	557.583
12-10	67.8	116.844	1125.232	.000	5.349	182.100	.000	18.69	2.17	99.958	394.254	494.211
12-11	61.3	95.015	982.659	.000	3.896	168.416	.000	18.59	2.15	72.436	362.130	434.566
12-12	49.3	72.799	844.317	.000	2.793	155.833	.000	18.60	2.14	51.967	333.102	385.069
12-13	41.1	61.286	697.798	.000	2.362	128.794	.000	18.71	2.10	44.200	270.897	315.098
S  TOT	3.5	2804.366	22589.160	.000	132.898	2944.403	.000	18.48	2.23	2456.537	6558.516	9015.051
AFTER	3.5	232.379	8760.744	.000	5.271	2423.422	.000	18.78	2.04	98.960	4954.087	5053.047
TOTAL	3.5	3036.745	31349.900	.000	138.169	5367.825	.000	18.50	2.14	2555.497	11512.600	14068.100

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	15.328	60.041	31.937	308.685	716.455	5.37	.000	716.455	716.455	681.221
12-03	19.760	65.817	36.901	237.054	947.574	4.12	50.000	897.574	1614.030	1459.148
12-04	17.212	57.567	32.231	231.187	803.505	4.42	.000	803.505	2417.535	2093.531
12-05	13.543	50.486	27.301	207.039	669.166	4.54	.000	669.166	3086.700	2573.725
12-06	11.470	45.473	24.132	205.367	569.203	4.90	.000	569.203	3655.903	2945.031
12-07	9.558	41.197	21.234	196.046	489.034	5.14	.000	489.034	4144.937	3235.005
12-08	8.017	36.956	18.626	184.903	418.522	5.37	.000	418.522	4563.459	3460.612
12-09	5.834	32.308	15.552	133.803	370.086	4.72	.000	370.086	4933.545	3641.889
12-10	4.599	29.568	13.776	107.113	339.156	4.34	.000	339.156	5272.701	3792.896
12-11	3.333	27.159	12.098	84.847	307.128	3.99	.000	307.128	5579.829	3917.244
12-12	2.392	24.982	10.709	68.874	278.113	3.72	.000	278.113	5857.943	4019.640
12-13	2.034	20.316	8.767	60.372	223.608	3.84	.000	223.608	6081.551	4094.434
S TOT	113.080	491.870	253.262	2025.289	6131.551	4.33	50.000	6081.551	6081.551	4094.434
AFTER	4.564	371.537	140.140	849.498	3687.308	4.33	.000	3687.308	9768.858	4530.777
TOTAL	117.644	863.407	393.402	2874.787	9818.858	4.33	50.000	9768.858	9768.858	4530.777

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	141.0	17.0	LIFE, YRS.	68.00	8.00	5010.570
GROSS ULT., MB & MMF	37982.750	156262.100	DISCOUNT %	10.00	10.00	4530.775
GROSS CUM., MB & MMF	34946.000	124912.200	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	4147.628
GROSS RES., MB & MMF	3036.744	31349.900	DISCOUNTED PAYOUT, YRS.	.00	15.00	3695.316
NET RES., MB & MMF	138.169	5367.825	UNDISCOUNTED NET/INVEST.	196.38	20.00	3147.612
NET REVENUE, M$	2555.498	11512.600	DISCOUNTED NET/INVEST.	104.72	25.00	2755.759
INITIAL PRICE, $	18.812	2.721	RATE-OF-RETURN, PCT.	100.00	35.00	2226.848
INITIAL N.I ., PCT.	5.197	10.567	INITIAL W.I., PCT.	7.917	50.00	1752.997
					70.00	1387.768
					100.00	1080.814

APPENDIX B4

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund VII-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 19 reserve determinations and are located in the states of Louisiana, New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 84.7 percent of the total net remaining liquid hydrocarbon reserves and 95.3 percent of the total net remaining gas reserves. The properties that we reviewed represent 91.7 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund VII-A

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		127,011		0		2,756		129,767
Gas—MMCF		674		73		11		758
Income Data
Future Gross Revenue	$	3,466,930	$	177,899	$	77,159	$	3,721,988
Deductions		1,606,394		26,513		13,061		1,645,968
Future Net Income (FNI)	$	1,860,536	$	151,386	$	64,098	$	2,076,020
Discounted FNI @ 10%	$	1,058,720	$	113,019	$	42,996	$	1,214,735

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		23,481		0		0		23,481
Gas—MMCF		37		0		0		37
Income Data
Future Gross Revenue	$	454,391	$	0	$	0	$	454,391
Deductions		300,805		0		0		300,805
Future Net Income (FNI)	$	153,586	$	0	$	0	$	153,586
Discounted FNI @ 10%	$	109,371	$	0	$	0	$	109,371
Total Net Reserves
Oil/Condensate—Barrels		150,492		0		2,756		153,248
Gas—MMCF		711		73		11		795
Income Data
Future Gross Revenue	$	3,921,321	$	177,899	$	77,159	$	4,176,379
Deductions		1,907,199		26,513		13,061		1,946,773
Future Net Income (FNI)	$	2,014,122	$	151,386	$	64,098	$	2,229,606
Discounted FNI @ 10%	$	1,168,091	$	113,019	$	42,996	$	1,324,106

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? . . . The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 15.3 percent of the total net remaining liquid hydrocarbon reserves and 4.7 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours, RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:44:56
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	33.8	64.776	610.232	.000	11.033	69.722	.000	17.42	2.33	192.167	162.519	354.685
12-03	33.0	60.058	525.510	.000	10.056	59.689	.000	17.38	2.33	174.716	138.805	313.521
12-04	33.0	56.654	464.230	.000	9.500	53.358	.000	17.38	2.34	165.056	124.750	289.805
12-05	33.0	53.454	415.604	.000	8.975	48.237	.000	17.38	2.35	155.949	113.270	269.219
12-06	33.0	50.443	376.117	.000	8.481	43.999	.000	17.38	2.36	147.362	103.680	251.041
12-07	33.0	47.608	343.313	.000	8.015	40.414	.000	17.38	2.36	139.261	95.495	234.756
12-08	33.0	44.939	315.376	.000	7.574	37.312	.000	17.38	2.37	131.618	88.359	219.977
12-09	28.5	39.581	281.636	.000	7.110	33.837	.000	17.39	2.38	123.615	80.471	204.086
12-10	21.2	30.697	252.550	.000	6.163	29.510	.000	17.33	2.34	106.826	69.075	175.901
12-11	19.3	27.431	222.697	.000	5.198	23.367	.000	17.22	2.31	89.509	54.025	143.533
12-12	19.0	25.810	204.660	.000	4.910	21.013	.000	17.22	2.34	84.544	49.083	133.626
12-13	19.0	24.384	191.310	.000	4.647	19.654	.000	17.22	2.34	80.031	45.935	125.966
S TOT	1.0	525.834	4203.234	.000	91.661	480.110	.000	17.35	2.34	1590.652	1125.465	2716.118
AFTER	1.0	218.492	1925.860	.000	35.350	194.336	.000	16.50	2.29	583.252	445.365	1028.617
TOTAL	1.0	744.326	6129.094	.000	127.011	674.446	.000	17.12	2.33	2173.904	1570.830	3744.735

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	14.162	12.189	8.661	105.073	214.600	6.18	.000	214.600	214.600	204.902
12-03	13.093	10.410	7.569	93.270	189.179	6.22	.000	189.179	403.779	369.098
12-04	12.396	9.356	6.965	93.270	167.819	6.63	.000	167.819	571.598	501.510
12-05	11.737	8.495	6.445	93.270	149.273	7.05	.000	149.273	720.870	608.580
12-06	11.114	7.776	5.989	93.270	132.893	7.47	.000	132.893	853.764	695.236
12-07	10.524	7.162	5.584	93.270	118.217	7.90	.000	118.217	971.980	765.314
12-08	9.967	6.627	5.218	93.270	104.896	8.34	.000	104.896	1076.876	821.845
12-09	9.403	6.035	4.813	90.967	92.867	8.72	.000	92.867	1169.743	867.343
12-10	8.445	5.181	4.054	75.838	82.384	8.44	.000	82.384	1252.127	904.035
12-11	7.472	4.052	3.185	54.816	74.008	7.65	.000	74.008	1326.135	933.996
12-12	7.076	3.681	2.948	53.418	66.504	7.98	.000	66.504	1392.639	958.473
12-13	6.709	3.445	2.772	53.418	59.622	8.37	.000	59.622	1452.261	978.423
S TOT	122.095	84.410	64.203	993.149	1452.261	11.24	.000	1452.261	1452.261	978.423
AFTER	37.897	33.402	28.506	520.536	408.275	11.24	.000	408.275	1860.536	1058.720
TOTAL	159.993	117.812	92.709	1513.685	1860.536	11.24	.000	1860.536	1860.536	1058.720

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	24.0	10.0	LIFE, YRS.	41.17	8.00	1156.820
GROSS ULT., MB & MMF	15247.290	38309.820	DISCOUNT %	10.00	10.00	1058.720
GROSS CUM., MB & MMF	14502.960	32180.730	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	977.009
GROSS RES., MB & MMF	744.326	6129.094	DISCOUNTED PAYOUT, YRS.	.00	15.00	877.346
NET RES., MB & MMF	127.011	674.445	UNDISCOUNTED NET/INVEST.	.00	20.00	753.303
NET REVENUE, M$	2173.904	1570.831	DISCOUNTED NET/INVEST.	.00	25.00	663.261
INITIAL PRICE, $	16.799	2.205	RATE-OF-RETURN, PCT.	100.00	35.00	541.299
INITIAL N.I., PCT.	17.081	11.382	INITIAL W.I., PCT.	17.252	50.00	432.532
					70.00	349.271
					100.00	279.498

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:12
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.0	.000	163.485	.000	.000	15.110	.000	.00	2.64	.000	39.889	39.889
12-03	1.0	.000	130.793	.000	.000	12.088	.000	.00	2.64	.000	31.913	31.913
12-04	1.0	.000	104.638	.000	.000	9.671	.000	.00	2.64	.000	25.531	25.531
12-05	1.0	.000	83.714	.000	.000	7.737	.000	.00	2.64	.000	20.426	20.426
12-06	1.0	.000	66.974	.000	.000	6.190	.000	.00	2.64	.000	16.341	16.341
12-07	1.0	.000	53.581	.000	.000	4.952	.000	.00	2.64	.000	13.073	13.073
12-08	1.0	.000	42.866	.000	.000	3.962	.000	.00	2.64	.000	10.459	10.459
12-09	1.0	.000	34.294	.000	.000	3.170	.000	.00	2.64	.000	8.368	8.368
12-10	1.0	.000	27.436	.000	.000	2.536	.000	.00	2.64	.000	6.694	6.694
12-11	1.0	.000	21.950	.000	.000	2.029	.000	.00	2.64	.000	5.356	5.356
12-12	1.0	.000	17.561	.000	.000	1.623	.000	.00	2.64	.000	4.285	4.285
12-13	1.0	.000	14.049	.000	.000	1.298	.000	.00	2.64	.000	3.428	3.428
S TOT	1.0	.000	761.342	.000	.000	70.365	.000	.00	2.64	.000	185.763	185.763
AFTER	1.0	.000	26.886	.000	.000	2.485	.000	.00	2.64	.000	6.560	6.560
TOTAL	1.0	.000	788.227	.000	.000	72.849	.000	.00	2.64	.000	192.323	192.323

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	2.992	1.107	1.420	34.371	2.19	.000	34.371	34.371	32.844
12-03	.000	2.393	.886	1.420	27.214	2.33	.000	27.214	61.585	56.485
12-04	.000	1.915	.708	1.420	21.488	2.51	.000	21.488	83.073	73.456
12-05	.000	1.532	.567	1.420	16.907	2.73	.000	16.907	99.981	85.595
12-06	.000	1.226	.453	1.420	13.242	3.00	.000	13.242	113.223	94.239
12-07	.000	.981	.363	1.420	10.311	3.35	.000	10.311	123.534	100.357
12-08	.000	.784	.290	1.420	7.965	3.78	.000	7.965	131.498	104.655
12-09	.000	.628	.232	1.420	6.088	4.31	.000	6.088	137.587	107.641
12-10	.000	.502	.186	1.420	4.587	4.99	.000	4.587	142.174	109.687
12-11	.000	.402	.149	1.420	3.386	5.83	.000	3.386	145.559	111.060
12-12	.000	.321	.119	1.420	2.425	6.88	.000	2.425	147.984	111.954
12-13	.000	.257	.095	1.420	1.656	8.19	.000	1.656	149.640	112.509
S TOT	.000	13.932	5.155	17.035	149.640	14.32	.000	149.640	149.640	112.509
AFTER	.000	.492	.182	4.141	1.745	14.32	.000	1.745	151.386	113.019
TOTAL	.000	14.424	5.337	21.176	151.386	14.32	.000	151.386	151.386	113.019

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	.0	1.0	LIFE, YRS.	14.92	8.00	118.966
GROSS ULT., MB & MMF	.000	788.227	DISCOUNT %	10.00	10.00	113.019
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	107.687
GROSS RES., MB & MMF	.000	788.227	DISCOUNTED PAYOUT, YRS.	.00	15.00	100.657
NET RES., MB & MMF	.000	72.849	UNDISCOUNTED NET/INVEST.	.00	20.00	90.984
NET REVENUE, M$	.000	192.323	DISCOUNTED NET/INVEST.	.00	25.00	83.230
INITIAL PRICE, $	.000	2.640	RATE-OF-RETURN, PCT.	100.00	35.00	71.608
INITIAL N.I., PCT.	.000	9.242	INITIAL W.I., PCT.	10.562	50.00	60.023
					70.00	50.296
					100.00	41.524

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:19
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.0	13.833	55.331	.000	.611	2.445	.000	18.91	2.69	11.559	6.577	18.136
12-04	1.0	9.402	37.609	.000	.415	1.662	.000	18.91	2.69	7.857	4.471	12.327
12-05	1.0	7.296	29.183	.000	.322	1.290	.000	18.91	2.69	6.097	3.469	9.566
12-06	1.0	6.034	24.137	.000	.267	1.067	.000	18.91	2.69	5.042	2.869	7.912
12-07	1.0	5.184	20.735	.000	.229	.916	.000	18.91	2.69	4.332	2.465	6.796
12-08	1.0	4.567	18.267	.000	.202	.807	.000	18.91	2.69	3.816	2.171	5.988
12-09	1.0	4.096	16.386	.000	.181	.724	.000	18.91	2.69	3.423	1.948	5.371
12-10	1.0	3.474	13.896	.000	.154	.614	.000	18.91	2.69	2.903	1.652	4.555
12-11	1.0	3.146	12.584	.000	.139	.556	.000	18.91	2.69	2.629	1.496	4.125
12-12	1.0	2.894	11.577	.000	.128	.512	.000	18.91	2.69	2.418	1.376	3.795
12-13	1.0	2.449	9.797	.000	.108	.433	.000	18.91	2.69	2.047	1.165	3.211
S TOT	1.0	62.376	249.502	.000	2.756	11.025	.000	18.91	2.69	52.122	29.658	81.781
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	62.376	249.502	.000	2.756	11.025	.000	18.91	2.69	52.122	29.658	81.781

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.000	.000	.000	.000	.000
12-03	.532	.493	.513	.984	15.613	2.48	.000	15.613	15.613	13.594
12-04	.361	.335	.349	.984	10.297	2.93	.000	10.297	25.911	21.732
12-05	.280	.260	.271	.984	7.770	3.34	.000	7.770	33.681	27.311
12-06	.232	.215	.224	.984	6.256	3.72	.000	6.256	39.937	31.393
12-07	.199	.185	.192	.984	5.236	4.09	.000	5.236	45.172	34.498
12-08	.176	.163	.169	.984	4.495	4.44	.000	4.495	49.668	36.921
12-09	.157	.146	.152	.984	3.931	4.77	.000	3.931	53.599	38.847
12-10	.134	.124	.129	.984	3.184	5.36	.000	3.184	56.783	40.266
12-11	.121	.112	.117	.984	2.790	5.76	.000	2.790	59.573	41.396
12-12	.111	.103	.107	.984	2.488	6.13	.000	2.488	62.061	42.312
12-13	.094	.087	.091	.902	2.036	6.51	.000	2.036	64.098	42.996
S TOT	2.398	2.224	2.315	10.746	64.098	6.51	.000	64.098	64.098	42.996
AFTER	.000	.000	.000	.000	.000	6.51	.000	.000	64.098	42.996
TOTAL	2.398	2.224	2.315	10.746	64.098	6.51	.000	64.098	64.098	42.996

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	11.92	8.00	46.181
GROSS ULT., MB & MMF	62.376	304.915	DISCOUNT %	10.00	10.00	42.996
GROSS CUM., MB & MMF	.000	55.413	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	40.172
GROSS RES., MB & MMF	62.376	249.502	DISCOUNTED PAYOUT, YRS.	.00	15.00	36.501
NET RES., MB & MMF	2.756	11.025	UNDISCOUNTED NET/INVEST.	.00	20.00	31.555
NET REVENUE, M$	52.122	29.658	DISCOUNTED NET/INVEST.	.00	25.00	27.689
INITIAL PRICE, $	18.910	2.690	RATE-OF-RETURN, PCT.	100.00	35.00	22.080
INITIAL N.I., PCT	4.419	4.419	INITIAL W.I., PCT.	5.469	50.00	16.745
					70.00	12.498
					100.00	8.895

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:26
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	34.8	64.776	773.717	.000	11.033	84.831	.000	17.42	2.39	192.167	202.408	394.575
12-03	35.0	73.891	711.634	.000	10.667	74.222	.000	17.46	2.39	186.275	177.295	363.570
12-04	35.0	66.057	606.477	.000	9.915	64.690	.000	17.44	2.39	172.912	154.751	327.664
12-05	35.0	60.750	528.501	.000	9.298	57.263	.000	17.43	2.40	162.046	137.165	299.210
12-06	35.0	56.477	467.228	.000	8.748	51.255	.000	17.42	2.40	152.404	122.890	275.294
12-07	35.0	52.792	417.629	.000	8.244	46.282	.000	17.42	2.40	143.593	111.033	254.626
12-08	35.0	49.505	376.510	.000	7.776	42.081	.000	17.42	2.40	135.434	100.990	236.424
12-09	30.5	43.677	332.316	.000	7.291	37.731	.000	17.42	2.41	127.038	90.787	217.824
12-10	23.2	34.171	293.883	.000	6.316	32.660	.000	17.37	2.37	109.729	77.421	187.150
12-11	21.3	30.577	257.230	.000	5.337	25.952	.000	17.26	2.35	92.137	60.876	153.013
12-12	21.0	28.704	233.798	.000	5.038	23.147	.000	17.26	2.37	86.962	54.743	141.706
12-13	20.9	26.833	215.155	.000	4.755	21.385	.000	17.26	2.36	82.077	50.527	132.605
S TOT	1.0	588.210	5214.078	.000	94.417	561.500	.000	17.40	2.39	1642.775	1340.886	2983.661
AFTER	1.0	218.492	1952.746	.000	35.350	196.821	.000	16.50	2.30	583.252	451.925	1035.177
TOTAL	1.0	806.702	7166.823	.000	129.767	758.320	.000	17.15	2.36	2226.027	1792.811	4018.838

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	14.162	15.181	9.768	106.493	248.971	5.78	.000	248.971	248.971	237.746
12-03	13.625	13.297	8.968	95.674	232.006	5.71	.000	232.006	480.977	439.178
12-04	12.757	11.606	8.022	95.674	199.604	6.19	.000	199.604	680.582	596.698
12-05	12.017	10.287	7.282	95.674	173.950	6.65	.000	173.950	854.532	721.486
12-06	11.346	9.217	6.666	95.674	152.392	7.11	.000	152.392	1006.923	820.867
12-07	10.723	8.327	6.139	95.674	133.763	7.57	.000	133.763	1140.686	900.170
12-08	10.142	7.574	5.678	95.674	117.356	8.05	.000	117.356	1258.043	963.421
12-09	9.560	6.809	5.198	93.371	102.886	8.46	.000	102.886	1360.929	1013.831
12-10	8.578	5.807	4.368	78.242	90.155	8.25	.000	90.155	1451.083	1053.987
12-11	7.593	4.566	3.450	57.220	80.184	7.54	.000	80.184	1531.268	1086.452
12-12	7.187	4.106	3.175	55.822	71.417	7.90	.000	71.417	1602.684	1112.739
12-13	6.803	3.790	2.958	55.740	63.314	8.33	.000	63.314	1665.999	1133.928
S TOT	124.493	100.566	71.673	1020.930	1665.999	11.24	.000	1665.999	1665.999	1133.928
AFTER	37.897	33.894	28.688	524.677	410.021	11.24	.000	410.021	2076.019	1214.735
TOTAL	162.390	134.461	100.360	1545.606	2076.019	11.24	.000	2076.019	2076.019	1214.735

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	25.0	11.0	LIFE, YRS.	41.17	8.00	1321.967
GROSS ULT., MB & MMF	15309.660	39402.970	DISCOUNT %	10.00	10.00	1214.735
GROSS CUM., MB & MMF	14502.960	32236.140	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1124.869
GROSS RES., MB & MMF	806.702	7166.823	DISCOUNTED PAYOUT, YRS.	.00	15.00	1014.504
NET RES., MB & MMF	129.767	758.320	UNDISCOUNTED NET/INVEST.	.00	20.00	875.841
NET REVENUE, M$	2226.026	1792.811	DISCOUNTED NET/INVEST.	.00	25.00	774.180
INITIAL PRICE, $	17.237	2.330	RATE-OF-RETURN, PCT.	100.00	35.00	634.987
INITIAL N.I., PCT.	14.451	10.416	INITIAL W.I., PCT.	14.638	50.00	509.300
					70.00	412.064
					100.00	329.917

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	16:57:50
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	37.7	385.050	720.212	.000	6.263	4.371	.000	17.58	2.29	110.092	10.002	120.093
12-03	37.0	200.344	647.588	.000	5.577	4.036	.000	17.49	2.29	97.546	9.240	106.787
12-04	17.7	116.925	590.641	.000	3.834	3.728	.000	16.68	2.29	63.951	8.539	72.490
12-05	8.0	77.389	538.706	.000	2.955	3.443	.000	16.05	2.29	47.440	7.892	55.331
12-06	3.0	63.840	491.340	.000	.998	3.181	.000	15.81	2.29	15.775	7.294	23.070
12-07	3.0	58.449	448.141	.000	.926	2.939	.000	15.79	2.29	14.623	6.743	21.366
12-08	3.0	53.514	408.743	.000	.860	2.716	.000	15.76	2.30	13.559	6.234	19.792
12-09	2.8	48.802	372.725	.000	.719	2.475	.000	15.86	2.28	11.413	5.643	17.055
12-10	2.0	43.733	339.543	.000	.283	2.117	.000	17.43	2.19	4.936	4.628	9.564
12-11	2.0	40.015	309.685	.000	.258	1.954	.000	17.43	2.19	4.498	4.271	8.768
12-12	2.0	36.614	282.454	.000	.235	1.803	.000	17.43	2.19	4.099	3.941	8.040
12-13	1.2	33.250	255.487	.000	.139	1.028	.000	17.77	2.18	2.474	2.237	4.711
S TOT	.0	1157.925	5405.265	.000	23.049	33.791	.000	16.94	2.27	390.405	76.663	467.069
AFTER	.0	169.801	1288.668	.000	.432	3.246	.000	18.85	2.27	8.135	7.366	15.501
TOTAL	.0	1327.727	6693.933	.000	23.481	37.036	.000	16.97	2.27	398.540	84.029	482.570

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	6.421	.769	1.843	72.688	38.373	11.69	.000	38.373	38.373	36.700
12-03	5.635	.710	1.703	72.383	26.356	12.87	.000	26.356	64.729	59.629
12-04	3.348	.656	1.573	49.590	17.322	12.38	.000	17.322	82.051	73.319
12-05	2.266	.607	1.454	38.194	12.811	12.05	.000	12.811	94.862	82.523
12-06	.801	.561	.542	11.250	9.916	8.61	.000	9.916	104.778	88.991
12-07	.741	.519	.503	11.250	8.354	9.19	.000	8.354	113.132	93.946
12-08	.685	.480	.467	11.250	6.911	9.81	.000	6.911	120.043	97.673
12-09	.580	.434	.397	10.058	5.586	10.13	.000	5.586	125.629	100.411
12-10	.277	.358	.191	4.098	4.641	7.74	.000	4.641	130.271	102.479
12-11	.252	.330	.175	4.098	3.914	8.32	.000	3.914	134.185	104.065
12-12	.229	.305	.160	4.098	3.248	8.95	.000	3.248	137.432	105.261
12-13	.120	.169	.122	1.572	2.727	6.39	.000	2.727	140.160	106.174
S TOT	21.355	5.897	9.130	290.527	140.160	1.42	.000	140.160	140.160	106.174
AFTER	.374	.552	.437	.711	13.426	1.42	.000	13.426	153.586	109.371
TOTAL	21.729	6.450	9.567	291.238	153.586	1.42	.000	153.586	153.586	109.371

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	44.0	4.0	LIFE, YRS.	19.33	8.00	115.618
GROSS ULT., MB & MMF	26410.360	40318.630	DISCOUNT %	10.00	10.00	109.371
GROSS CUM., MB & MMF	25082.640	33624.700	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	103.931
GROSS RES., MB & MMF	1327.727	6693.933	DISCOUNTED PAYOUT, YRS.	.00	15.00	96.968
NET RES., MB & MMF	23.481	37.036	UNDISCOUNTED NET/INVEST.	.00	20.00	87.728
NET REVENUE, M$	398.541	84.029	DISCOUNTED NET/INVEST.	.00	25.00	80.552
INITIAL PRICE, $	19.402	2.254	RATE-OF-RETURN, PCT.	100.00	35.00	70.060
INITIAL N.I., PCT.	1.604	.990	INITIAL W.I., PCT.	1.627	50.00	59.752
					70.00	51.063
					100.00	43.082

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:38:20
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	71.5	449.826	1330.444	.000	17.296	74.093	.000	17.48	2.33	302.259	172.520	474.779
12-03	70.0	260.402	1173.098	.000	15.633	63.725	.000	17.42	2.32	272.262	148.045	420.307
12-04	50.7	173.579	1054.871	.000	13.333	57.085	.000	17.18	2.33	229.007	133.289	362.296
12-05	41.0	130.843	954.310	.000	11.931	51.680	.000	17.05	2.34	203.389	121.162	324.550
12-06	36.0	114.283	867.457	.000	9.479	47.179	.000	17.21	2.35	163.137	110.974	274.111
12-07	36.0	106.057	791.454	.000	8.941	43.352	.000	17.21	2.36	153.884	102.238	256.122
12-08	36.0	98.453	724.119	.000	8.434	40.027	.000	17.21	2.36	145.177	94.593	239.770
12-09	31.3	88.383	654.362	.000	7.830	36.312	.000	17.25	2.37	135.027	86.114	221.141
12-10	23.2	74.430	592.093	.000	6.446	31.628	.000	17.34	2.33	111.762	73.703	185.466
12-11	21.3	67.447	532.381	.000	5.456	25.321	.000	17.23	2.30	94.006	58.295	152.302
12-12	21.0	62.424	487.114	.000	5.145	22.816	.000	17.23	2.32	88.642	53.023	141.666
12-13	20.2	57.634	446.797	.000	4.786	20.682	.000	17.24	2.33	82.505	48.172	130.677
S TOT	1.0	683.760	9608.499	.000	114.710	513.900	.000	17.27	2.34	1981.058	1202.129	3183.187
AFTER	1.0	388.293	3214.528	.000	35.781	197.581	.000	16.53	2.29	591.387	452.731	1044.118
TOTAL	1.0	2072.053	12823.030	.000	150.492	711.482	.000	17.09	2.33	2572.445	1654.860	4227.305

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	20.582	12.957	10.504	177.762	252.973	7.48	.000	252.973	252.973	241.602
12-03	18.728	11.121	9.272	165.652	215.535	7.80	.000	215.535	468.508	428.727
12-04	15.744	10.013	8.538	142.860	185.141	7.75	.000	185.141	653.649	574.829
12-05	14.002	9.102	7.899	131.463	162.084	7.91	.000	162.084	815.733	691.103
12-06	11.915	8.337	6.531	104.519	142.809	7.57	.000	142.809	958.542	784.227
12-07	11.265	7.681	6.087	104.519	126.571	8.01	.000	126.571	1085.113	859.260
12-08	10.652	7.107	5.685	104.519	111.807	8.47	.000	111.807	1196.920	919.518
12-09	9.983	6.470	5.211	101.025	98.453	8.84	.000	98.453	1295.373	967.754
12-10	8.722	5.538	4.244	79.936	87.025	8.40	.000	87.025	1382.398	1006.514
12-11	7.724	4.382	3.360	58.914	77.922	7.69	.000	77.922	1460.320	1038.061
12-12	7.305	3.986	3.109	57.515	69.751	8.04	.000	69.751	1530.071	1063.734
12-13	6.829	3.614	2.895	54.990	62.349	8.30	.000	62.349	1592.421	1084.596
S TOT	143.450	90.307	73.333	1283.676	1592.421	11.24	.000	1592.421	1592.421	1084.596
AFTER	38.272	33.955	28.943	521.247	421.701	11.24	.000	421.701	2014.122	1168.091
TOTAL	181.722	124.262	102.276	1804.923	2014.122	11.24	.000	2014.122	2014.122	1168.091

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	68.0	14.0	LIFE, YRS.	41.17	8.00	1272.437
GROSS ULT., MB & MMF	41657.650	78628.460	DISCOUNT %	10.00	10.00	1168.091
GROSS CUM., MB & MMF	39585.600	65805.430	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1080.940
GROSS RES., MB & MMF	2072.053	12823.030	DISCOUNTED PAYOUT, YRS.	.00	15.00	974.315
NET RES., MB & MMF	150.492	711.482	UNDISCOUNTED NET/INVEST.	.00	20.00	841.031
NET REVENUE, M$	2572.445	1654.860	DISCOUNTED NET/INVEST.	.00	25.00	743.812
INITIAL PRICE, $	19.090	2.231	RATE-OF-RETURN, PCT.	100.00	35.00	611.359
INITIAL N.I., PCT.	3.455	5.767	INITIAL W.I., PCT.	4.523	50.00	492.284
					70.00	400.334
					100.00	322.580

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:38:24
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.0	.000	163.485	.000	.000	15.110	.000	.00	2.64	.000	39.889	39.889
12-03	1.0	.000	130.793	.000	.000	12.088	.000	.00	2.64	.000	31.913	31.913
12-04	1.0	.000	104.638	.000	.000	9.671	.000	.00	2.64	.000	25.531	25.531
12-05	1.0	.000	83.714	.000	.000	7.737	.000	.00	2.64	.000	20.426	20.426
12-06	1.0	.000	66.974	.000	.000	6.190	.000	.00	2.64	.000	16.341	16.341
12-07	1.0	.000	53.581	.000	.000	4.952	.000	.00	2.64	.000	13.073	13.073
12-08	1.0	.000	42.866	.000	.000	3.962	.000	.00	2.64	.000	10.459	10.459
12-09	1.0	.000	34.294	.000	.000	3.170	.000	.00	2.64	.000	8.368	8.368
12-10	1.0	.000	27.436	.000	.000	2.536	.000	.00	2.64	.000	6.694	6.694
12-11	1.0	.000	21.950	.000	.000	2.029	.000	.00	2.64	.000	5.356	5.356
12-12	1.0	.000	17.561	.000	.000	1.623	.000	.00	2.64	.000	4.285	4.285
12-13	1.0	.000	14.049	.000	.000	1.298	.000	.00	2.64	.000	3.428	3.428
S TOT	1.0	.000	761.342	.000	.000	70.365	.000	.00	2.64	.000	185.763	185.763
AFTER	1.0	.000	26.886	.000	.000	2.485	.000	.00	2.64	.000	6.560	6.560
TOTAL	1.0	.000	788.227	.000	.000	72.849	.000	.00	2.64	.000	192.323	192.323

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	2.992	1.107	1.420	34.371	2.19	.000	34.371	34.371	32.844
12-03	.000	2.393	.886	1.420	27.214	2.33	.000	27.214	61.585	56.485
12-04	.000	1.915	.708	1.420	21.488	2.51	.000	21.488	83.073	73.456
12-05	.000	1.532	.567	1.420	16.907	2.73	.000	16.907	99.981	85.595
12-06	.000	1.226	.453	1.420	13.242	3.00	.000	13.242	113.223	94.239
12-07	.000	.981	.363	1.420	10.311	3.35	.000	10.311	123.534	100.357
12-08	.000	.784	.290	1.420	7.965	3.78	.000	7.965	131.498	104.655
12-09	.000	.628	.232	1.420	6.088	4.31	.000	6.088	137.587	107.641
12-10	.000	.502	.186	1.420	4.587	4.99	.000	4.587	142.174	109.687
12-11	.000	.402	.149	1.420	3.386	5.83	.000	3.386	145.559	111.060
12-12	.000	.321	.119	1.420	2.425	6.88	.000	2.425	147.984	111.954
12-13	.000	.257	.095	1.420	1.656	8.19	.000	1.656	149.640	112.509
S TOT	.000	13.932	5.155	17.035	149.640	14.32	.000	149.640	149.640	112.509
AFTER	.000	.492	.182	4.141	1.745	14.32	.000	1.745	151.386	113.019
TOTAL	.000	14.424	5.337	21.176	151.386	14.32	.000	151.386	151.386	113.019

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	.0	1.0	LIFE, YRS.	14.92	8.00	18.966
GROSS ULT., MB & MMF	.000	788.227	DISCOUNT %	10.00	10.00	113.019
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	107.687
GROSS RES., MB & MMF	.000	788.227	DISCOUNTED PAYOUT, YRS.	.00	15.00	100.657
NET RES., MB & MMF	.000	72.849	UNDISCOUNTED NET/INVEST.	.00	20.00	90.984
NET REVENUE, M$	.000	192.323	DISCOUNTED NET/INVEST.	.00	25.00	83.230
INITIAL PRICE, $	.000	2.640	RATE-OF-RETURN, PCT.	100.00	35.00	71.608
INITIAL N.I., PCT	.000	9.242	INITIAL W.I., PCT.	10.562	50.00	60.023
					70.00	50.296
					100.00	41.524

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:38:30
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.0	13.833	55.331	.000	.611	2.445	.000	18.91	2.69	11.559	6.577	18.136
12-04	1.0	9.402	37.609	.000	.415	1.662	.000	18.91	2.69	7.857	4.471	12.327
12-05	1.0	7.296	29.183	.000	.322	1.290	.000	18.91	2.69	6.097	3.469	9.566
12-06	1.0	6.034	24.137	.000	.267	1.067	.000	18.91	2.69	5.042	2.869	7.912
12-07	1.0	5.184	20.735	.000	.229	.916	.000	18.91	2.69	4.332	2.465	6.796
12-08	1.0	4.567	18.267	.000	.202	.807	.000	18.91	2.69	3.816	2.171	5.988
12-09	1.0	4.096	16.386	.000	.181	.724	.000	18.91	2.69	3.423	1.948	5.371
12-10	1.0	3.474	13.896	.000	.154	.614	.000	18.91	2.69	2.903	1.652	4.555
12-11	1.0	3.146	12.584	.000	.139	.556	.000	18.91	2.69	2.629	1.496	4.125
12-12	1.0	2.894	11.577	.000	.128	.512	.000	18.91	2.69	2.418	1.376	3.795
12-13	1.0	2.449	9.797	.000	.108	.433	.000	18.91	2.69	2.047	1.165	3.211
S TOT	1.0	62.376	249.502	.000	2.756	11.025	.000	18.91	2.69	52.122	29.658	81.781
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	62.376	249.502	.000	2.756	11.025	.000	18.91	2.69	52.122	29.658	81.781

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.532	.493	.513	.984	15.613	2.48	.000	15.613	15.613	13.594
12-04	.361	.335	.349	.984	10.297	2.93	.000	10.297	25.911	21.732
12-05	.280	.260	.271	.984	7.770	3.34	.000	7.770	33.681	27.311
12-06	.232	.215	.224	.984	6.256	3.72	.000	6.256	39.937	31.393
12-07	.199	.185	.192	.984	5.236	4.09	.000	5.236	45.172	34.498
12-08	.176	.163	.169	.984	4.495	4.44	.000	4.495	49.668	36.921
12-09	.157	.146	.152	.984	3.931	4.77	.000	3.931	53.599	38.847
12-10	.134	.124	.129	.984	3.184	5.36	.000	3.184	56.783	40.266
12-11	.121	.112	.117	.984	2.790	5.76	.000	2.790	59.573	41.396
12-12	.111	.103	.107	.984	2.488	6.13	.000	2.488	62.061	42.312
12-13	.094	.087	.091	.902	2.036	6.51	.000	2.036	64.098	42.996
S TOT	2.398	2.224	2.315	10.746	64.098	6.51	.000	64.098	64.098	42.996
AFTER	.000	.000	.000	.000	.000	6.51	.000	.000	64.098	42.996
TOTAL	2.398	2.224	2.315	10.746	64.098	6.51	.000	64.098	64.098	42.996

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	11.92	8.00	46.181
GROSS ULT., MB & MMF	62.376	304.915	DISCOUNT %	10.00	10.00	42.996
GROSS CUM., MB & MMF	.000	55.413	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	40.172
GROSS RES., MB & MMF	62.376	249.502	DISCOUNTED PAYOUT, YRS.	.00	15.00	36.501
NET RES., MB & MMF	2.756	11.025	UNDISCOUNTED NET/INVEST.	.00	20.00	31.555
NET REVENUE, M$	52.122	229.658	DISCOUNTED NET/INVEST.	.00	25.00	27.689
INITIAL PRICE, $	18.910	2.690	RATE-OF-RETURN, PCT.	100.00	35.00	22.080
INITIAL N.I., PCT.	4.419	4.419	INITIAL W.I., PCT.	5.469	50.00	16.745
					70.00	12.498
					100.00	8.895

SW OIL & GAS INCOME FUND VII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:38:37
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	72.5	449.826	1493.929	.000	17.296	89.203	.000	17.48	2.38	302.259	212.410	514.668
12-03	72.0	274.234	1359.222	.000	16.244	78.258	.000	17.47	2.38	283.821	186.535	470.356
12-04	52.7	182.982	1197.118	.000	13.749	68.418	.000	17.23	2.39	236.864	163.290	400.154
12-05	43.0	138.139	1067.207	.000	12.253	60.706	.000	17.10	2.39	209.485	145.056	354.542
12-06	38.0	120.317	958.567	.000	9.746	54.436	.000	17.26	2.39	168.180	130.184	298.364
12-07	38.0	111.241	865.770	.000	9.170	49.221	.000	17.25	2.39	158.216	117.776	275.992
12-08	38.0	103.020	785.253	.000	8.636	44.796	.000	17.25	2.39	148.993	107.223	256.216
12-09	33.3	92.479	705.042	.000	8.011	40.205	.000	17.28	2.40	138.450	96.429	234.880
12-10	25.2	77.904	633.425	.000	6.599	34.777	.000	17.38	2.36	114.665	82.049	196.715
12-11	23.3	70.592	566.915	.000	5.595	27.905	.000	17.27	2.33	96.635	65.147	161.782
12-12	23.0	65.318	516.252	.000	5.273	24.950	.000	17.27	2.35	91.061	58.684	149.745
12-13	22.1	60.083	470.642	.000	4.894	22.414	.000	17.28	2.35	84.552	52.764	137.316
S TOT	1.0	1746.135	10619.340	.000	117.467	595.290	.000	17.31	2.38	2033.180	1417.549	3450.730
AFTER	1.0	388.293	3241.413	.000	35.781	200.066	.000	16.53	2.30	591.387	459.291	1050.678
TOTAL	1.0	2134.429	13860.760	.000	153.248	795.357	.000	17.13	2.36	2624.567	1876.840	4501.408

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	20.582	15.949	11.611	179.181	287.344	7.07	.000	287.344	287.344	274.446
12-03	19.260	14.007	10.671	168.056	258.362	7.24	.000	258.362	545.706	498.806
12-04	16.105	12.263	9.596	145.264	216.927	7.28	.000	216.927	762.633	670.017
12-05	14.283	10.894	8.736	133.867	186.761	7.50	.000	186.761	949.394	804.009
12-06	12.147	9.778	7.208	106.923	162.308	7.23	.000	162.308	1111.702	909.859
12-07	11.464	8.846	6.642	106.923	142.117	7.71	.000	142.117	1253.819	994.115
12-08	10.827	8.054	6.145	106.923	124.267	8.19	.000	124.267	1378.086	1061.093
12-09	10.141	7.243	5.595	103.429	108.472	8.59	.000	108.472	1486.558	1114.242
12-10	8.855	6.164	4.559	82.340	94.796	8.22	.000	94.796	1581.354	1156.467
12-11	7.845	4.896	3.625	61.318	84.098	7.58	.000	84.098	1665.452	1190.516
12-12	7.416	4.410	3.335	59.919	74.664	7.96	.000	74.664	1740.117	1217.999
12-13	6.923	3.959	3.081	57.312	66.042	8.26	.000	66.042	1806.159	1240.101
S TOT	145.848	106.464	80.803	1311.457	1806.159	11.24	.000	1806.159	1806.159	1240.101
AFTER	38.272	34.447	29.125	525.388	423.447	11.24	.000	423.447	2229.605	1324.106
TOTAL	184.119	140.910	109.928	1836.845	2229.605	11.24	.000	2229.605	2229.605	1324.106

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	69.0	15.0	LIFE, YRS.	41.17	8.00	1437.584
GROSS ULT., MB & MMF	41720.030	79721.600	DISCOUNT %	10.00	10.00	1324.106
GROSS CUM., MB & MMF	39585.600	65860.840	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1228.800
GROSS RES., MB & MMF	2134.429	13860.760	DISCOUNTED PAYOUT, YRS.	.00	15.00	1111.473
NET RES., MB & MMF	153.248	795.357	UNDISCOUNTED NET/INVEST.	.00	20.00	963.569
NET REVENUE, M$	2624.568	1876.841	DISCOUNTED NET/INVEST.	.00	25.00	854.732
INITIAL PRICE, $	19.085	2.295	RATE-OF-RETURN, PCT.	100.00	35.00	705.047
INITIAL N.I., PCT.	3.484	6.086	INITIAL W.I., PCT.	4.751	50.00	569.052
					70.00	463.128
					100.00	372.998

APPENDIX B5

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund VII-B (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 33 reserve determinations and are located in the states of Louisiana, New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 89.4 percent of the total net remaining liquid hydrocarbon reserves and 92.7 percent of the total net remaining gas reserves. The properties that we reviewed represent 90.2 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund VII-B

As of January 1, 2002

	Proved
	Developed
	Producing		Non-Producing		Undeveloped		Total Proved
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		276,189		377		3,467		280,033
Gas—MMCF		580		74		6		660
Income Data
Future Gross Revenue	$	5,842,397	$	187,100	$	76,469	$	6,105,966
Deductions		1,426,414		29,244		10,701		1,466,359
Future Net Income (FNI)	$	4,415,983	$	157,856	$	65,768	$	4,639,607
Discounted FNI @ 10%	$	2,290,394	$	117,994	$	46,753	$	2,455,141

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		32,625		745		0		33,370
Gas—MMCF		51		1		0		52
Income Data
Future Gross Revenue	$	656,249	$	13,181	$	0	$	669,430
Deductions		244,088		5,785		0		249,873
Future Net Income (FNI)	$	412,161	$	7,396	$	0	$	419,557
Discounted FNI @ 10%	$	259,288	$	6,038	$	0	$	265,326
Total Net Reserves
Oil/Condensate — Barrels		308,814		1,122		3,467		313,403
Gas—MMCF		631		75		6		712
Income Data
Future Gross Revenue	$	6,498,646	$	200,281	$	76,469	$	6,775,396
Deductions		1,670,502		35,029		10,701		1,716,232
Future Net Income (FNI)	$	4,828,144	$	165,252	$	65,768	$	5,059,164
Discounted FNI @ 10%	$	2,549,682	$	124,032	$	46,753	$	2,720,467

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)  Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A)  that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B)  the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii)  Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)  Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 10.6 percent of the total net remaining liquid hydrocarbon reserves and 7.3 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:34
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NE GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	98.0	326.116	619.889	.000	20.584	57.606	.000	18.09	2.13	372.275	122.528	494.803
12-03	98.0	307.534	538.946	.000	19.502	50.179	.000	18.09	2.13	352.778	106.904	459.682
12-04	98.0	290.408	476.149	.000	18.487	44.413	.000	18.09	2.13	334.498	94.754	429.252
12-05	97.6	274.107	423.305	.000	17.531	39.820	.000	18.10	2.14	317.275	85.050	402.324
12-06	95.7	251.438	376.604	.000	16.560	36.057	.000	18.11	2.14	299.898	77.073	376.971
12-07	95.0	235.213	342.778	.000	15.688	32.957	.000	18.12	2.14	284.232	70.503	354.736
12-08	95.0	223.646	315.184	.000	14.899	30.326	.000	18.12	2.14	269.993	64.923	334.916
12-09	93.5	212.707	283.523	.000	14.152	27.324	.000	18.13	2.14	256.512	58.576	315.088
12-10	93.0	202.348	262.615	.000	13.444	25.321	.000	18.13	2.14	243.741	54.312	298.053
12-11	92.3	192.516	238.665	.000	12.773	21.965	.000	18.13	2.18	231.625	47.816	279.441
12-12	92.0	183.067	219.967	.000	12.127	19.716	.000	18.14	2.20	219.944	43.299	263.243
12-13	92.0	174.187	205.981	.000	11.522	18.457	.000	18.14	2.20	209.033	40.549	249.582
S TOT	1.0	2873.288	4303.606	.000	187.271	404.141	.000	18.11	2.14	3391.805	866.286	4258.091
AFTER	1.0	1379.091	1914.417	.000	88.918	176.090	.000	17.84	2.16	1586.527	380.267	1966.793
TOTAL	1.0	4252.379	6218.022	.000	276.189	580.231	.000	18.03	2.15	4978.331	1246.553	6224.884

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	22.447	9.190	12.955	64.439	385.772	3.61	.000	385.772	385.772	368.216
12-03	21.284	8.018	12.011	64.439	353.930	3.80	.000	353.930	739.702	675.314
12-04	20.190	7.107	11.197	64.439	326.320	3.98	.000	326.320	1066.022	932.707
12-05	19.158	6.379	10.478	64.369	301.941	4.15	.000	301.941	1367.963	1149.214
12-06	18.130	5.780	9.779	63.136	280.145	4.29	.000	280.145	1648.108	1331.826
12-07	17.193	5.288	9.181	62.570	260.505	4.45	.000	260.505	1908.612	1486.197
12-08	16.332	4.869	8.661	62.570	242.484	4.63	.000	242.484	2151.097	1616.826
12-09	15.516	4.393	8.140	61.073	225.966	4.76	.000	225.966	2377.062	1727.488
12-10	14.743	4.073	7.695	60.574	210.967	4.93	.000	210.967	2588.029	1821.411
12-11	14.009	3.586	7.205	57.777	196.864	5.02	.000	196.864	2784.894	1901.089
12-12	13.304	3.247	6.780	56.378	183.533	5.17	.000	183.533	2968.427	1968.618
12-13	12.643	3.041	6.426	56.378	171.095	5.38	.000	171.095	3139.521	2025.849
S TOT	204.948	64.971	110.508	738.142	3139.521	11.24	.000	3139.521	3139.521	2025.849
AFTER	84.048	28.520	56.572	521.192	1276.462	11.24	.000	1276.462	4415.984	2290.394
TOTAL	288.996	93.491	167.080	1259.334	4415.983	11.24	.000	4415.983	4415.984	2290.394

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	89.0	9.0	LIFE, YRS.	41.17	8.00	2542.795
GROSS ULT., MB & MMF	30541.270	38255.780	DISCOUNT %	10.00	10.00	2290.394
GROSS CUM., MB & MMF	26288.890	32037.760	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	2083.545
GROSS RES., MB & MMF	4252.379	6218.023	DISCOUNTED PAYOUT, YRS.	.00	15.00	1836.330
NET RES., MB & MMF	276.189	580.231	UNDISCOUNTED NET/INVEST.	.00	20.00	1538.024
NET REVENUE, M$	4978.331	1246.553	DISCOUNTED NET/INVEST.	.00	25.00	1329.048
INITIAL PRICE, $	18.328	2.167	RATE-OF-RETURN, PCT.	100.00	35.00	1057.223
INITIAL N.I ., PCT.	6.297	9.285	INITIAL W.I., PCT.	4.598	50.00	826.070
					70.00	656.104
					100.00	518.054

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:40
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMC	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.1	.447	165.718	.000	.000	15.112	.000	18.07	2.64	.008	39.895	39.903
12-03	5.8	24.547	204.279	.000	.113	12.410	.000	18.07	2.64	2.035	32.750	34.785
12-04	7.0	21.728	167.747	.000	.097	9.949	.000	18.07	2.64	1.753	26.253	28.007
12-05	6.4	15.067	129.507	.000	.072	7.948	.000	18.07	2.64	1.305	20.974	22.279
12-06	5.3	9.691	99.507	.000	.049	6.343	.000	18.07	2.64	.881	16.739	17.620
12-07	4.0	5.757	76.504	.000	.030	5.061	.000	18.07	2.64	.549	13.356	13.905
12-08	2.5	2.496	52.255	.000	.015	4.015	.000	18.07	2.64	.273	10.596	10.869
12-09	1.0	.000	34.294	.000	.000	3.170	.000	.00	2.64	.000	8.368	8.368
12-10	1.0	.000	27.436	.000	.000	2.536	.000	.00	2.64	.000	6.694	6.694
12-11	1.0	.000	21.950	.000	.000	2.029	.000	.00	2.64	.000	5.356	5.356
12-12	1.0	.000	17.561	.000	.000	1.623	.000	.00	2.64	.000	4.285	4.285
12-13	1.0	.000	14.049	.000	.000	1.298	.000	.00	2.64	.000	3.428	3.428
S TOT	1.0	79.733	1010.808	.000	.377	71.492	.000	18.07	2.64	6.804	188.693	195.497
AFTER	1.0	.000	26.886	.000	.000	2.485	.000	.00	2.64	.000	6.560	6.560
TOTAL	1.0	79.733	1037.693	.000	.377	73.977	.000	18.07	2.64	6.804	195.253	202.057

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	2.992	1.107	1.420	34.383	2.19	.000	34.383	34.383	32.855
12-03	.094	2.456	.967	1.838	29.431	2.46	.000	29.431	63.813	58.409
12-04	.081	1.969	.779	1.941	23.237	2.72	.000	23.237	87.051	76.763
12-05	.060	1.573	.619	1.927	18.099	2.99	.000	18.099	105.150	89.759
12-06	.041	1.255	.490	1.863	13.971	3.30	.000	13.971	119.121	98.881
12-07	.025	1.002	.386	1.777	10.714	3.65	.000	10.714	129.836	105.239
12-08	.013	.795	.302	1.626	8.133	4.00	.000	8.133	137.969	109.629
12-09	.000	.628	.232	1.420	6.088	4.31	.000	6.088	144.057	112.616
12-10	.000	.502	.186	1.420	4.587	4.99	.000	4.587	148.644	114.661
12-11	.000	.402	.149	1.420	3.386	5.83	.000	3.386	152.030	116.034
12-12	.000	.321	.119	1.420	2.425	6.88	.000	2.425	154.455	116.929
12-13	.000	.257	.095	1.420	1.656	8.19	.000	1.656	156.111	117.484
S TOT	.313	14.152	5.431	19.490	156.111	14.32	.000	156.111	156.111	117.484
AFTER	.000	.492	.182	4.141	1.745	14.32	.000	1.745	157.856	117.994
TOTAL	.313	14.644	5.613	23.631	157.856	14.32	.000	157.856	157.856	117.994

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	6.0	1.0	LIFE, YRS.	14.92	8.00	124.193
GROSS ULT., MB & MMF	79.733	1093.566	DISCOUNT %	10.00	10.00	117.994
GROSS CUM., MB & MMF	.000	55.873	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	112.429
GROSS RES., MB & MMF	79.733	1037.693	DISCOUNTED PAYOUT, YRS.	.00	15.00	105.080
NET RES., MB & MMF	.377	73.977	UNDISCOUNTED NET/INVEST.	.00	20.00	94.947
NET REVENUE, M$	6.804	195.253	DISCOUNTED NET/INVEST.	.00	25.00	86.806
INITIAL PRICE, $	18.070	2.625	RATE-OF-RETURN, PCT.	100.00	35.00	74.572
INITIAL N.I., PC.	.444	5.973	INITIAL W.I., PCT.	3.898	50.00	62.342
					70.00	52.054
					100.00	42.778

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:46
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.6	8.863	44.314	.000	.033	.163	.000	18.07	2.60	.588	.423	1.012
12-03	5.7	76.204	321.299	.000	.280	1.180	.000	18.07	2.60	5.059	3.069	8.128
12-04	6.8	78.756	230.616	.000	1.229	.847	.000	18.97	2.60	23.306	2.203	25.509
12-05	7.0	62.989	179.726	.000	1.036	.660	.000	18.98	2.60	19.671	1.717	21.387
12-06	6.2	38.405	149.058	.000	.240	.548	.000	18.55	2.60	4.446	1.424	5.870
12-07	6.0	30.964	128.291	.000	.114	.471	.000	18.07	2.60	2.056	1.225	3.281
12-08	6.0	27.294	113.179	.000	.100	.416	.000	18.07	2.60	1.812	1.081	2.893
12-09	6.0	24.492	101.627	.000	.090	.373	.000	18.07	2.60	1.626	.971	2.597
12-10	6.0	22.276	92.474	.000	.082	.340	.000	18.07	2.60	1.479	.883	2.362
12-11	6.0	20.451	84.918	.000	.075	.312	.000	18.07	2.60	1.358	.811	2.169
12-12	6.0	18.816	78.130	.000	.069	.287	.000	18.07	2.60	1.249	.746	1.995
12-13	6.0	17.311	71.880	.000	.064	.264	.000	18.07	2.60	1.149	.687	1.836
S TOT	2.0	426.821	1595.512	.000	3.411	5.862	.000	18.71	2.60	63.798	15.240	79.038
AFTER	2.0	15.328	60.995	.000	.056	.224	.000	18.07	2.60	1.018	.583	1.600
TOTAL	2.0	442.148	1656.507	.000	3.467	6.086	.000	18.70	2.60	64.815	15.823	80.638

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.027	.032	.029	.068	.856	2.61	.000	.856	.856	.802
12-03	.233	.230	.230	.662	6.773	2.84	.000	6.773	7.630	6.684
12-04	1.072	.165	.728	.701	22.843	1.95	.000	22.843	30.472	24.561
12-05	.905	.129	.611	.701	19.042	2.05	.000	19.042	49.515	38.256
12-06	.205	.107	.167	.701	4.691	3.56	.000	4.691	54.206	41.365
12-07	.095	.092	.093	.701	2.301	5.10	.000	2.301	56.507	42.730
12-08	.083	.081	.082	.701	1.946	5.58	.000	1.946	58.453	43.779
12-09	.075	.073	.073	.701	1.675	6.06	.000	1.675	60.128	44.600
12-10	.068	.066	.067	.701	1.460	6.51	.000	1.460	61.588	45.250
12-11	.062	.061	.061	.701	1.284	6.96	.000	1.284	62.872	45.770
12-12	.057	.056	.056	.701	1.125	7.44	.000	1.125	63.997	46.184
12-13	.053	.051	.052	.701	.979	7.96	.000	.979	64.976	46.512
S TOT	2.935	1.143	2.249	7.736	64.976	10.17	.000	64.976	64.976	46.512
AFTER	.047	.044	.045	.671	.793	10.17	.000	.793	65.769	46.753
TOTAL	2.982	1.187	2.294	8.407	65.769	10.17	.000	65.769	65.769	46.753

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	7.0	.0	LIFE, YRS.	13.17	8.00	49.773
GROSS ULT., MB & MMF	442.148	1671.093	DISCOUNT %	10.00	10.00	46.753
GROSS CUM., MB & MMF	.000	14.586	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	44.020
GROSS RES., MB & MMF	442.148	1656.507	DISCOUNTED PAYOUT, YRS.	.00	15.00	40.376
NET RES., MB & MMF	3.467	6.086	UNDISCOUNTED NET/INVEST.	.00	20.00	35.289
NET REVENUE, M$	64.815	15.823	DISCOUNTED NET/INVEST.	.00	25.00	31.151
INITIAL PRICE, $	18.344	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	24.866
INITIAL N.I ., PCT.	1.416	.367	INITIAL W.I., PCT.	.397	50.00	18.570
					70.00	13.386
					100.00	8.979

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:53
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC01C2  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	99.7	335.426	829.921	.000	20.617	72.881	.000	18.09	2.23	372.871	162.847	535.718
12-03	109.5	408.285	1064.524	.000	19.895	63.770	.000	18.09	2.24	359.872	142.723	502.595
12-04	111.8	390.892	874.512	.000	19.813	55.209	.000	18.15	2.23	359.557	123.210	482.767
12-05	111.0	352.163	732.539	.000	18.640	48.428	.000	18.15	2.22	338.250	107.740	445.990
12-06	107.2	299.534	625.168	.000	16.849	42.947	.000	18.12	2.22	305.225	95.235	400.461
12-07	105.0	271.934	547.573	.000	15.832	38.489	.000	18.12	2.21	286.836	85.085	371.921
12-08	103.5	253.436	480.618	.000	15.014	34.756	.000	18.12	2.20	272.078	76.600	348.678
12-09	100.5	237.199	419.444	.000	14.242	30.867	.000	18.13	2.20	258.138	67.914	326.053
12-10	100.0	224.624	382.525	.000	13.526	28.196	.000	18.13	2.19	245.220	61.890	307.109
12-11	99.3	212.967	345.533	.000	12.848	24.305	.000	18.13	2.22	232.982	53.983	286.966
12-12	99.0	201.884	315.658	.000	12.196	21.626	.000	18.14	2.23	221.193	48.330	269.523
12-13	99.0	191.498	291.910	.000	11.586	20.019	.000	18.14	2.23	210.183	44.663	254.846
S TOT	1.0	3379.841	6909.925	.000	191.058	481.495	.000	18.12	2.22	3462.406	1070.220	4532.626
AFTER	1.0	1394.419	2002.297	.000	88.975	178.799	.000	17.84	2.17	1587.544	387.409	1974.954
TOTAL	1.0	4774.260	8912.222	.000	280.033	660.293	.000	18.03	2.21	5049.950	1457.629	6507.580

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	22.474	12.213	14.091	65.927	421.011	3.50	.000	421.011	421.011	401.872
12-03	21.610	10.704	13.208	66.938	390.134	3.68	.000	390.134	811.145	740.407
12-04	21.343	9.241	12.703	67.080	372.400	3.80	.000	372.400	1183.545	1034.030
12-05	20.123	8.081	11.708	66.997	339.082	4.00	.000	339.082	1522.628	1277.229
12-06	18.375	7.143	10.435	65.700	298.807	4.23	.000	298.807	1821.435	1472.073
12-07	17.313	6.381	9.660	65.047	273.520	4.42	.000	273.520	2094.955	1634.167
12-08	16.428	5.745	9.045	64.896	252.564	4.62	.000	252.564	2347.519	1770.235
12-09	15.591	5.094	8.446	63.193	233.729	4.76	.000	233.729	2581.248	1884.703
12-10	14.811	4.642	7.947	62.695	217.014	4.94	.000	217.014	2798.262	1981.323
12-11	14.071	4.049	7.415	59.897	201.533	5.06	.000	201.533	2999.795	2062.894
12-12	13.361	3.625	6.956	58.498	187.083	5.22	.000	187.083	3186.878	2131.732
12-13	12.696	3.350	6.573	58.498	173.729	5.44	.000	173.729	3360.608	2189.845
S TOT	208.196	80.266	118.187	765.368	3360.608	11.24	.000	3360.608	3360.608	2189.845
AFTER	84.095	29.056	56.799	526.004	1279.000	11.24	.000	1279.000	4639.609	2455.141
TOTAL	292.291	109.322	174.987	1291.372	4639.608	11.24	.000	4639.608	4639.609	2455.141

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	102.0	10.0	LIFE, YRS.	41.17	8.00	2716.762
GROSS ULT., MB & MMF	31063.150	41020.440	DISCOUNT %	10.00	10.00	2455.142
GROSS CUM., MB & MMF	26288.890	32108.220	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	2239.993
GROSS RES., MB & MMF	4774.261	8912.221	DISCOUNTED PAYOUT, YRS.	.00	15.00	1981.786
NET RES., MB & MMF	280.033	660.293	UNDISCOUNTED NET/INVEST.	.00	20.00	1668.260
NET REVENUE, M$	5049.950	1457.629	DISCOUNTED NET/INVEST.	.00	25.00	1447.005
INITIAL PRICE, $	18.314	2.398	RATE-OF-RETURN, PCT .	100.00	35.00	1156.661
INITIAL N.I ., PCT.	4.533	5.790	INITIAL W.I., PCT.	3.292	50.00	906.981
					70.00	721.544
					100.00	569.811

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:07:34
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2520.7	15993.410	38254.260	.000	5.675	6.149	.000	17.27	2.30	98.002	14.128	112.130
12-03	2520.0	13767.820	36359.580	.000	5.171	5.673	.000	17.28	2.29	89.350	13.000	102.350
12-04	2512.9	12147.870	34568.610	.000	4.507	4.997	.000	17.22	2.32	77.604	11.592	89.196
12-05	2077.3	9575.859	32866.010	.000	3.716	4.280	.000	17.11	2.37	63.580	10.144	73.723
12-06	1858.8	8342.884	31253.020	.000	1.659	3.946	.000	18.10	2.36	30.024	9.331	39.355
12-07	1858.0	7895.728	29723.990	.000	1.516	3.650	.000	18.07	2.36	27.392	8.616	36.007
12-08	1856.3	7474.087	28266.380	.000	1.424	3.355	.000	18.06	2.35	25.728	7.899	33.628
12-09	1679.3	6816.542	26721.020	.000	1.298	3.023	.000	18.11	2.36	23.506	7.129	30.635
12-10	1502.0	6200.293	25258.750	.000	1.184	2.651	.000	18.16	2.33	21.502	6.178	27.680
12-11	1499.0	5867.323	24028.210	.000	1.118	2.462	.000	18.16	2.33	20.299	5.737	26.036
12-12	1498.9	5554.674	22860.530	.000	1.056	2.272	.000	18.16	2.32	19.174	5.278	24.452
12-13	1496.8	5258.476	21746.210	.000	.906	1.265	.000	18.28	2.19	16.556	2.768	19.325
S TOT	379.0	104895.000	351906.600	.000	29.229	43.724	.000	17.54	2.33	512.718	101.799	614.517
AFTER	379.0	62303.090	344925.700	.000	3.395	7.339	.000	18.75	2.11	63.678	15.493	79.171
TOTAL	379.0	167198.000	696832.300	.000	32.625	51.064	.000	17.67	2.30	576.396	117.292	693.688

-END-   MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	4.978	1.088	2.681	36.856	66.527	6.81	.000	66.527	66.527	63.525
12-03	4.537	1.002	2.449	36.594	57.768	7.29	.000	57.768	124.295	113.672
12-04	3.858	.892	2.203	36.594	45.650	8.15	.000	45.650	169.945	149.800
12-05	3.045	.780	1.914	36.594	31.392	9.56	.000	31.392	201.337	172.347
12-06	1.490	.717	.946	9.650	26.551	5.53	.000	26.551	227.888	189.661
12-07	1.360	.662	.865	9.650	23.471	5.90	.000	23.471	251.359	203.571
12-08	1.274	.608	.810	9.650	21.286	6.22	.000	21.286	272.645	215.041
12-09	1.164	.549	.738	9.650	18.534	6.72	.000	18.534	291.179	224.130
12-10	1.065	.477	.669	9.650	15.820	7.30	.000	15.820	306.999	231.175
12-11	1.003	.443	.631	9.650	14.310	7.67	.000	14.310	321.309	236.968
12-12	.945	.407	.595	9.650	12.855	8.09	.000	12.855	334.163	241.700
12-13	.782	.210	.523	7.124	10.685	7.74	.000	10.685	344.849	245.278
S TOT	25.500	7.835	15.023	221.311	344.849	1.43	.000	344.849	344.849	245.278
AFTER	2.942	1.162	2.238	5.516	67.313	1.43	.000	67.313	412.162	259.288
TOTAL	28.442	8.997	17.261	226.827	412.162	1.43	.000	412.162	412.162	259.288

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2532.0	5.0	LIFE, YRS.	52.00	8.00	278.968
GROSS ULT., MB & MMF	2811446.000	2632644.00	DISCOUNT %	10.00	10.00	259.288
GROSS CUM., MB & MMF	2644248.000	1935812.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	242.608
GROSS RES., MB & MMF	167198.000	696832.300	DISCOUNTED PAYOUT, YRS.	.00	15.00	221.872
NET RES., MB & MMF	32.625	51.064	UNDISCOUNTED NET/INVEST.	.00	20.00	195.380
NET REVENUE, M$	576.397	117.292	DISCOUNTED NET/INVEST.	.00	25.00	175.597
INITIAL PRICE, $	17.527	2.234	RATE-OF-RETURN, PCT.	100.00	35.00	147.881
INITIAL N.I., PCT.	.039	.024	INITIAL W.I., PCT.	.025	50.00	122.004
					70.00	101.194
					100.00	82.875

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:07:37
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.8	19.112	15.289	.000	.180	.144	.000	16.72	2.35	3.009	.338	3.348
12-03	1.0	13.014	10.411	.000	.123	.098	.000	16.72	2.35	2.049	.230	2.279
12-04	1.0	10.730	8.584	.000	.101	.081	.000	16.72	2.35	1.690	.190	1.880
12-05	1.0	9.121	7.297	.000	.086	.069	.000	16.72	2.35	1.436	.161	1.598
12-06	1.0	7.753	6.202	.000	.073	.058	.000	16.72	2.35	1.221	.137	1.358
12-07	1.0	6.590	5.272	.000	.062	.050	.000	16.72	2.35	1.038	.117	1.154
12-08	1.0	5.601	4.481	.000	.053	.042	.000	16.72	2.35	.882	.099	.981
12-09	1.0	4.761	3.809	.000	.045	.036	.000	16.72	2.35	.750	.084	.834
12-10	1.0	2.440	1.952	.000	.023	.018	.000	16.72	2.35	.384	.043	.427
12-11
12-12
12-13
S TOT	1.0	79.121	63.297	.000	.745	.596	.000	16.72	2.35	12.458	1.401	13.859
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	79.121	63.297	.000	.745	.596	.000	16.72	2.35	12.458	1.401	13.859

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.138	.025	.096	.485	2.603	3.65	.000	2.603	2.603	2.466
12-03	.094	.017	.065	.647	1.456	5.93	.000	1.456	4.059	3.733
12-04	.078	.014	.054	.647	1.087	6.92	.000	1.087	5.146	4.592
12-05	.066	.012	.046	.647	.827	7.92	.000	.827	5.974	5.186
12-06	.056	.010	.039	.647	.606	9.09	.000	.606	6.580	5.582
12-07	.048	.009	.033	.647	.418	10.47	.000	.418	6.998	5.830
12-08	.041	.007	.028	.647	.258	12.09	.000	.258	7.256	5.970
12-09	.034	.006	.024	.647	.123	14.00	.000	.123	7.378	6.030
12-10	.018	.003	.012	.377	.017	15.76	.000	.017	7.396	6.038
12-11
12-12
12-13
S TOT	.573	.105	.395	5.390	7.396	15.76	.000	7.396	7.396	6.038
AFTER	.000	.000	.000	.000	.000	15.76	.000	.000	7.396	6.038
TOTAL	.573	.105	.395	5.390	7.396	15.76	.000	7.396	7.396	6.038

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	8.58	8.00	6.265
GROSS ULT., MB & MMF	79.121	63.297	DISCOUNT %	10.00	10.00	6.038
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	5.829
GROSS RES., MB & MMF	79.121	63.297	DISCOUNTED PAYOUT, YRS.	.00	15.00	5.545
NET RES., MB & MMF	.745	.596	UNDISCOUNTED NET/INVEST.	.00	20.00	5.136
NET REVENUE, M$	12.458	1.401	DISCOUNTED NET/INVEST.	.00	25.00	4.791
INITIAL PRICE, $	16.720	2.350	RATE-OF-RETURN, PCT.	100.00	35.00	4.244
INITIAL N.I., PCT.	.942	.942	INITIAL W.I., PCT.	1.230	50.00	3.659
					70.00	3.133
					100.00	2.628

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:07:43
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2521.4	16012.520	38269.550	.000	5.855	6.293	.000	17.25	2.30	101.011	14.466	115.477
12-03	2521.0	13780.830	36369.990	.000	5.293	5.771	.000	17.27	2.29	91.399	13.230	104.629
12-04	2513.9	12158.600	34577.200	.000	4.608	5.078	.000	17.21	2.32	79.294	11.782	91.076
12-05	2078.3	9584.980	32873.310	.000	3.802	4.349	.000	17.10	2.37	65.016	10.305	75.321
12-06	1859.8	8350.636	31259.220	.000	1.732	4.004	.000	18.04	2.36	31.245	9.468	40.713
12-07	1859.0	7902.318	29729.260	.000	1.578	3.700	.000	18.01	2.36	28.429	8.732	37.162
12-08	1857.3	7479.688	28270.860	.000	1.477	3.398	.000	18.02	2.35	26.610	7.999	34.609
12-09	1680.3	6821.303	26724.830	.000	1.343	3.059	.000	18.06	2.36	24.256	7.213	31.469
12-10	1502.6	6202.733	25260.700	.000	1.207	2.670	.000	18.14	2.33	21.886	6.221	28.107
12-11	1499.0	5867.323	24028.210	.000	1.118	2.462	.000	18.16	2.33	20.299	5.737	26.036
12-12	1498.9	5554.674	22860.530	.000	1.056	2.272	.000	18.16	2.32	19.174	5.278	24.452
12-13	1496.8	5258.476	21746.210	.000	.906	1.265	.000	18.28	2.19	16.556	2.768	19.325
S TOT	379.0	104974.100	351969.900	.000	29.974	44.321	.000	17.52	2.33	525.176	103.200	628.376
AFTER	379.0	62303.090	344925.700	.000	3.395	7.339	.000	18.75	2.11	63.678	15.493	79.171
TOTAL	379.0	167277.200	696895.600	.000	33.370	51.660	.000	17.65	2.30	588.854	118.693	707.547

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	5.117	1.114	2.776	37.341	69.130	6.71	.000	69.130	69.130	65.992
12-03	4.632	1.019	2.514	37.240	59.224	7.26	.000	59.224	128.354	117.406
12-04	3.935	.907	2.256	37.240	46.737	8.13	.000	46.737	175.091	154.392
12-05	3.111	.792	1.959	37.240	32.219	9.52	.000	32.219	207.311	177.533
12-06	1.547	.728	.985	10.297	27.157	5.65	.000	27.157	234.468	195.243
12-07	1.407	.671	.898	10.297	23.889	6.05	.000	23.889	258.356	209.401
12-08	1.315	.615	.838	10.297	21.544	6.39	.000	21.544	279.901	221.011
12-09	1.199	.555	.762	10.297	18.657	6.92	.000	18.657	298.558	230.160
12-10	1.082	.480	.681	10.027	15.837	7.43	.000	15.837	314.394	237.213
12-11	1.003	.443	.631	9.650	14.310	7.67	.000	14.310	328.704	243.006
12-12	.945	.407	.595	9.650	12.855	8.09	.000	12.855	341.559	247.738
12-13	.782	.210	.523	7.124	10.685	7.74	.000	10.685	352.244	251.317
S TOT	26.073	7.940	15.418	226.701	352.244	1.43	.000	352.244	352.244	251.317
AFTER	2.942	1.162	2.238	5.516	67.313	1.43	.000	67.313	419.558	265.326
TOTAL	29.016	9.102	17.656	232.217	419.558	1.43	.000	419.558	419.558	265.326

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2533.0	5.0	LIFE, YRS.	52.00	8.00	285.233
GROSS ULT., MB & MMF	2811525.000	2632708.000	DISCOUNT %	10.00	10.00	265.326
GROSS CUM., MB & MMF	2644248.000	1935812.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	248.438
GROSS RES., MB & MMF	167277.100	696895.600	DISCOUNTED PAYOUT, YRS.	.00	15.00	227.417
NET RES., MB & MMF	33.370	51.660	UNDISCOUNTED NET/INVEST.	.00	20.00	200.516
NET REVENUE, M$	588.855	118.693	DISCOUNTED NET/INVEST.	.00	25.00	180.388
INITIAL PRICE, $	17.525	2.232	RATE-OF-RETURN, PCT.	100.00	35.00	152.125
INITIAL N.I ., PCT.	.041	.024	INITIAL W.I., PCT.	.027	50.00	125.663
					70.00	104.327
					100.00	85.502

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:38:58
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.3	27.975	59.604	.000	.213	.307	.000	16.93	2.48	3.598	.762	4.359
12-03	6.7	89.218	331.710	.000	.403	1.278	.000	17.66	2.58	7.108	3.299	10.407
12-04	7.8	89.486	239.201	.000	1.330	.928	.000	18.80	2.58	24.996	2.393	27.388
12-05	8.0	72.109	187.023	.000	1.122	.729	.000	18.81	2.58	21.107	1.878	22.985
12-06	7.2	46.157	155.260	.000	.313	.606	.000	18.13	2.58	5.666	1.561	7.227
12-07	7.0	37.554	133.563	.000	.176	.521	.000	17.59	2.58	3.093	1.342	4.435
12-08	7.0	32.895	117.660	.000	.153	.458	.000	17.60	2.58	2.694	1.180	3.874
12-09	7.0	29.253	105.436	.000	.135	.409	.000	17.62	2.58	2.376	1.055	3.431
12-10	6.6	24.716	94.426	.000	.105	.358	.000	17.77	2.59	1.863	.927	2.790
12-11	6.0	20.451	84.918	.000	.075	.312	.000	18.07	2.60	1.358	.811	2.169
12-12	6.0	18.816	78.130	.000	.069	.287	.000	18.07	2.60	1.249	.746	1.995
12-13	6.0	17.311	71.880	.000	.064	.264	.000	18.07	2.60	1.149	.687	1.836
S TOT	2.0	505.942	1658.809	.000	4.156	6.458	.000	18.35	2.58	76.256	16.641	92.897
AFTER	2.0	15.328	60.995	.000	.056	.224	.000	18.07	2.60	1.018	.583	1.600
TOTAL	2.0	521.270	1719.804	.000	4.212	6.682	.000	18.35	2.58	77.274	17.224	94.497

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.165	.057	.124	.553	3.459	3.41	.000	3.459	3.459	3.268
12-03	.327	.247	.295	1.308	8.230	3.54	.000	8.230	11.689	10.417
12-04	1.150	.179	.782	1.347	23.930	2.33	.000	23.930	35.619	29.153
12-05	.971	.141	.656	1.347	19.870	2.51	.000	19.870	55.488	43.443
12-06	.261	.117	.205	1.347	5.297	4.67	.000	5.297	60.785	46.947
12-07	.142	.101	.126	1.347	2.719	6.53	.000	2.719	63.504	48.560
12-08	.124	.089	.110	1.347	2.204	7.28	.000	2.204	65.709	49.749
12-09	.109	.079	.097	1.347	1.798	8.04	.000	1.798	67.507	50.630
12-10	.086	.069	.079	1.078	1.477	7.98	.000	1.477	68.984	51.289
12-11	.062	.061	.061	.701	1.284	6.96	.000	1.284	70.267	51.808
12-12	.057	.056	.056	.701	1.125	7.44	.000	1.125	71.392	52.223
12-13	.053	.051	.052	.701	.979	7.96	.000	.979	72.371	52.550
S TOT	3.508	1.248	2.644	13.126	72.371	10.17	.000	72.371	72.371	52.550
AFTER	.047	.044	.045	.671	.793	10.17	.000	.793	73.164	52.791
TOTAL	3.555	1.292	2.690	13.797	73.164	10.17	.000	73.164	73.164	52.791

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	8.0	.0	LIFE, YRS.	13.17	8.00	56.038
GROSS ULT., MB & MMF	521.270	1734.390	DISCOUNT %	10.00	10.00	52.791
GROSS CUM., MB & MMF	.000	14.586	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	49.849
GROSS RES., MB & MMF	521.270	1719.804	DISCOUNTED PAYOUT, YRS.	.00	15.00	45.921
NET RES., MB & MMF	4.212	6.682	UNDISCOUNTED NET/INVEST.	.00	20.00	40.425
NET REVENUE, M$	77.274	17.224	DISCOUNTED NET/INVEST.	.00	25.00	35.943
INITIAL PRICE, $	18.021	2.585	RATE-OF-RETURN, PCT.	100.00	35.00	29.110
INITIAL N.I., PCT.	1.322	.402	INITIAL W.I., PCT.	.521	50.00	22.229
					70.00	16.519
					100.00	11.607

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:38:51
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.1	.447	165.718	.000	.000	15.112	.000	18.07	2.64	.008	39.895	39.903
12-03	5.8	24.547	204.279	.000	.113	12.410	.000	18.07	2.64	2.035	32.750	34.785
12-04	7.0	21.728	167.747	.000	.097	9.949	.000	18.07	2.64	1.753	26.253	28.007
12-05	6.4	15.067	129.507	.000	.072	7.948	.000	18.07	2.64	1.305	20.974	22.279
12-06	5.3	9.691	99.507	.000	.049	6.343	.000	18.07	2.64	.881	16.739	17.620
12-07	4.0	5.757	76.504	.000	.030	5.061	.000	18.07	2.64	.549	13.356	13.905
12-08	2.5	2.496	52.255	.000	.015	4.015	.000	18.07	2.64	.273	10.596	10.869
12-09	1.0	.000	34.294	.000	.000	3.170	.000	.00	2.64	.000	8.368	8.368
12-10	1.0	.000	27.436	.000	.000	2.536	.000	.00	2.64	.000	6.694	6.694
12-11	1.0	.000	21.950	.000	.000	2.029	.000	.00	2.64	.000	5.356	5.356
12-12	1.0	.000	17.561	.000	.000	1.623	.000	.00	2.64	.000	4.285	4.285
12-13	1.0	.000	14.049	.000	.000	1.298	.000	.00	2.64	.000	3.428	3.428
S TOT	1.0	79.733	1010.808	.000	.377	71.492	.000	18.07	2.64	6.804	188.693	195.497
AFTER	1.0	.000	26.886	.000	.000	2.485	.000	.00	2.64	.000	6.560	6.560
TOTAL	1.0	79.733	1037.693	.000	.377	73.977	.000	18.07	2.64	6.804	195.253	202.057

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	2.992	1.107	1.420	34.383	2.19	.000	34.383	34.383	32.855
12-03	.094	2.456	.967	1.838	29.431	2.46	.000	29.431	63.813	58.409
12-04	.081	1.969	.779	1.941	23.237	2.72	.000	23.237	87.051	76.763
12-05	.060	1.573	.619	1.927	18.099	2.99	.000	18.099	105.150	89.759
12-06	.041	1.255	.490	1.863	13.971	3.30	.000	13.971	119.121	98.881
12-07	.025	1.002	.386	1.777	10.714	3.65	.000	10.714	129.836	105.239
12-08	.013	.795	.302	1.626	8.133	4.00	.000	8.133	137.969	109.629
12-09	.000	.628	.232	1.420	6.088	4.31	.000	6.088	144.057	112.616
12-10	.000	.502	.186	1.420	4.587	4.99	.000	4.587	148.644	114.661
12-11	.000	.402	.149	1.420	3.386	5.83	.000	3.386	152.030	116.034
12-12	.000	.321	.119	1.420	2.425	6.88	.000	2.425	154.455	116.929
12-13	.000	.257	.095	1.420	1.656	8.19	.000	1.656	156.111	117.484
S TOT	.313	14.152	5.431	19.490	156.111	14.32	.000	156.111	156.111	117.484
AFTER	.000	.492	.182	4.141	1.745	14.32	.000	1.745	157.856	117.994
TOTAL	.313	14.644	5.613	23.631	157.856	14.32	.000	157.856	157.856	117.994

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	6.0	1.0	LIFE, YRS.	14.92	8.00	124.193
GROSS ULT., MB & MMF	79.733	1093.566	DISCOUNT %	10.00	10.00	117.994
GROSS CUM., MB & MMF	.000	55.873	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	112.429
GROSS RES., MB & MMF	79.733	1037.693	DISCOUNTED PAYOUT, YRS.	.00	15.00	105.080
NET RES., MB & MMF	.377	73.977	UNDISCOUNTED NET/INVEST.	.00	20.00	94.947
NET REVENUE, M$	6.804	195.253	DISCOUNTED NET/INVEST.	.00	25.00	86.806
INITIAL PRICE, $	18.070	2.625	RATE-OF-RETURN, PCT.	100.00	35.00	74.572
INITIAL N.I., PCT.	.444	5.973	INITIAL W.I., PCT.	3.898	50.00	62.342
					70.00	52.054
					100.00	42.778

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	16:46:55
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2618.7	16319.530	38874.150	.000	26.259	63.756	.000	17.91	2.14	470.277	136.656	606.933
12-03	2618.0	14075.350	36898.520	.000	24.673	55.852	.000	17.92	2.15	442.128	119.904	562.032
12-04	2610.9	12438.270	35044.760	.000	22.995	49.410	.000	17.92	2.15	412.103	106.346	518.448
12-05	2174.8	9849.967	33289.320	.000	21.247	44.100	.000	17.92	2.16	380.854	95.194	476.048
12-06	1954.5	8594.321	31629.620	.000	18.219	40.002	.000	18.11	2.16	329.922	86.404	416.326
12-07	1953.0	8130.941	30066.760	.000	17.204	36.607	.000	18.11	2.16	311.624	79.119	390.743
12-08	1951.3	7697.733	28581.560	.000	16.323	33.681	.000	18.12	2.16	295.722	72.822	368.544
12-09	1772.8	7029.249	27004.540	.000	15.450	30.347	.000	18.12	2.17	280.019	65.705	345.723
12-10	1595.0	6402.642	25521.370	.000	14.628	27.972	.000	18.13	2.16	265.242	60.490	325.732
12-11	1591.3	6059.839	24266.880	.000	13.891	24.427	.000	18.14	2.19	251.924	53.553	305.478
12-12	1590.9	5737.741	23080.500	.000	13.182	21.989	.000	18.14	2.21	239.118	48.577	287.695
12-13	1588.8	5432.663	21952.190	.000	12.428	19.722	.000	18.15	2.20	225.590	43.317	268.907
S TOT	379.2	107768.300	356210.200	.000	216.500	447.866	.000	18.03	2.16	3904.523	968.085	4872.608
AFTER	379.2	63682.180	346840.100	.000	92.314	183.429	.000	17.88	2.16	1650.205	395.760	2045.964
TOTAL	379.2	171450.400	703050.200	.000	308.814	631.294	.000	17.99	2.16	5554.727	1363.845	6918.572

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	27.425	10.278	15.636	101.295	452.299	4.19	.000	452.299	452.299	431.742
12-03	25.821	9.019	14.460	101.033	411.698	4.42	.000	411.698	863.997	788.987
12-04	24.048	7.999	13.399	101.033	371.970	4.69	.000	371.970	1235.967	1082.507
12-05	22.202	7.158	12.392	100.962	333.333	4.99	.000	333.333	1569.300	1321.561
12-06	19.621	6.498	10.725	72.786	306.696	4.41	.000	306.696	1875.996	1521.487
12-07	18.552	5.950	10.045	72.219	283.975	4.58	.000	283.975	2159.971	1689.768
12-08	17.606	5.477	9.471	72.219	263.770	4.78	.000	263.770	2423.741	1831.867
12-09	16.680	4.942	8.878	70.723	244.500	4.94	.000	244.500	2668.241	1951.617
12-10	15.808	4.550	8.364	70.224	226.787	5.13	.000	226.787	2895.028	2052.586
12-11	15.012	4.029	7.836	67.427	211.174	5.25	.000	211.174	3106.202	2138.057
12-12	14.249	3.655	7.376	66.028	196.388	5.42	.000	196.388	3302.590	2210.318
12-13	13.424	3.252	6.949	63.502	181.786	5.54	.000	181.780	3484.369	2271.127
S TOT	230.449	72.806	125.531	959.453	3484.369	10.07	.000	3484.369	3484.369	2271.127
AFTER	86.990	29.682	58.810	526.708	1343.775	10.07	.000	1343.775	4828.144	2549.682
TOTAL	317.439	102.488	184.340	1486.161	4828.144	10.07	.000	4828.144	4828.144	2549.682

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2621.0	14.0	LIFE, YRS.	52.00	8.00	2821.763
GROSS ULT., MB & MMF	2841987.000	2670900.000	DISCOUNT %	10.00	10.00	2549.682
GROSS CUM., MB & MMF	2670536.000	1967850.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	2326.153
GROSS RES., MB & MMF	171450.400	703050.200	DISCOUNTED PAYOUT, YRS.	.00	15.00	2058.202
NET RES., MB & MMF	308.814	631.294	UNDISCOUNTED NET/INVEST.	.00	20.00	1733.404
NET REVENUE, M$	5554.728	1363.845	DISCOUNTED NET/INVEST.	.00	25.00	1504.644
INITIAL PRICE, $	17.542	2.231	RATE-OF-RETURN, PCT.	100.00	35.00	1205.104
INITIAL N.I., PCT.	.159	.178	INITIAL W.I., PCT.	.113	50.00	948.073
					70.00	757.298
					100.00	600.929

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:39:04
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2621.1	16347.950	39099.470	.000	26.472	79.174	.000	17.90	2.24	473.882	177.313	651.195
12-03	2630.5	14189.120	37434.520	.000	25.188	69.540	.000	17.92	2.24	451.272	155.953	607.225
12-04	2625.7	12549.490	35451.710	.000	24.421	60.287	.000	17.97	2.24	438.851	134.992	573.843
12-05	2189.3	9937.143	33605.850	.000	22.442	52.777	.000	17.97	2.24	403.266	118.045	521.311
12-06	1967.0	8650.169	31884.390	.000	18.581	46.951	.000	18.11	2.23	336.470	104.704	441.173
12-07	1964.0	8174.252	30276.830	.000	17.410	42.189	.000	18.11	2.22	315.266	93.817	409.083
12-08	1960.8	7733.125	28751.470	.000	16.492	38.154	.000	18.11	2.22	298.688	84.599	383.287
12-09	1780.8	7058.503	27144.270	.000	15.585	33.926	.000	18.12	2.21	282.394	75.127	357.522
12-10	1602.6	6427.358	25643.230	.000	14.733	30.866	.000	18.13	2.21	267.105	68.111	335.216
12-11	1598.3	6080.290	24373.750	.000	13.966	26.767	.000	18.14	2.23	253.282	59.720	313.002
12-12	1597.9	5756.558	23176.190	.000	13.251	23.899	.000	18.14	2.24	240.367	53.608	293.975
12-13	1595.8	5449.974	22038.120	.000	12.492	21.284	.000	18.15	2.23	226.739	47.431	274.170
S TOT	379.2	108353.900	358879.800	.000	221.032	525.815	.000	18.04	2.23	3987.583	1173.420	5161.002
AFTER	379.2	63697.500	346928.000	.000	92.370	186.138	.000	17.88	2.16	1651.222	402.902	2054.125
TOTAL	379.2	172051.400	705807.700	.000	313.402	711.953	.000	17.99	2.21	5638.805	1576.322	7215.127

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	27.591	13.327	16.868	103.268	490.141	4.06	.000	490.141	490.141	467.864
12-03	26.242	11.723	15.722	104.179	449.359	4.29	.000	449.359	939.500	857.813
12-04	25.278	10.147	14.960	104.321	419.137	4.49	.000	419.137	1358.637	1188.422
12-05	23.233	8.872	13.668	104.237	371.301	4.80	.000	371.301	1729.938	1454.762
12-06	19.922	7.870	11.420	75.997	325.965	4.36	.000	325.965	2055.903	1667.315
12-07	18.720	7.053	10.558	75.344	297.409	4.57	.000	297.409	2353.312	1843.568
12-08	17.743	6.360	9.883	75.193	274.108	4.78	.000	274.108	2627.420	1991.246
12-09	16.790	5.649	9.207	73.490	252.386	4.95	.000	252.386	2879.805	2114.863
12-10	15.893	5.122	8.628	72.722	232.851	5.15	.000	232.851	3112.656	2218.536
12-11	15.074	4.491	8.046	69.547	215.843	5.27	.000	215.843	3328.500	2305.899
12-12	14.306	4.032	7.551	68.148	199.937	5.46	.000	199.937	3528.437	2379.469
12-13	13.477	3.560	7.096	65.623	184.415	5.60	.000	184.415	3712.852	2441.161
S TOT	234.269	88.206	133.606	992.069	3712.852	10.07	.000	3712.852	3712.852	2441.161
AFTER	87.037	30.218	59.037	531.520	1346.313	10.07	.000	1346.313	5059.165	2720.467
TOTAL	321.307	118.424	192.643	1523.589	5059.165	10.07	.000	5059.165	5059.165	2720.467

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2635.0	15.0	LIFE, YRS.	52.00	8.00	3001.994
GROSS ULT., MB & MMF	2842588.000	2673728.000	DISCOUNT %	10.00	10.00	2720.468
GROSS CUM., MB & MMF	2670536.000	1967920.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	2488.431
GROSS RES., MB & MMF	172051.400	705807.700	DISCOUNTED PAYOUT, YRS.	.00	15.00	2209.204
NET RES., MB & MMF	313.402	711.953	UNDISCOUNTED NET/INVEST.	.00	20.00	1868.776
NET REVENUE, M$	5638.805	1576.322	DISCOUNTED NET/INVEST.	.00	25.00	1627.393
INITIAL PRICE, $	17.548	2.238	RATE-OF-RETURN, PCT.	100.00	35.00	1308.786
INITIAL N.I., PCT.	.171	.222	INITIAL W.I., PCT.	.131	50.00	1032.644
					70.00	825.871
					100.00	655.313

APPENDIX B6

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund VIII-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 34 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 94.5 percent of the total net remaining liquid hydrocarbon reserves and 85.6 percent of the total net remaining gas reserves. The properties that we reviewed represent 96.7 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund VIII-A

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		296,481		516		24,917		321,914
Gas—MMCF		309		3		3		315
Income Data
Future Gross Revenue	$	5,783,953	$	15,004	$	450,516	$	6,249,473
Deductions		3,561,069		2,317		172,179		3,735,565
Future Net Income (FNI)	$	2,222,884	$	12,687	$	278,337	$	2,513,908
Discounted FNI @ 10%	$	1,378,858	$	9,590	$	155,648	$	1,544,096

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		18,697		0		0		18,697
Gas—MMCF		53		0		0		53
Income Data
Future Gross Revenue	$	451,238	$	0	$	0	$	451,238
Deductions		386,809		0		0		386,809
Future Net Income (FNI)	$	64,429	$	0	$	0	$	64,429
Discounted FNI @ 10%	$	53,114	$	0	$	0	$	53,114
Total Net Reserves
Oil/Condensate—Barrels		315,178		516		24,917		340,611
Gas—MMCF		362		3		3		368
Income Data
Future Gross Revenue	$	6,235,191	$	15,004	$	450,516	$	6,700,711
Deductions		3,947,878		2,317		172,179		4,122,374
Future Net Income (FNI)	$	2,287,313	$	12,687	$	278,337	$	2,578,337
Discounted FNI @ 10%	$	1,431,972	$	9,590	$	155,648	$	1,597,210

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 5.5 percent of the total net remaining liquid hydrocarbon reserves and 14.4 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:46:29
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	41.0	123.822	234.891	.000	29.730	30.441	.000	18.04	2.49	536.322	75.743	612.065
12-03	41.0	116.569	215.993	.000	28.047	28.733	.000	18.04	2.49	505.933	71.445	577.378
12-04	40.8	109.346	198.480	.000	26.453	27.126	.000	18.04	2.48	477.135	67.401	544.536
12-05	39.8	100.324	181.459	.000	24.386	25.587	.000	18.02	2.48	439.452	63.525	502.977
12-06	38.0	87.162	168.180	.000	20.084	24.208	.000	17.92	2.48	359.832	60.072	419.904
12-07	38.0	82.478	156.166	.000	19.036	22.913	.000	17.92	2.48	341.109	56.829	397.938
12-08	38.0	78.051	145.256	.000	18.044	21.693	.000	17.92	2.48	323.371	53.778	377.149
12-09	35.0	71.025	133.553	.000	16.955	20.452	.000	17.94	2.48	304.134	50.657	354.791
12-10	28.8	61.655	118.328	.000	15.782	19.179	.000	17.97	2.47	283.615	47.441	331.056
12-11	23.0	52.848	75.699	.000	12.949	11.641	.000	17.94	2.70	232.361	31.424	263.785
12-12	22.0	48.501	66.346	.000	12.205	10.767	.000	17.94	2.72	218.985	29.252	248.237
12-13	21.3	45.362	62.744	.000	11.354	10.210	.000	17.94	2.71	203.694	27.715	231.409
S TOT	3.5	977.143	1757.096	.000	235.025	252.951	.000	17.98	2.51	4225.942	635.284	4861.226
AFTER	3.5	296.633	366.409	.000	61.455	56.411	.000	17.27	2.91	1061.524	164.403	1225.927
TOTAL	3.5	1273.776	2123.505	.000	296.481	309.362	.000	17.83	2.58	5287.466	799.687	6087.153

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	24.671	5.681	18.075	271.135	292.504	9.18	.000	292.504	292.504	279.244
12-03	23.273	5.358	17.053	271.135	260.559	9.65	.000	260.559	553.062	505.389
12-04	21.948	5.055	16.086	270.826	230.621	10.13	.000	230.621	783.683	687.363
12-05	20.215	4.764	14.870	260.460	202.668	10.48	.000	202.668	986.352	832.751
12-06	16.552	4.505	12.467	206.869	179.510	9.97	.000	179.510	1165.862	949.803
12-07	15.691	4.262	11.815	206.869	159.301	10.44	.000	159.301	1325.163	1044.241
12-08	14.875	4.033	11.197	206.869	140.174	10.94	.000	140.174	1465.337	1119.790
12-09	13.990	3.799	10.521	204.388	122.092	11.43	.000	122.092	1587.429	1179.617
12-10	13.046	3.558	9.793	199.388	105.271	11.90	.000	105.271	1692.699	1226.516
12-11	10.689	2.357	7.862	152.163	90.714	11.62	.000	90.714	1783.414	1263.253
12-12	10.073	2.194	7.401	150.441	78.128	12.15	.000	78.128	1861.542	1292.019
12-13	9.370	2.079	6.904	146.790	66.267	12.65	.000	66.267	1927.809	1314.203
S TOT	194.393	47.646	144.045	2547.333	1927.809	16.07	.000	1927.809	1927.809	1314.203
AFTER	48.830	12.330	38.568	831.123	295.076	16.07	.000	295.076	2222.885	1378.858
TOTAL	243.223	59.977	182.613	3378.456	2222.885	16.07	.000	2222.885	2222.885	1378.858

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	33.0	8.0	LIFE, YRS.	31.00	8.00	1491.389
GROSS ULT., MB & MMF	14605.560	8117.415	DISCOUNT %	10.00	10.00	1378.858
GROSS CUM., MB & MMF	13331.790	5993.910	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1282.821
GROSS RES., MB & MMF	1273.776	2123.505	DISCOUNTED PAYOUT, YRS.	.00	15.00	1162.761
NET RES., MB & MMF	296.481	309.362	UNDISCOUNTED NET/INVEST.	.00	20.00	1008.797
NET REVENUE, M$	5287.465	799.687	DISCOUNTED NET/INVEST.	.00	25.00	893.959
INITIAL PRICE, $	17.669	2.555	RATE-OF-RETURN, PCT.	100.00	35.00	734.624
INITIAL N.I., PCT.	23.982	12.799	INITIAL W.I., PCT.	27.262	50.00	589.434
					70.00	476.821
					100.00	381.782

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:46:33
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.447	2.233	.000	.014	.068	.000	18.07	2.60	.245	.177	.422
12-03	1.8	8.131	37.941	.000	.146	.721	.000	18.07	2.60	2.647	1.876	4.522
12-04	2.0	6.551	30.352	.000	.110	.540	.000	18.07	2.60	1.987	1.404	3.391
12-05	2.0	5.220	24.201	.000	.088	.433	.000	18.07	2.60	1.594	1.127	2.720
12-06	2.0	4.383	20.331	.000	.074	.365	.000	18.07	2.60	1.343	.950	2.293
12-07	2.0	3.803	17.643	.000	.065	.318	.000	18.07	2.60	1.169	.826	1.995
12-08	1.7	1.389	6.320	.000	.019	.093	.000	18.07	2.60	.344	.241	.585
12-09
12-10
12-11
12-12
12-13
S TOT	1.7	29.924	139.022	.000	.516	2.538	.000	18.07	2.60	9.328	6.600	15.928
AFTER	1.7	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.7	29.924	139.022	.000	.516	2.538	.000	18.07	2.60	9.328	6.600	15.928

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.011	.013	.012	.019	.366	2.23	.000	.366	.366	.334
12-03	.122	.141	.128	.327	3.805	2.69	.000	3.805	4.171	3.642
12-04	.091	.105	.096	.346	2.752	3.20	.000	2.752	6.923	5.816
12-05	.073	.084	.077	.346	2.139	3.62	.000	2.139	9.062	7.352
12-06	.062	.071	.065	.346	1.749	4.02	.000	1.749	10.811	8.493
12-07	.054	.062	.056	.346	1.476	4.41	.000	1.476	12.288	9.368
12-08	.016	.018	.017	.135	.400	5.38	.000	.400	12.687	9.590
12-09
12-10
12-11
12-12
12-13
S TOT	.429	.495	.450	1.867	12.687	5.38	.000	12.687	12.687	9.590
AFTER	.000	.000	.000	.000	.000	5.38	.000	.000	12.687	9.590
TOTAL	.429	.495	.450	1.867	12.687	5.38	.000	12.687	12.687	9.590

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	6.50	8.00	10.105
GROSS ULT., MB & MMF	29.924	166.586	DISCOUNT %	10.00	10.00	9.590
GROSS CUM., MB & MMF	.000	27.564	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	9.117
GROSS RES., MB & MMF	29.924	139.022	DISCOUNTED PAYOUT, YRS.	.00	15.00	8.474
NET RES., MB & MMF	.516	2.538	UNDISCOUNTED NET/INVEST.	.00	20.00	7.557
NET REVENUE, M$	9.328	6.600	DISCOUNTED NET/INVEST.	.00	25.00	6.793
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	5.603
INITIAL N.I., PCT.	1.722	1.823	INITIAL W.I., PCT.	2.442	50.00	4.375
					70.00	3.330
					100.00	2.403

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:46:40
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.0	4.551	18.203	.000	.019	.078	.000	19.10	2.59	.371	.201	.573
12-03	5.3	64.169	199.685	.000	.813	.698	.000	18.84	2.59	15.323	1.808	17.131
12-04	8.8	118.971	168.487	.000	3.084	.544	.000	18.66	2.59	57.556	1.410	58.966
12-05	9.0	93.145	129.179	.000	2.392	.421	.000	18.68	2.59	44.688	1.090	45.778
12-06	9.0	75.400	106.195	.000	2.057	.347	.000	18.66	2.59	38.391	.900	39.291
12-07	9.0	63.606	90.893	.000	1.802	.298	.000	18.65	2.59	33.606	.772	34.379
12-08	9.0	56.509	79.879	.000	1.617	.262	.000	18.65	2.59	30.149	.680	30.828
12-09	9.0	51.132	71.515	.000	1.473	.235	.000	18.65	2.59	27.461	.609	28.071
12-10	9.0	46.830	64.815	.000	1.360	.213	.000	18.64	2.59	25.350	.553	25.903
12-11	7.2	37.841	38.486	.000	1.235	.106	.000	18.63	2.59	22.995	.276	23.271
12-12	5.7	30.960	20.271	.000	1.126	.035	.000	18.62	2.59	20.960	.092	21.052
12-13	5.0	26.647	11.988	.000	1.034	.008	.000	18.63	2.60	19.268	.021	19.290
S TOT	1.0	669.761	999.595	.000	18.013	3.248	.000	18.66	2.59	336.118	8.413	344.532
AFTER	1.0	150.563	15.699	.000	6.904	.011	.000	18.53	2.60	127.936	.028	127.964
TOTAL	1.0	820.324	1015.294	.000	24.917	3.258	.000	18.62	2.59	464.055	8.441	472.496

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.017	.015	.016	.117	.407	5.11	.000	.407	.407	.371
12-03	.705	.136	.489	1.517	14.285	3.06	.000	14.285	14.692	12.558
12-04	2.648	.106	1.686	8.112	46.415	3.95	.000	46.415	61.107	49.239
12-05	2.056	.082	1.309	8.284	34.047	4.76	.000	34.047	95.154	73.677
12-06	1.766	.067	1.124	8.284	28.050	5.31	.000	28.050	123.203	91.977
12-07	1.546	.058	.983	8.284	23.507	5.87	.000	23.507	146.710	105.917
12-08	1.387	.051	.882	8.284	20.224	6.39	.000	20.224	166.935	116.818
12-09	1.263	.046	.803	8.284	17.674	6.88	.000	17.674	184.609	125.478
12-10	1.166	.041	.741	8.284	15.670	7.33	.000	15.670	200.279	132.457
12-11	1.058	.021	.666	8.070	13.457	7.84	.000	13.457	213.736	137.908
12-12	.964	.007	.602	7.894	11.584	8.37	.000	11.584	225.320	142.173
12-13	.886	.002	.552	7.816	10.034	8.94	.000	10.034	235.354	145.531
S TOT	15.461	.631	9.853	83.232	235.354	17.98	.000	235.354	235.354	145.531
AFTER	5.885	.002	3.662	75.432	42.983	17.98	.000	42.983	278.337	155.648
TOTAL	21.347	.633	13.515	158.664	278.337	17.98	.000	278.337	278.337	155.648

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	9.0	.0	LIFE, YRS.	24.83	8.00	172.121
GROSS ULT., MB & MMF	820.324	1109.397	DISCOUNT %	10.00	10.00	155.648
GROSS CUM., MB & MMF	.000	94.103	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	141.608
GROSS RES., MB & MMF	820.324	1015.294	DISCOUNTED PAYOUT, YRS.	.00	15.00	124.115
NET RES., MB & MMF	24.917	3.258	UNDISCOUNTED NET/INVEST.	.00	20.00	101.854
NET REVENUE, M$	464.055	8.441	DISCOUNTED NET/INVEST.	.00	25.00	85.457
INITIAL PRICE, $	18.604	2.593	RATE-OF-RETURN, PCT.	100.00	35.00	63.186
INITIAL N.I., PCT.	2.516	.310	INITIAL W.I., PCT.	2.719	50.00	43.696
					70.00	29.500
					100.00	18.596

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:46:47
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	42.1	128.819	255.327	.000	29.763	30.587	.000	18.04	2.49	536.939	76.121	613.060
12-03	48.1	188.868	453.620	.000	29.007	30.153	.000	18.06	2.49	523.902	75.129	599.032
12-04	51.5	234.868	397.319	.000	29.647	28.210	.000	18.10	2.49	536.677	70.216	606.893
12-05	50.8	198.689	334.839	.000	26.867	26.441	.000	18.08	2.49	485.734	65.742	551.476
12-06	49.0	166.945	294.706	.000	22.216	24.921	.000	17.99	2.48	399.567	61.922	461.489
12-07	49.0	149.886	264.703	.000	20.903	23.529	.000	17.98	2.48	375.884	58.428	434.312
12-08	47.8	135.949	231.455	.000	19.680	22.048	.000	17.98	2.48	353.864	54.699	408.562
12-09	44.0	122.157	205.068	.000	18.428	20.687	.000	17.99	2.48	331.595	51.266	382.861
12-10	37.8	108.485	183.142	.000	17.142	19.393	.000	18.02	2.47	308.964	47.994	356.959
12-11	30.2	90.689	114.185	.000	14.183	11.748	.000	18.00	2.70	255.356	31.700	287.056
12-12	27.7	79.461	86.618	.000	13.331	10.803	.000	18.00	2.72	239.944	29.344	269.289
12-13	26.3	72.009	74.731	.000	12.388	10.218	.000	18.00	2.71	222.963	27.736	250.699
S TOT	3.5	1676.828	2895.713	.000	253.554	258.737	.000	18.03	2.51	4571.389	650.297	5221.685
AFTER	3.5	447.197	382.108	.000	68.360	56.422	.000	17.40	2.91	1189.460	164.431	1353.892
TOTAL	3.5	2124.024	3277.821	.000	321.914	315.159	.000	17.90	2.59	5760.849	814.728	6575.577

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	24.699	5.709	18.103	271.271	293.277	9.17	.000	293.277	293.277	279.949
12-03	24.100	5.635	17.670	272.979	278.649	9.41	.000	278.649	571.926	521.589
12-04	24.687	5.266	17.868	279.284	279.787	9.52	.000	279.787	851.713	742.418
12-05	22.344	4.931	16.256	269.091	238.854	10.00	.000	238.854	1090.567	913.779
12-06	18.380	4.644	13.656	215.500	209.309	9.56	.000	209.309	1299.876	1050.273
12-07	17.291	4.382	12.855	215.500	184.285	10.07	.000	184.285	1484.161	1159.526
12-08	16.278	4.102	12.096	215.289	160.798	10.61	.000	160.798	1644.959	1246.199
12-09	15.253	3.845	11.324	212.673	139.766	11.11	.000	139.766	1784.725	1314.685
12-10	14.212	3.600	10.534	207.673	120.940	11.58	.000	120.940	1905.665	1368.563
12-11	11.746	2.377	8.528	160.233	104.171	11.33	.000	104.171	2009.837	1410.751
12-12	11.037	2.201	8.004	158.335	89.712	11.87	.000	89.712	2099.549	1443.782
12-13	10.256	2.080	7.456	154.605	76.301	12.38	.000	76.301	2175.850	1469.324
S TOT	210.284	48.772	154.348	2632.432	2175.850	16.07	.000	2175.850	2175.850	1469.324
AFTER	54.715	12.332	42.230	906.555	338.059	16.07	.000	338.059	2513.909	1544.097
TOTAL	264.999	61.105	196.579	3538.986	2513.909	16.07	.000	2513.909	2513.909	1544.097

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	44.0	8.0	LIFE, YRS.	31.00	8.00	1673.616
GROSS ULT., MB & MMF	15455.810	9393.398	DISCOUNT %	10.00	10.00	1544.097
GROSS CUM., MB & MMF	13331.790	6115.577	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1433.546
GROSS RES., MB & MMF	2124.024	3277.821	DISCOUNTED PAYOUT, YRS.	.00	15.00	1295.350
NET RES., MB & MMF	321.914	315.159	UNDISCOUNTED NET/INVEST.	.00	20.00	1118.207
NET REVENUE, M$	5760.849	814.728	DISCOUNTED NET/INVEST.	.00	25.00	986.209
INITIAL PRICE, $	18.202	2.576	RATE-OF-RETURN, PCT.	100.00	35.00	803.413
INITIAL N.I., PCT.	11.291	6.103	INITIAL W.I., PCT.	12.721	50.00	637.504
					70.00	509.651
					100.00	402.781

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:08:21
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	17.3	18.201	82.804	.000	5.138	12.113	.000	18.32	2.54	94.106	30.724	124.830
12-03	15.2	13.403	64.611	.000	4.614	10.680	.000	18.28	2.52	84.326	26.916	111.242
12-04	14.5	12.004	53.850	.000	4.081	9.517	.000	18.29	2.52	74.643	24.004	98.647
12-05	10.7	6.988	33.043	.000	2.050	6.198	.000	18.43	2.61	37.771	16.150	53.921
12-06	9.3	4.954	25.924	.000	1.366	4.730	.000	18.37	2.69	25.100	12.747	37.848
12-07	7.7	3.241	21.293	.000	.937	3.831	.000	18.22	2.73	17.078	10.449	27.527
12-08	3.2	.630	9.135	.000	.149	1.511	.000	16.88	2.81	2.512	4.250	6.761
12-09	2.8	.392	7.381	.000	.076	1.173	.000	15.87	2.81	1.212	3.299	4.511
12-10	2.0	.362	5.150	.000	.071	.850	.000	15.87	2.62	1.120	2.229	3.349
12-11	2.0	.334	4.805	.000	.065	.792	.000	15.87	2.63	1.034	2.082	3.116
12-12	1.9	.309	4.284	.000	.060	.710	.000	15.87	2.60	.955	1.848	2.804
12-13	1.0	.285	1.859	.000	.056	.363	.000	15.87	1.93	.883	.700	1.582
S TOT	1.0	61.104	314.139	.000	18.663	52.468	.000	18.26	2.58	340.741	135.397	476.137
AFTER	1.0	.178	1.161	.000	.035	.226	.000	15.87	1.93	.551	.437	.988
TOTAL	1.0	61.282	315.301	.000	18.697	52.694	.000	18.25	2.58	341.291	135.834	477.125

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	4.329	2.304	3.440	92.976	21.781	14.40	.000	21.781	21.781	20.825
12-03	3.879	2.019	3.074	86.518	15.753	14.94	.000	15.753	37.533	34.523
12-04	3.434	1.800	2.725	80.353	10.335	15.58	.000	10.335	47.869	42.702
12-05	1.737	1.211	1.458	43.157	6.357	15.43	.000	6.357	54.226	47.273
12-06	1.155	.956	1.006	30.688	4.043	15.69	.000	4.043	58.268	49.916
12-07	.786	.784	.723	22.963	2.271	16.03	.000	2.271	60.540	51.269
12-08	.116	.319	.163	4.823	1.341	13.53	.000	1.341	61.881	51.993
12-09	.056	.247	.105	3.153	.950	13.10	.000	.950	62.830	52.459
12-10	.052	.167	.081	2.361	.687	12.54	.000	.687	63.518	52.765
12-11	.048	.156	.076	2.361	.475	13.39	.000	.475	63.993	52.958
12-12	.044	.139	.069	2.274	.279	14.14	.000	.279	64.272	53.061
12-13	.041	.052	.045	1.313	.131	12.51	.000	.131	64.403	53.106
S TOT	15.674	10.155	12.964	372.942	64.403	13.27	.000	64.403	64.403	53.106
AFTER	.025	.033	.028	.876	.026	13.27	.000	.026	64.429	53.114
TOTAL	15.699	10.188	12.991	373.818	64.429	13.27	.000	64.429	64.429	53.114

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	40.0	10.0	LIFE, YRS.	12.67	8.00	54.990
GROSS ULT., MB & MMF	6581.091	7470.434	DISCOUNT %	10.00	10.00	53.114
GROSS CUM., MB & MMF	6519.808	7155.133	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	51.385
GROSS RES., MB & MMF	61.282	315.301	DISCOUNTED PAYOUT, YRS.	.00	15.00	49.033
NET RES., MB & MMF	18.697	52.694	UNDISCOUNTED NET/INVEST.	.00	20.00	45.648
NET REVENUE, M$	341.291	135.834	DISCOUNTED NET/INVEST.	.00	25.00	42.794
INITIAL PRICE, $	18.072	2.450	RATE-OF-RETURN, PCT.	100.00	35.00	38.245
INITIAL N.I., PCT.	30.225	18.828	INITIAL W.I., PCT.	33.247	50.00	33.335
					70.00	28.872
					100.00	24.547

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:39:43
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	58.3	142.023	317.695	.000	34.868	42.554	.000	18.08	2.50	630.428	106.467	736.895
12-03	56.2	129.972	280.604	.000	32.661	39.413	.000	18.07	2.50	590.259	98.361	688.620
12-04	55.3	121.351	252.330	.000	30.534	36.643	.000	18.07	2.49	551.778	91.405	643.183
12-05	50.4	107.312	214.502	.000	26.436	31.785	.000	18.05	2.51	477.223	79.676	556.898
12-06	47.3	92.115	194.104	.000	21.450	28.938	.000	17.95	2.52	384.932	72.820	457.752
12-07	45.7	85.719	177.459	.000	19.974	26.743	.000	17.93	2.52	358.187	67.278	425.465
12-08	41.2	78.681	154.391	.000	18.193	23.204	.000	17.91	2.50	325.883	58.027	383.910
12-09	37.8	71.416	140.934	.000	17.031	21.625	.000	17.93	2.50	305.346	53.956	359.302
12-10	30.8	62.017	123.477	.000	15.853	20.030	.000	17.96	2.48	284.734	49.670	334.405
12-11	25.0	53.182	80.504	.000	13.014	12.433	.000	17.93	2.69	233.396	33.506	266.901
12-12	23.9	48.810	70.630	.000	12.266	11.477	.000	17.93	2.71	219.940	31.101	251.041
12-13	22.3	45.648	64.603	.000	11.409	10.572	.000	17.93	2.69	204.577	28.414	232.991
S TOT	3.5	1038.247	2071.235	.000	253.688	305.419	.000	18.00	2.52	4566.683	770.680	5337.364
AFTER	3.5	296.811	367.570	.000	61.490	56.638	.000	17.27	2.91	1062.075	164.840	1226.915
TOTAL	3.5	1335.059	2438.806	.000	315.178	362.056	.000	17.86	2.58	5628.758	935.521	6564.279

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	29.000	7.985	21.515	364.111	314.284	10.07	.000	314.284	314.284	300.069
12-03	27.152	7.377	20.127	357.653	276.311	10.51	.000	276.311	590.596	539.911
12-04	25.382	6.855	18.811	351.179	240.956	10.98	.000	240.956	831.552	730.065
12-05	21.952	5.976	16.328	303.617	209.026	10.96	.000	209.026	1040.577	880.023
12-06	17.707	5.461	13.474	237.557	183.553	10.44	.000	183.553	1224.130	999.719
12-07	16.477	5.046	12.538	229.832	161.572	10.80	.000	161.572	1385.702	1095.509
12-08	14.991	4.352	11.360	211.692	141.515	10.99	.000	141.515	1527.217	1171.783
12-09	14.046	4.047	10.625	207.542	123.042	11.45	.000	123.042	1650.259	1232.076
12-10	13.098	3.725	9.874	201.749	105.958	11.90	.000	105.958	1756.217	1279.281
12-11	10.736	2.513	7.938	154.524	91.190	11.65	.000	91.190	1847.407	1316.211
12-12	10.117	2.333	7.470	152.715	78.407	12.18	.000	78.407	1925.813	1345.080
12-13	9.411	2.131	6.949	148.103	66.398	12.65	.000	66.398	1992.212	1367.308
S TOT	210.067	57.801	157.009	2920.275	1992.212	16.07	.000	1992.212	1992.212	1367.308
AFTER	48.855	12.363	38.596	831.998	295.102	16.07	.000	295.102	2287.314	1431.972
TOTAL	258.923	70.164	195.604	3752.273	2287.314	16.07	.000	2287.314	2287.314	1431.972

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	73.0	18.0	LIFE, YRS.	31.00	8.00	1546.380
GROSS ULT., MB & MMF	21186.650	15587.850	DISCOUNT %	10.0	10.00	1431.972
GROSS CUM., MB & MMF	19851.600	13149.040	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1334.206
GROSS RES., MB & MMF	1335.059	2438.806	DISCOUNTED PAYOUT, YRS.	.00	15.00	1211.794
NET RES., MB & MMF	315.178	362.056	UNDISCOUNTED NET/INVEST.	.00	20.00	1054.445
NET REVENUE, M$	5628.757	935.521	DISCOUNTED NET/ INVEST.	.00	25.00	936.753
INITIAL PRICE, $	17.778	2.513	RATE-OF-RETURN, PCT.	100.00	35.00	772.869
INITIAL N.I., PCT.	25.671	15.172	INITIAL W.I., PCT.	29.067	50.00	622.769
					70.00	505.693
					100.00	406.329

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:39:44
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MMBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.447	2.233	.000	.014	.068	.000	18.07	2.60	.245	.177	.422
12-03	1.8	8.131	37.941	.000	.146	.721	.000	18.07	2.60	2.647	1.876	4.522
12-04	2.0	6.551	30.352	.000	.110	.540	.000	18.07	2.60	1.987	1.404	3.391
12-05	2.0	5.220	24.201	.000	.088	.433	.000	18.07	2.60	1.594	1.127	2.720
12-06	2.0	4.383	20.331	.000	.074	.365	.000	18.07	2.60	1.343	.950	2.293
12-07	2.0	3.803	17.643	.000	.065	.318	.000	18.07	2.60	1.169	.826	1.995
12-08	1.7	1.389	6.320	.000	.019	.093	.000	18.07	2.60	.344	.241	.585
12-09
12-10
12-11
12-12
12-13
S TOT	1.7	29.924	139.022	.000	.516	2.538	.000	18.07	2.60	9.328	6.600	15.928
AFTER	1.7	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.7	29.924	139.022	.000	.516	2.538	.000	18.07	2.60	9.328	6.600	15.928

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.011	.013	.012	.019	.366	2.23	.000	.366	.366	.334
12-03	.122	.141	.128	.327	3.805	2.69	.000	3.805	4.171	3.642
12-04	.091	.105	.096	.346	2.752	3.20	.000	2.752	6.923	5.816
12-05	.073	.084	.077	.346	2.139	3.62	.000	2.139	9.062	7.352
12-06	.062	.071	.065	.346	1.749	4.02	.000	1.749	10.811	8.493
12-07	.054	.062	.056	.346	1.476	4.41	.000	1.476	12.288	9.368
12-08	.016	.018	.017	.135	.400	5.38	.000	.400	12.687	9.590
12-09
12-10
12-11
12-12
12-13
S TOT	.429	.495	.450	1.867	12.687	5.38	.000	12.687	12.687	9.590
AFTER	.000	.000	.000	.000	.000	5.38	.000	.000	12.687	9.590
TOTAL	.429	.495	.450	1.867	12.687	5.38	.000	12.687	12.687	9.590

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	6.50	8.00	10.105
GROSS ULT., MB & MMF	29.924	166.586	DISCOUNT %	10.00	10.00	9.590
GROSS CUM., MB & MMF	.000	27.564	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	9.117
GROSS RES., MB & MMF	29.924	139.022	DISCOUNTED PAYOUT, YRS.	.00	15.00	8.474
NET RES., MB & MMF	.516	2.538	UNDISCOUNTED NET/INVEST.	.00	20.00	7.557
NET REVENUE, M$	9.328	6.600	DISCOUNTED NET/INVEST.	.00	25.00	6.793
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	5.603
INITIAL N.I., PCT.	1.722	1.823	INITIAL W.I., PCT.	2.442	50.00	4.375
					70.00	3.330
					100.00	2.403

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:39:51
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.0	4.551	18.203	.000	.019	.078	.000	19.10	2.59	.371	.201	.573
12-03	5.3	64.169	199.685	.000	.813	.698	.000	18.84	2.59	15.323	1.808	17.131
12-04	8.8	118.971	168.487	.000	3.084	.544	.000	18.66	2.59	57.556	1.410	58.966
12-05	9.0	93.145	129.179	.000	2.392	.421	.000	18.68	2.59	44.688	1.090	45.778
12-06	9.0	75.400	106.195	.000	2.057	.347	.000	18.66	2.59	38.391	.900	39.291
12-07	9.0	63.606	90.893	.000	1.802	.298	.000	18.65	2.59	33.606	.772	34.379
12-08	9.0	56.509	79.879	.000	1.617	.262	.000	18.65	2.59	30.149	.680	30.828
12-09	9.0	51.132	71.515	.000	1.473	.235	.000	18.65	2.59	27.461	.609	28.071
12-10	9.0	46.830	64.815	.000	1.360	.213	.000	18.64	2.59	25.350	.553	25.903
12-11	7.2	37.841	38.486	.000	1.235	.106	.000	18.63	2.59	22.995	.276	23.271
12-12	5.7	30.960	20.271	.000	1.126	.035	.000	18.62	2.59	20.960	.092	21.052
12-13	5.0	26.647	11.988	.000	1.034	.008	.000	18.63	2.60	19.268	.021	19.290
S TOT	1.0	669.761	999.595	.000	18.013	3.248	.000	18.66	2.59	336.118	8.413	344.532
AFTER	1.0	150.563	15.699	.000	6.904	.011	.000	18.53	2.60	127.936	.028	127.964
TOTAL	1.0	820.324	1015.294	.000	24.917	3.258	.000	18.62	2.59	464.055	8.441	472.496

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.017	.015	.016	.117	.407	5.11	.000	.407	.407	.371
12-03	.705	.136	.489	1.517	14.285	3.06	.000	14.285	14.692	12.558
12-04	2.648	.106	1.686	8.112	46.415	3.95	.000	46.415	61.107	49.239
12-05	2.056	.082	1.309	8.284	34.047	4.76	.000	34.047	95.154	73.677
12-06	1.766	.067	1.124	8.284	28.050	5.31	.000	28.050	123.203	91.977
12-07	1.546	.058	.983	8.284	23.507	5.87	.000	23.507	146.710	105.917
12-08	1.387	.051	.882	8.284	20.224	6.39	.000	20.224	166.935	116.818
12-09	1.263	.046	.803	8.284	17.674	6.88	.000	17.674	184.609	125.478
12-10	1.166	.041	.741	8.284	15.670	7.33	.000	15.670	200.279	132.457
12-11	1.058	.021	.666	8.070	13.457	7.84	.000	13.457	213.736	137.908
12-12	.964	.007	.602	7.894	11.584	8.37	.000	11.584	225.320	142.173
12-13	.886	.002	.552	7.816	10.034	8.94	.000	10.034	235.354	145.531
S TOT	15.461	.631	9.853	83.232	235.354	17.98	.000	235.354	235.354	145.531
AFTER	5.885	.002	3.662	75.432	42.983	17.98	.000	42.983	278.337	155.648
TOTAL	21.347	.633	13.515	158.664	278.337	17.98	.000	278.337	278.337	155.648

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	9.0	.0	LIFE, YRS.	24.83	8.00	172.121
GROSS ULT., MB & MMF	820.324	1109.397	DISCOUNT %	10.00	10.00	155.648
GROSS CUM., MB & MMF	.000	94.103	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	141.608
GROSS RES., MB & MMF	820.324	1015.294	DISCOUNTED PAYOUT, YRS.	.00	15.00	124.115
NET RES., MB & MMF	24.917	3.258	UNDISCOUNTED NET/INVEST.	.00	20.00	101.854
NET REVENUE, M$	464.055	8.441	DISCOUNTED NET/INVEST.	.00	25.00	85.457
INITIAL PRICE, $	18.604	2.593	RATE-OF-RETURN, PCT.	100.00	35.00	63.186
INITIAL N.I ., PCT.	2.516	.310	INITIAL W.I., PCT.	2.719	50.00	43.696
					70.00	29.500
					100.00	18.596

SW OIL & GAS INCOME FUND VIII-A	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:39:58
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	59.4	147.020	338.131	.000	34.901	42.700	.000	18.08	2.50	631.045	106.845	737.890
12-03	63.3	202.272	518.231	.000	33.620	40.833	.000	18.09	2.50	608.229	102.045	710.274
12-04	66.0	246.872	451.168	.000	33.728	37.727	.000	18.12	2.50	611.321	94.219	705.540
12-05	61.4	205.678	367.882	.000	28.916	32.639	.000	18.10	2.51	523.504	81.892	605.397
12-06	58.3	171.899	320.631	.000	23.582	29.651	.000	18.01	2.52	424.667	74.669	499.336
12-07	56.7	153.128	285.996	.000	21.840	27.359	.000	17.99	2.52	392.962	68.876	461.839
12-08	51.0	136.580	240.591	.000	19.829	23.559	.000	17.97	2.50	356.376	58.948	415.324
12-09	46.8	122.548	212.449	.000	18.504	21.861	.000	17.99	2.50	332.807	54.565	387.372
12-10	39.8	108.847	188.292	.000	17.213	20.243	.000	18.01	2.48	310.084	50.223	360.307
12-11	32.2	91.024	118.990	.000	14.249	12.540	.000	17.99	2.69	256.391	33.782	290.172
12-12	29.6	79.770	90.901	.000	13.391	11.513	.000	17.99	2.71	240.900	31.193	272.092
12-13	27.3	72.295	76.591	.000	12.444	10.580	.000	17.99	2.69	223.845	28.436	252.281
S TOT	3.5	1737.932	3209.852	.000	272.217	311.205	.000	18.04	2.52	4912.130	785.694	5697.823
AFTER	3.5	447.375	383.269	.000	68.394	56.648	.000	17.40	2.91	1190.011	164.868	1354.879
TOTAL	3.5	2185.306	3593.121	.000	340.611	367.853	.000	17.92	2.58	6102.141	950.562	7052.702

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	29.028	8.013	21.543	364.248	315.058	10.06	.000	315.058	315.058	300.774
12-03	27.979	7.653	20.744	359.497	294.401	10.29	.000	294.401	609.459	556.112
12-04	28.121	7.066	20.593	359.637	290.122	10.38	.000	290.122	899.582	785.120
12-05	24.081	6.142	17.714	312.248	245.212	10.48	.000	245.212	1144.793	961.052
12-06	19.535	5.600	14.662	246.188	213.351	10.03	.000	213.351	1358.144	1100.189
12-07	18.076	5.166	13.577	238.463	186.556	10.43	.000	186.556	1544.700	1210.794
12-08	16.393	4.421	12.259	220.112	162.139	10.66	.000	162.139	1706.839	1298.192
12-09	15.309	4.092	11.428	215.826	140.716	11.14	.000	140.716	1847.555	1367.144
12-10	14.264	3.767	10.615	210.034	121.628	11.59	.000	121.628	1969.183	1421.328
12-11	11.794	2.534	8.604	162.594	104.647	11.36	.000	104.647	2073.830	1463.709
12-12	11.081	2.339	8.072	160.608	89.991	11.89	.000	89.991	2163.821	1496.843
12-13	10.297	2.133	7.501	155.919	76.432	12.38	.000	76.432	2240.253	1522.429
S TOT	225.958	58.927	167.312	3005.374	2240.253	16.07	.000	2240.253	2240.253	1522.429
AFTER	54.741	12.365	42.258	907.430	338.085	16.07	.000	338.085	2578.339	1597.210
TOTAL	280.698	71.292	209.570	3912.804	2578.338	16.07	.000	2578.338	2578.339	1597.210

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	84.0	18.0	LIFE, YRS.	31.00	8.00	1728.606
GROSS ULT., MB & MMF	22036.900	16863.830	DISCOUNT %	10.00	10.00	1597.210
GROSS CUM., MB & MMF	19851.600	13270.710	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1484.931
GROSS RES., MB & MMF	2185.306	3593.122	DISCOUNTED PAYOUT, YRS.	.00	15.00	1344.383
NET RES., MB & MMF	340.611	367.853	UNDISCOUNTED NET/INVEST.	.00	20.00	1163.855
NET REVENUE, M$	6102.141	950.562	DISCOUNTED NET/INVEST.	.00	25.00	1029.003
INITIAL PRICE, $	18.185	2.547	RATE-OF-RETURN, PCT.	100.00	35.00	841.658
INITIAL N.I., PCT.	13.789	8.992	INITIAL W.I., PCT.	15.797	50.00	670.839
					70.00	538.523
					100.00	427.328

APPENDIX B7

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund VIII-B (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 23 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 89.7 percent of the total net remaining liquid hydrocarbon reserves and 82.9 percent of the total net remaining gas reserves. The properties that we reviewed represent 85.6 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund VIII-B

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		294,531		23,455		0		317,986
Gas—MMCF		271		0		0		271
Income Data
Future Gross Revenue	$	5,677,326	$	416,314	$	0	$	6,093,640
Deductions		3,492,720		161,760		0		3,654,480
Future Net Income (FNI)	$	2,184,606	$	254,554	$	0	$	2,439,160
Discounted FNI @ 10%	$	1,357,179	$	136,897	$	0	$	1,494,076

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		36,508		0		0		36,508
Gas—MMCF		56		0		0		56
Income Data
Future Gross Revenue	$	733,520	$	0	$	0	$	733,520
Deductions		319,649		0		0		319,649
Future Net Income (FNI)	$	413,871	$	0	$	0	$	413,871
Discounted FNI @10%	$	251,691	$	0	$	0	$	251,691
Total Net Reserves
Oil/Condensate—Barrels		331,039		23,455		0		354,494
Gas—MMCF		327		0		0		327
Income Data
Future Gross Revenue	$	6,410,846	$	416,314	$	0	$	6,827,160
Deductions		3,812,369		161,760		0		3,974,129
Future Net Income (FNI)	$	2,598,477	$	254,554	$	0	$	2,853,031
Discounted FNI @ 10%	$	1,608,870	$	136,897	$	0	$	1,745,767

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 10.3 percent of the total net remaining liquid hydrocarbon reserves and 17.1 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND VIII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:46:55
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	29.0	107.565	159.458	.000	29.043	26.602	.000	18.13	2.44	526.687	64.870	591.558
12-03	29.0	101.364	149.791	.000	27.400	25.159	.000	18.13	2.44	496.853	61.321	558.174
12-04	29.0	95.608	140.976	.000	25.856	23.814	.000	18.13	2.44	468.849	58.018	526.867
12-05	28.9	90.088	132.862	.000	24.346	22.555	.000	18.13	2.44	441.388	54.930	496.318
12-06	27.3	78.191	125.340	.000	20.217	21.372	.000	18.05	2.43	364.857	52.031	416.887
12-07	27.0	72.306	118.328	.000	18.467	20.258	.000	18.03	2.43	332.882	49.301	382.183
12-08	27.0	68.473	111.770	.000	17.508	19.207	.000	18.03	2.43	315.632	46.727	362.359
12-09	27.0	64.846	105.620	.000	16.599	18.215	.000	18.03	2.43	299.286	44.296	343.582
12-10	27.0	61.414	99.826	.000	15.738	17.277	.000	18.03	2.43	283.795	41.999	325.794
12-11	22.0	52.848	72.453	.000	12.910	10.232	.000	18.02	2.64	232.580	27.038	259.618
12-12	21.0	48.501	63.295	.000	12.170	9.591	.000	18.01	2.65	219.216	25.388	244.604
12-13	20.3	45.362	59.876	.000	11.321	9.103	.000	18.01	2.65	203.937	24.082	228.019
S TOT	3.1	886.567	1339.596	.000	231.574	223.386	.000	18.08	2.46	4185.962	550.001	4735.964
AFTER	3.1	305.528	342.051	.000	62.956	47.947	.000	17.46	2.85	1099.119	136.872	1235.991
TOTAL	3.1	1192.095	1681.647	.000	294.531	271.333	.000	17.94	2.53	5285.081	686.873	5971.955

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	24.228	4.865	17.394	258.414	286.656	9.11	.000	286.656	286.656	273.658
12-03	22.855	4.599	16.415	258.414	255.892	9.57	.000	255.892	542.548	495.748
12-04	21.567	4.351	15.495	258.414	227.040	10.05	.000	227.040	769.588	674.893
12-05	20.304	4.120	14.599	257.350	199.946	10.55	.000	199.946	969.534	818.326
12-06	16.783	3.902	12.304	207.948	175.949	10.13	.000	175.949	1145.483	933.059
12-07	15.313	3.698	11.291	195.382	156.500	10.33	.000	156.500	1301.983	1025.833
12-08	14.519	3.505	10.705	195.382	138.249	10.82	.000	138.249	1440.232	1100.343
12-09	13.767	3.322	10.149	195.382	120.961	11.34	.000	120.961	1561.193	1159.614
12-10	13.055	3.150	9.623	195.382	104.584	11.88	.000	104.584	1665.777	1206.206
12-11	10.699	2.028	7.725	148.843	90.324	11.58	.000	90.324	1756.101	1242.784
12-12	10.084	1.904	7.279	147.366	77.971	12.10	.000	77.971	1834.072	1271.491
12-13	9.381	1.806	6.790	143.715	66.327	12.59	.000	66.327	1900.399	1293.695
S TOT	192.554	41.250	139.769	2461.991	1900.399	16.13	.000	1900.399	1900.399	1293.695
AFTER	50.559	10.265	38.584	852.376	284.207	16.13	.000	284.207	2184.606	1357.179
TOTAL	243.114	51.515	178.353	3314.367	2184.606	16.13	.000	2184.606	2184.606	1357.179

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	22.0	7.0	LIFE, YRS.	31.00	8.00	1467.973
GROSS ULT., MB & MMF	12680.590	6882.009	DISCOUNT %	10.00	10.00	1357.179
GROSS CUM., MB & MMF	11488.500	5200.361	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1262.545
GROSS RES., MB & MMF	1192.095	1681.647	DISCOUNTED PAYOUT, YRS.	.00	15.00	1144.164
NET RES., MB & MMF	294.531	271.333	UNDISCOUNTED NET/INVEST.	.00	20.00	992.289
NET REVENUE, M$	5285.080	686.873	DISCOUNTED NET/INVEST.	.00	25.00	879.012
INITIAL PRICE, $	17.793	2.504	RATE-OF-RETURN, PCT.	100.00	35.00	721.923
INITIAL N.I., PCT.	26.981	16.625	INITIAL W.I., PCT.	31.307	50.00	578.915
					70.00	468.101
					100.00	374.647

SW OIL & GAS INCOME FUND VII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:45:34
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF7B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	98.0	326.116	619.889	.000	20.584	57.606	.000	18.09	2.13	372.275	122.528	494.803
12-03	98.0	307.534	538.946	.000	19.502	50.179	.000	18.09	2.13	352.778	106.904	459.682
12-04	98.0	290.408	476.149	.000	18.487	44.413	.000	18.09	2.13	334.498	94.754	429.252
12-05	97.6	274.107	423.305	.000	17.531	39.820	.000	18.10	2.14	317.275	85.050	402.324
12-06	95.7	251.438	376.604	.000	16.560	36.057	.000	18.11	2.14	299.898	77.073	376.971
12-07	95.0	235.213	342.778	.000	15.688	32.957	.000	18.12	2.14	284.232	70.503	354.736
12-08	95.0	223.646	315.184	.000	14.899	30.326	.000	18.12	2.14	269.993	64.923	334.916
12-09	93.5	212.707	283.523	.000	14.152	27.324	.000	18.13	2.14	256.512	58.576	315.088
12-10	93.0	202.348	262.615	.000	13.444	25.321	.000	18.13	2.14	243.741	54.312	298.053
12-11	92.3	192.516	238.665	.000	12.773	21.965	.000	18.13	2.18	231.625	47.816	279.441
12-12	92.0	183.067	219.967	.000	12.127	19.716	.000	18.14	2.20	219.944	43.299	263.243
12-13	92.0	174.187	205.981	.000	11.522	18.457	.000	18.14	2.20	3209.033	40.549	249.582
S TOT	1.0	2873.288	4303.606	.000	187.271	404.141	.000	18.11	2.14	13391.805	866.286	4258.091
AFTER	1.0	1379.091	1914.417	.000	88.918	176.090	.000	17.84	2.16	1586.527	380.267	1966.793
TOTAL	1.0	4252.379	6218.022	.000	276.189	580.231	.000	18.03	2.15	4978.331	1246.553	6224.884

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	22.447	9.190	12.955	64.439	385.772	3.61	.000	385.772	385.772	368.216
12-03	21.284	8.018	12.011	64.439	353.930	3.80	.000	353.930	739.702	675.314
12-04	20.190	7.107	11.197	64.439	326.320	3.98	.000	326.320	1066.022	932.707
12-05	19.158	6.379	10.478	64.369	301.941	4.15	.000	301.941	1367.963	1149.214
12-06	18.130	5.780	9.779	63.136	280.145	4.29	.000	280.145	1648.108	1331.826
12-07	17.193	5.288	9.181	62.570	260.505	4.45	.000	260.505	1908.612	1486.197
12-08	16.332	4.869	8.661	62.570	242.484	4.63	.000	242.484	2151.097	1616.826
12-09	15.516	4.393	8.140	61.073	225.966	4.76	.000	225.966	2377.062	1727.488
12-10	14.743	4.073	7.695	60.574	210.967	4.93	.000	210.967	2588.029	1821.411
12-11	14.009	3.586	7.205	57.777	196.864	5.02	.000	196.864	2784.894	1901.089
12-12	13.304	3.247	6.780	56.378	183.533	5.17	.000	183.533	2968.427	1968.618
12-13	12.643	3.041	6.426	56.378	171.095	5.38	.000	171.095	3139.521	2025.849
S TOT	204.948	64.971	110.508	738.142	3139.521	11.24	.000	3139.521	3139.521	2025.849
AFTER	84.048	28.520	56.572	521.192	1276.462	11.24	.000	1276.462	4415.984	2290.394
TOTAL	288.996	93.491	167.080	1259.334	4415.983	11.24	.000	4415.983	4415.984	2290.394

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	89.0	9.0	LIFE, YRS.	41.17	8.00	2542.795
GROSS ULT., MB & MMF	30541.270	38255.780	DISCOUNT %	10.00	10.00	2290.394
GROSS CUM., MB & MMF	26288.890	32037.760	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	2083.545
GROSS RES., MB & MMF	4252.379	6218.023	DISCOUNTED PAYOUT, YRS.	.00	15.00	1836.330
NET RES., MB & MMF	276.189	580.231	UNDISCOUNTED NET/INVEST.	.00	20.00	1538.024
NET REVENUE, M$	4978.331	1246.553	DISCOUNTED NET/INVEST.	.00	25.00	1329.048
INITIAL PRICE, $	18.328	2.167	RATE-OF-RETURN, PCT.	100.00	35.00	1057.223
INITIAL N.I., PCT.	6.297	9.285	INITIAL W.I., PCT.	4.598	50.00	826.070
					70.00	656.104
					100.00	518.054

SW OIL & GAS INCOME FUND VIII-B	DATE	:	02/15/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	16:47:07
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	29.0	107.565	159.458	.000	29.043	26.602	.000	18.13	2.44	526.687	64.870	591.558
12-03	30.6	122.840	185.242	.000	28.038	25.184	.000	18.15	2.44	508.939	61.385	570.324
12-04	33.0	159.294	184.126	.000	28.538	23.844	.000	18.18	2.44	518.716	58.095	576.812
12-05	32.9	138.552	164.973	.000	26.395	22.577	.000	18.17	2.44	479.522	54.987	534.509
12-06	31.3	121.078	151.317	.000	22.061	21.390	.000	18.09	2.43	399.168	52.077	451.245
12-07	31.0	110.561	140.339	.000	20.126	20.273	.000	18.07	2.43	363.758	49.340	413.099
12-08	31.0	102.753	130.980	.000	19.001	19.220	.000	18.07	2.43	343.419	46.761	390.180
12-09	31.0	96.023	122.733	.000	17.961	18.227	.000	18.07	2.43	324.638	44.327	368.965
12-10	31.0	90.189	115.304	.000	16.999	17.288	.000	18.08	2.43	307.264	42.027	349.291
12-11	26.0	79.459	86.617	.000	14.078	10.242	.000	18.06	2.64	254.316	27.063	281.379
12-12	25.0	73.137	76.326	.000	13.253	9.600	.000	18.06	2.65	239.355	25.412	264.767
12-13	24.3	68.178	71.863	.000	12.325	9.112	.000	18.06	2.65	222.604	24.103	246.707
S TOT	3.1	1269.628	1589.278	.000	247.818	223.558	.000	18.11	2.46	4488.387	550.448	5038.834
AFTER	3.1	451.763	357.750	.000	70.168	47.958	.000	17.57	2.85	1232.624	136.900	1369.524
TOTAL	3.1	1721.390	1947.028	.000	317.985	271.516	.000	17.99	2.53	5721.010	687.348	6408.358

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	24.228	4.865	17.394	258.414	286.656	9.11	.000	286.656	286.656	273.658
12-03	23.411	4.604	16.762	259.501	266.045	9.44	.000	266.045	552.701	504.354
12-04	23.861	4.357	16.924	265.538	266.131	9.56	.000	266.131	818.833	714.446
12-05	22.058	4.124	15.692	264.474	228.162	10.16	.000	228.162	1046.994	878.121
12-06	18.362	3.906	13.288	215.072	200.618	9.78	.000	200.618	1247.613	1008.942
12-07	16.733	3.701	12.176	202.506	177.984	10.00	.000	177.984	1425.596	1114.454
12-08	15.797	3.507	11.501	202.506	156.869	10.51	.000	156.869	1582.465	1199.000
12-09	14.933	3.325	10.876	202.506	137.326	11.03	.000	137.326	1719.790	1266.287
12-10	14.134	3.152	10.296	202.506	119.203	11.57	.000	119.203	1838.993	1319.390
12-11	11.699	2.030	8.347	155.967	103.336	11.28	.000	103.336	1942.330	1361.237
12-12	11.010	1.906	7.856	154.490	89.504	11.80	.000	89.504	2031.834	1394.190
12-13	10.240	1.808	7.325	150.839	76.496	12.29	.000	76.496	2108.331	1419.796
S TOT	206.466	41.284	148.437	2534.317	2108.331	16.13	.000	2108.331	2108.331	1419.796
AFTER	56.701	10.267	42.406	929.320	330.829	16.13	.000	330.829	2439.161	1494.076
TOTAL	263.166	51.551	190.843	3463.637	2439.160	16.13	.000	2439.160	2439.161	1494.076

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	26.0	7.0	LIFE, YRS.	31.00	8.00	1620.313
GROSS ULT., MB & MMF	13209.890	7147.89	DISCOUNT %	10.00	10.00	1494.076
GROSS CUM., MB & MMF	11488.500	5200.361	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1386.386
GROSS RES., MB & MMF	1721.390	1947.028	DISCOUNTED PAYOUT, YRS.	.00	15.00	1251.881
NET RES., MB & MMF	317.985	271.516	UNDISCOUNTED NET/INVEST.	.00	20.00	1079.745
NET REVENUE, M$	5721.011	687.348	DISCOUNTED NET/INVEST.	.00	25.00	951.744
INITIAL PRICE, $	18.122	2.533	RATE-OF-RETURN, PCT.	100.00	35.00	774.959
INITIAL N.I., PCT.	16.668	11.676	INITIAL W.I., PCT.	19.578	50.00	615.038
					70.00	492.124
					100.00	389.530

SW OIL & GAS INCOME FUND VIII-B	DATE	:	02/15/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	17:08:35
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2410.1	14093.840	5688.309	.000	6.867	10.991	.000	17.82	2.51	122.364	27.544	149.908
12-03	2408.3	12095.610	5414.066	.000	6.343	9.856	.000	17.83	2.48	113.085	24.481	137.566
12-04	2407.5	10548.950	5158.424	.000	5.606	8.777	.000	17.82	2.48	99.910	21.745	121.654
12-05	1961.0	8017.785	4907.807	.000	3.254	5.656	.000	17.70	2.53	57.589	14.332	71.921
12-06	1656.3	6724.419	4655.826	.000	2.415	4.652	.000	17.65	2.59	42.611	12.044	54.656
12-07	1654.1	6349.937	4440.436	.000	2.092	4.051	.000	17.54	2.58	36.694	10.456	47.149
12-08	1642.5	5987.734	4228.068	.000	1.346	1.870	.000	17.09	2.50	22.994	4.679	27.673
12-09	1446.3	5374.657	3873.733	.000	.988	1.477	.000	16.71	2.51	16.502	3.708	20.210
12-10	1226.3	4766.491	3525.401	.000	.840	1.168	.000	16.70	2.43	14.034	2.840	16.874
12-11	1087.0	4319.371	3306.066	.000	.631	1.000	.000	16.55	2.33	10.444	2.334	12.778
12-12	1085.8	4081.915	3158.799	.000	.595	.917	.000	16.55	2.31	9.845	2.117	11.962
12-13	1082.0	3856.977	3007.788	.000	.561	.637	.000	16.55	1.93	9.279	1.232	10.511
S TOT	172.3	86217.670	51364.720	.000	31.537	51.052	.000	17.61	2.50	555.351	127.511	682.862
AFTER	172.3	42055.730	41610.660	.000	4.971	4.454	.000	16.62	1.91	82.607	8.529	91.136
TOTAL	172.3	128273.400	92975.380	.000	36.508	55.506	.000	17.47	2.45	637.957	136.041	773.998

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	5.760	2.067	4.070	74.703	63.307	9.96	.000	63.307	63.307	60.474
12-03	5.326	1.837	3.742	73.296	53.365	10.54	.000	53.365	116.672	106.808
12-04	4.713	1.632	3.303	67.022	44.985	10.85	.000	44.985	161.657	142.318
12-05	2.759	1.076	1.897	30.034	36.155	8.52	.000	36.155	197.812	168.292
12-06	2.064	.904	1.415	21.915	28.358	8.24	.000	28.358	226.170	186.783
12-07	1.785	.785	1.214	18.407	24.958	8.02	.000	24.958	251.128	201.581
12-08	1.149	.352	.692	4.050	21.429	3.77	.000	21.429	272.558	213.146
12-09	.845	.279	.488	2.354	16.244	3.21	.000	16.244	288.801	221.109
12-10	.707	.213	.421	1.788	13.745	3.02	.000	13.745	302.546	227.241
12-11	.480	.175	.355	1.788	9.979	3.51	.000	9.979	312.526	231.280
12-12	.453	.159	.333	1.726	9.292	3.57	.000	9.292	321.817	234.699
12-13	.427	.092	.300	1.040	8.652	2.79	.000	8.652	330.470	237.593
S TOT	26.468	9.570	18.230	298.125	330.470	1.23	.000	330.470	330.470	237.593
AFTER	3.800	.640	2.601	.693	833.402	1.23	.000	83.402	413.872	251.691
TOTAL	30.268	10.210	20.831	298.818	413.872	1.23	.000	413.872	413.872	251.691

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2419.0	12.0	LIFE, YRS.	43.17	8.00	271.111
GROSS ULT., MB & MMF	1484666.000	335702.800	DISCOUNT %	10.00	10.00	251.691
GROSS CUM., MB & MMF	1356393.000	242727.500	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	235.409
GROSS RES., MB & MMF	128273.400	92975.350	DISCOUNTED PAYOUT, YRS.	.00	15.00	215.305
NET RES., MB & MMF	36.508	55.506	UNDISCOUNTED NET/INVEST.	.00	20.00	189.684
NET REVENUE, M$	637.957	136.041	DISCOUNTED NET/INVEST.	.00	25.00	170.492
INITIAL PRICE, $	16.815	1.867	RATE-OF-RETURN, PCT.	100.00	35.00	143.407
INITIAL N.I., PCT.	.079	.282	INITIAL W.I., PCT.	.091	50.00	117.908
					70.00	97.354
					100.00	79.354

SW OIL & GAS INCOME FUND VIII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:11
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2439.1	14201.400	5847.767	.000	35.910	37.593	.000	18.07	2.46	649.051	92.414	741.466
12-03	2437.3	12196.970	5563.857	.000	33.743	35.016	.000	18.08	2.45	609.938	85.802	695.740
12-04	2436.5	10644.560	5299.400	.000	31.462	32.591	.000	18.08	2.45	568.759	79.763	648.522
12-05	1989.9	8107.873	5040.669	.000	27.600	28.211	.000	18.08	2.46	498.977	69.261	568.238
12-06	1683.6	6802.610	4781.166	.000	22.632	26.024	.000	18.00	2.46	407.468	64.075	471.543
12-07	1681.1	6422.243	4558.764	.000	20.559	24.309	.000	17.98	2.46	369.576	59.757	429.333
12-08	1669.5	6056.207	4339.838	.000	18.853	21.077	.000	17.96	2.44	338.626	51.406	390.032
12-09	1473.3	5439.503	3979.353	.000	17.587	19.692	.000	17.96	2.44	315.788	48.004	363.792
12-10	1253.3	4827.905	3625.227	.000	16.578	18.445	.000	17.96	2.43	297.829	44.839	342.668
12-11	1109.0	4372.219	3378.519	.000	13.541	11.232	.000	17.95	2.61	243.024	29.371	272.396
12-12	1106.8	4130.417	3222.094	.000	12.764	10.508	.000	17.95	2.62	229.061	27.506	256.567
12-13	1102.3	3902.340	3067.663	.000	11.882	9.740	.000	17.94	2.60	213.216	25.314	238.529
S TOT	172.3	87104.240	52704.320	.000	263.111	274.438	.000	18.02	2.47	4741.314	677.513	5418.825
AFTER	172.3	42361.250	41952.700	.000	67.927	52.401	.000	17.40	2.77	1181.726	145.401	1327.127
TOTAL	172.3	129465.500	94657.020	.000	331.038	326.840	.000	17.89	2.52	5923.040	822.914	6745.952

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	29.988	6.932	21.465	333.117	349.963	9.28	.000	349.963	349.963	334.132
12-03	28.181	6.436	20.157	331.710	309.256	9.76	.000	309.256	659.220	602.556
12-04	26.280	5.983	18.799	325.436	272.025	10.20	.000	272.025	931.245	817.2111
12-05	23.063	5.195	16.496	287.384	236.101	10.28	.000	236.101	1167.346	986.618
12-06	18.847	4.806	13.719	229.863	204.308	9.91	.000	204.308	1371.653	1119.842
12-07	17.098	4.482	12.505	213.789	181.458	10.07	.000	181.458	1553.111	1227.414
12-08	15.668	3.856	11.397	199.432	159.678	10.30	.000	159.678	1712.789	1313.489
12-09	14.612	3.601	10.638	197.736	137.205	10.86	.000	137.205	1849.994	1380.722
12-10	13.761	3.363	10.044	197.170	118.329	11.42	.000	118.329	1968.323	1433.446
12-11	11.179	2.203	8.079	150.631	100.303	11.17	.000	100.303	2068.626	1474.063
12-12	10.537	2.063	7.612	149.092	87.263	11.66	.000	87.263	2155.889	1506.190
12-13	9.808	1.899	7.089	144.755	74.979	12.11	.000	74.979	2230.868	1531.287
S TOT	219.022	50.820	157.999	2760.116	2230.868	1.23	.000	2230.868	2230.868	1531.287
AFTER	54.359	10.905	41.185	853.069	367.609	1.23	.000	367.609	2598.477	1608.870
TOTAL	273.382	61.725	199.184	3613.185	2598.477	1.23	.000	2598.477	2598.477	1608.870

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2441.0	19.0	LIFE, YRS.	43.17	8.00	1739.084
GROSS ULT., MB & MMF	1497347.000	342584.900	DISCOUNT %	10.00	10.00	1608.871
GROSS CUM., MB & MMF	1367881.000	247927.800	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1497.954
GROSS RES., MB & MMF	129465.500	94657.020	DISCOUNTED PAYOUT, YRS.	.00	15.00	1359.468
NET RES., MB & MMF	331.038	326.840	UNDISCOUNTED NET/INVEST.	.00	20.00	1181.973
NET REVENUE, M$	5923.040	822.914	DISCOUNTED NET/INVEST.	.00	25.00	1049.504
INITIAL PRICE, $	16.822	1.885	RATE-OF-RETURN, PCT.	100.00	35.00	865.330
INITIAL N.I., PCT.	.274	.728	INITIAL W.I., PCT.	.367	50.00	696.824
					70.0	565.455
					100.00	454.001

SW OIL & GAS INCOME FUND VIII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:12
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.6	21.476	35.452	.000	.639	.024	.000	18.92	2.60	12.086	.063	12.149
12-04	4.0	63.686	43.150	.000	2.682	.030	.000	18.60	2.60	49.867	.077	49.944
12-05	4.0	48.463	32.111	.000	2.049	.022	.000	18.61	2.60	38.134	.057	38.191
12-06	4.0	42.886	25.977	.000	1.843	.018	.000	18.61	2.60	34.311	.046	34.358
12-07	4.0	38.255	22.010	.000	1.659	.015	.000	18.61	2.60	30.876	.039	30.915
12-08	4.0	34.280	19.209	.000	1.493	.013	.000	18.61	2.60	27.787	.034	27.821
12-09	4.0	31.177	17.113	.000	1.362	.012	.000	18.61	2.60	25.352	.031	25.383
12-10	4.0	28.775	15.479	.000	1.261	.011	.000	18.61	2.60	23.469	.028	23.497
12-11	4.0	26.610	14.163	.000	1.169	.010	.000	18.60	2.60	21.736	.025	21.761
12-12	4.0	24.636	13.030	.000	1.083	.009	.000	18.60	2.60	20.139	.023	20.162
12-13	4.0	22.816	11.988	.000	1.004	.008	.000	18.59	2.60	18.667	.021	18.689
S TOT	1.0	383.061	249.682	.000	16.244	.172	.000	18.62	2.60	302.424	.447	302.871
AFTER	1.0	46.234	15.699	.000	7.211	.011	.000	18.51	2.60	133.505	.028	133.533
TOTAL	1.0	529.295	265.381	.000	23.455	.183	.000	18.59	2.60	435.928	.475	436.403

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.556	.005	.348	1.088	10.153	3.11	.000	10.153	10.153	8.606
12-04	2.294	.006	1.429	7.124	39.091	4.04	.000	39.091	49.245	39.553
12-05	1.754	.004	1.093	7.124	28.216	4.86	.000	28.216	77.461	59.794
12-06	1.578	.003	.983	7.124	24.669	5.25	.000	24.669	102.130	75.883
12-07	1.420	.003	.885	7.124	21.483	5.68	.000	21.483	123.613	88.620
12-08	1.278	.003	.796	7.124	18.620	6.15	.000	18.620	142.233	98.657
12-09	1.166	.002	.726	7.124	16.364	6.61	.000	16.364	158.597	106.674
12-10	1.080	.002	.672	7.124	14.619	7.03	.000	14.619	173.216	113.185
12-11	1.000	.002	.623	7.124	13.013	7.48	.000	13.013	186.229	118.453
12-12	.926	.002	.577	7.124	11.533	7.96	.000	11.533	197.762	122.699
12-13	.859	.002	.535	7.124	10.170	8.47	.000	10.170	207.932	126.102
S TOT	13.911	.033	8.668	72.326	207.932	18.18	.000	207.932	207.932	126.102
AFTER	6.141	.002	3.822	76.945	46.623	18.18	.000	46.623	254.555	136.897
TOTAL	20.053	.036	12.489	149.271	254.555	18.18	.000	254.555	254.555	136.897

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	4.0	.0	LIFE, YRS.	25.50	8.00	152.340
GROSS ULT., MB & MMF	529.295	265.381	DISCOUNT %	10.00	10.00	136.897
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	123.841
GROSS RES., MB & MMF	529.295	265.381	DISCOUNTED PAYOUT, YRS.	.00	15.00	107.717
NET RES., MB & MMF	23.455	.183	UNDISCOUNTED NET/INVEST.	.00	20.00	87.456
NET REVENUE, M$	435.928	.475	DISCOUNTED NET/INVEST.	.00	25.00	72.732
INITIAL PRICE, $	18.522	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	53.036
INITIAL N.I., PCT.	4.089	.069	INITIAL W.I., PCT.	4.588	50.00	36.122
					70.00	24.024
					100.00	14.883

SW OIL & GAS INCOME FUND VIII-B	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:40:18
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF8B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2439.1	14201.400	5847.767	.000	35.910	37.593	.000	18.07	2.46	649.051	92.414	741.466
12-03	2438.8	12218.450	5599.308	.000	34.382	35.040	.000	18.09	2.45	622.024	85.866	707.890
12-04	2440.5	10708.240	5342.550	.000	34.144	32.621	.000	18.12	2.45	618.626	79.840	698.466
12-05	1993.9	8156.336	5072.780	.000	29.649	28.233	.000	18.12	2.46	537.111	69.319	606.430
12-06	1687.6	6845.496	4807.143	.000	24.475	26.042	.000	18.05	2.46	441.779	64.121	505.901
12-07	1685.1	6460.499	4580.775	.000	22.218	24.325	.000	18.02	2.46	400.452	59.796	460.248
12-08	1673.5	6090.487	4359.048	.000	20.346	21.090	.000	18.01	2.44	366.413	51.440	417.852
12-09	1477.3	5470.680	3996.466	.000	18.949	19.704	.000	18.00	2.44	341.140	48.035	389.175
12-10	1257.3	4856.680	3640.706	.000	17.840	18.455	.000	18.01	2.43	321.298	44.867	366.165
12-11	1113.0	4398.830	3392.682	.000	14.709	11.242	.000	18.00	2.61	264.760	29.397	294.157
12-12	1110.8	4155.052	3235.125	.000	13.847	10.516	.000	18.00	2.62	249.200	27.529	276.729
12-13	1106.3	3925.156	3079.651	.000	12.886	9.749	.000	17.99	2.60	231.883	25.335	257.218
S TOT	172.3	87487.310	52954.000	.000	279.355	274.610	.000	18.05	2.47	5043.737	677.959	5721.696
AFTER	172.3	42507.490	41968.400	.000	75.138	52.412	.000	17.50	2.77	1315.230	145.429	1460.659
TOTAL	172.3	129994.800	94922.400	.000	354.493	327.022	.000	17.94	2.52	6358.967	823.388	7182.355

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	29.988	6.932	21.465	333.177	349.963	9.28	.000	349.963	349.963	334.132
12-03	28.737	6.441	20.504	332.798	319.410	9.66	.000	319.410	669.373	611.162
12-04	28.573	5.989	20.228	332.560	311.116	9.79	.000	311.116	980.489	856.764
12-05	24.817	5.200	17.589	294.508	264.317	9.96	.000	264.317	1244.806	1046.413
12-06	20.425	4.810	14.702	236.987	228.977	9.61	.000	228.977	1473.783	1195.725
12-07	18.518	4.485	13.390	220.913	202.942	9.79	.000	202.942	1676.724	1316.035
12-08	16.947	3.859	12.193	206.556	178.298	10.04	.000	178.298	1855.022	1412.146
12-09	15.779	3.603	11.364	204.860	153.569	10.60	.000	153.569	2008.591	1487.396
12-10	14.841	3.365	10.716	204.294	132.948	11.15	.000	132.948	2141.540	1546.631
12-11	12.179	2.205	8.702	157.755	113.316	10.91	.000	113.316	2254.855	1592.517
12-12	11.463	2.065	8.189	156.216	98.796	11.41	.000	98.796	2353.652	1628.889
12-13	10.667	1.900	7.624	151.878	85.149	11.86	.000	85.149	2438.800	1657.389
S TOT	232.934	50.854	166.667	2832.442	2438.800	1.23	.000	2438.800	2438.800	1657.389
AFTER	60.501	10.907	45.006	930.014	414.232	1.23	.000	414.232	2853.031	1745.768
TOTAL	293.435	61.761	211.673	3762.455	2853.032	1.23	.000	2853.032	2853.031	1745.768

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2445.0	19.0	LIFE, YRS.	43.17	8.00	1891.424
GROSS ULT., MB & MMF	1497876.000	342850.200	DISCOUNT %	10.00	10.00	1745.768
GROSS CUM., MB & MMF	1367881.000	247927.800	UNDISCOUNTED PAYOUT,YRS.	.00	12.00	1621.795
GROSS RES., MB & MMF	129994.800	94922.390	DISCOUNTED PAYOUT, YRS.	.00	15.00	1467.186
NET RES., MB & MMF	354.493	327.022	UNDISCOUNTED NET/INVEST.	.00	20.00	1269.429
NET REVENUE, M$	6358.967	823.388	DISCOUNTED NET/INVEST.	.00	25.00	1122.236
INITIAL PRICE, $	16.832	1.893	RATE-OF-RETURN, PCT.	100.00	35.00	918.366
INITIAL N.I., PCT.	.296	.721	INITIAL W.I., PCT.	.396	50.00	732.946
					70.00	589.478
					100.00	468.884

APPENDIX B8

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund IX-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 26 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 81.7 percent of the total net remaining liquid hydrocarbon reserves and 85.0 percent of the total net remaining gas reserves. The properties that we reviewed represent 88.8 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund IX-A

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		158,276		0		12,693		170,969
Gas—MMCF		607		0		106		713
Income Data
Future Gross Revenue	$	4,032,217	$	0	$	515,419	$	4,547,636
Deductions		1,844,279		0		130,824		1,975,103
Future Net Income (FNI)	$	2,187,938	$	0	$	384,595	$	2,572,533
Discounted FNI @ 10%	$	1,255,288	$	0	$	261,914	$	1,517,202

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		35,537		0		2,814		38,351
Gas—MMCF		121		0		5		126
Income Data
Future Gross Revenue	$	791,349	$	0	$	52,483	$	843,832
Deductions		532,762		0		15,566		548,328
Future Net Income (FNI)	$	258,587	$	0	$	36,917	$	295,504
Discounted FNI @ 10%	$	168,230	$	0	$	23,076	$	191,306
Total Net Reserves
Oil/Condensate—Barrels		193,813		0		15,507		209,320
Gas—MMCF		728		0		111		839
Income Data
Future Gross Revenue	$	4,823,566	$	0	$	567,902	$	5,391,468
Deductions		2,377,041		0		146,390		2,523,431
Future Net Income (FNI)	$	2,446,525	$	0	$	421,512	$	2,868,037
Discounted FNI @ 10%	$	1,423,518	$	0	$	284,990	$	1,708,508

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

recovery when a field is in the late stages of depletion? The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 18.3 percent of the total net remaining liquid hydrocarbon reserves and 15.0 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:13
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	19.0	62.437	304.924	.000	12.045	55.754	.000	18.41	2.27	221.694	126.821	348.514
12-03	19.0	53.953	272.549	.000	11.133	51.480	.000	18.39	2.26	204.726	116.489	321.216
12-04	19.0	48.031	246.216	.000	10.383	47.702	.000	18.38	2.25	190.831	107.478	298.309
12-05	19.0	43.529	223.872	.000	9.733	44.294	.000	18.37	2.24	178.807	99.427	278.234
12-06	19.0	39.914	204.457	.000	9.152	41.189	.000	18.37	2.24	168.086	92.139	260.225
12-07	19.0	36.901	187.331	.000	8.624	38.340	.000	18.36	2.23	158.353	85.490	243.842
12-08	19.0	34.323	172.076	.000	8.139	35.718	.000	18.36	2.22	149.414	79.395	228.809
12-09	19.0	32.071	158.396	.000	7.690	33.296	.000	18.36	2.22	141.144	73.789	214.934
12-10	18.3	29.865	132.928	.000	7.269	30.894	.000	18.35	2.21	133.401	68.189	201.591
12-11	18.0	28.039	119.465	.000	6.878	28.792	.000	18.35	2.20	126.209	63.344	189.553
12-12	17.3	25.971	107.430	.000	6.285	25.240	.000	18.42	2.32	115.783	58.572	174.355
12-13	17.0	24.297	98.231	.000	5.841	22.749	.000	18.46	2.39	107.836	54.354	162.190
S TOT	1.0	459.332	2227.876	.000	103.171	455.449	.000	18.38	2.25	1896.284	1025.487	2921.771
AFTER	1.0	201.390	593.055	.000	55.105	151.460	.000	18.59	2.28	1024.373	345.294	1369.667
TOTAL	1.0	660.722	2820.931	.000	158.276	606.909	.000	18.45	2.26	2920.657	1370.781	4291.438

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	11.740	9.792	7.374	78.702	240.907	5.04	.000	240.907	240.907	229.991
12-03	10.870	9.000	6.754	78.702	215.890	5.34	.000	215.890	456.797	417.347
12-04	10.147	8.308	6.248	78.702	194.905	5.64	.000	194.905	651.702	571.108
12-05	9.515	7.688	5.813	78.702	176.516	5.94	.000	176.516	828.217	697.700
12-06	8.947	7.127	5.429	78.702	160.020	6.26	.000	160.020	988.237	802.030
12-07	8.429	6.615	5.082	78.702	145.014	6.58	.000	145.014	1133.251	887.981
12-08	7.952	6.145	4.766	78.702	131.243	6.92	.000	131.243	1264.495	958.699
12-09	7.510	5.713	4.476	78.702	118.532	7.28	.000	118.532	1383.027	1016.764
12-10	7.095	5.282	4.195	78.245	106.773	7.64	.000	106.773	1489.800	1064.313
12-11	6.710	4.908	3.945	78.093	95.897	8.02	.000	95.897	1585.698	1103.139
12-12	6.089	4.538	3.678	74.228	85.821	8.44	.000	85.821	1671.519	1134.726
12-13	5.636	4.212	3.448	72.296	76.598	8.89	.000	76.598	1748.117	1160.357
S TOT	100.641	79.329	61.207	932.477	1748.117	19.99	.000	1748.117	1748.117	1160.357
AFTER	52.260	26.991	29.778	820.817	439.821	19.99	.000	439.821	2187.938	1255.288
TOTAL	152.901	106.320	90.985	1753.294	2187.938	19.99	.000	2187.938	2187.938	1255.288

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	10.0	9.0	LIFE, YRS	31.00	8.00	1373.295
GROSS ULT., MB & MMF	1964.452	11640.210	DISCOUNT %	10.00	10.00	1255.289
GROSS CUM., MB & MMF	1303.730	8819.280	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1156.438
GROSS RES., MB & MMF	660.722	2820.931	DISCOUNTED PAYOUT, YRS.	.00	15.00	1035.389
NET RES., MB & MMF	158.276	606.909	UNDISCOUNTED NET/INVEST.	.00	20.00	884.438
NET REVENUE, M$	2920.657	1370.781	DISCOUNTED NET/INVEST.	.00	25.00	775.038
INITIAL PRICE, $	18.714	2.596	RATE-OF-RETURN, PCT.	100.00	35.00	627.694
INITIAL N.I., PCT.	18.559	17.965	INITIAL W.I., PCT.	20.095	50.00	497.667
					70.00	399.317
					100.00	317.814

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:13
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.7	13.516	849.555	.000	.287	22.998	.000	19.72	2.90	5.657	66.637	72.293
12-03	4.8	35.966	596.378	.000	.452	14.262	.000	19.31	2.87	8.730	40.968	49.697
12-04	8.3	107.557	482.785	.000	2.654	10.034	.000	19.16	2.86	50.846	28.683	79.528
12-05	9.0	85.648	366.390	.000	2.216	7.539	.000	19.16	2.86	42.454	21.548	64.002
12-06	9.0	60.684	291.723	.000	1.417	6.020	.000	19.16	2.86	27.139	17.195	44.334
12-07	9.0	46.979	244.057	.000	.980	5.023	.000	19.16	2.86	18.769	14.342	33.111
12-08	9.0	39.874	210.664	.000	.844	4.317	.000	19.15	2.85	16.172	12.319	28.491
12-09	9.0	34.918	185.860	.000	.753	3.789	.000	19.15	2.85	14.414	10.808	25.222
12-10	9.0	31.120	166.663	.000	.675	3.380	.000	19.15	2.85	12.934	9.635	22.569
12-11	7.2	22.891	130.544	.000	.556	2.838	.000	19.15	2.87	10.640	8.142	18.782
12-12	6.0	17.869	107.880	.000	.472	2.466	.000	19.15	2.88	9.037	7.106	16.143
12-13	4.8	11.522	92.291	.000	.394	2.215	.000	19.15	2.88	7.547	6.382	13.929
S TOT	1.0	508.544	3724.790	.000	11.700	84.881	.000	19.17	2.87	224.337	243.766	468.103
AFTER	1.0	26.936	811.214	.000	.993	21.618	.000	19.25	2.89	19.122	62.573	81.695
TOTAL	1.0	535.480	4536.004	.000	12.693	106.500	.000	19.18	2.88	243.459	306.339	549.798

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.260	4.998	2.011	1.879	63.145	2.22	.000	63.145	63.145	60.350
12-03	.405	3.073	1.383	2.659	42.177	2.66	.000	42.177	105.323	97.043
12-04	2.369	2.154	2.218	6.114	66.674	2.97	.000	66.674	171.996	149.390
12-05	1.974	1.618	1.789	7.192	51.429	3.62	.000	51.429	223.425	186.376
12-06	1.266	1.291	1.234	7.192	33.351	4.54	.000	33.351	256.776	208.174
12-07	.879	1.077	.918	7.192	23.045	5.54	.000	23.045	279.821	221.851
12-08	.758	.925	.789	7.192	18.827	6.18	.000	18.827	298.648	232.002
12-09	.676	.812	.698	7.192	15.844	6.77	.000	15.844	314.493	239.768
12-10	.607	.724	.624	7.192	13.423	7.38	.000	13.423	327.915	245.748
12-11	.501	.612	.518	6.633	10.519	8.03	.000	10.519	338.434	250.014
12-12	.426	.534	.444	6.278	8.461	8.70	.000	8.461	346.896	253.129
12-13	.357	.479	.382	6.050	6.660	9.52	.000	6.660	353.556	255.362
S TOT	10.480	18.295	13.009	72.763	353.556	17.10	.000	353.556	353.556	255.362
AFTER	.910	4.695	2.250	42.801	31.039	17.10	.000	31.039	384.595	261.914
TOTAL	11.389	22.990	15.260	115.564	384.595	17.10	.000	384.595	384.595	261.914

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	7.0	2.0	LIFE, YRS	32.00	8.00	279.272
GROSS ULT., MB & MMF	540.863	4657.494	DISCOUNT %	10.00	10.00	261.914
GROSS CUM., MB & MMF	5.383	121.490	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	246.753
GROSS RES., MB & MMF	535.480	4536.004	DISCOUNTED PAYOUT, YRS.	.00	15.00	227.284
NET RES., MB & MMF	12.693	106.500	UNDISCOUNTED NET/INVEST.	.00	20.00	201.343
NET REVENUE, M$	243.459	306.339	DISCOUNTED NET/INVEST.	.00	25.00	181.163
INITIAL PRICE, $	19.171	2.863	RATE-OF-RETURN, PCT.	100.00	35.00	151.792
INITIAL N.I., PCT.	2.478	2.468	INITIAL W.I., PCT.	3.071	50.00	123.483
					70.00	100.511
					100.00	80.583

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:13
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	21.7	75.954	1154.479	.000	12.332	78.753	.000	18.44	2.46	227.351	193.457	420.808
12-03	23.8	89.919	868.928	.000	11.585	65.742	.000	18.43	2.40	213.456	157.457	370.913
12-04	27.3	155.587	729.001	.000	13.037	57.736	.000	18.54	2.36	241.676	136.161	377.837
12-05	28.0	129.177	590.262	.000	11.949	51.834	.000	18.52	2.33	221.261	120.975	342.236
12-06	28.0	100.599	496.180	.000	10.569	47.208	.000	18.47	2.32	195.225	109.334	304.559
12-07	28.0	83.880	431.388	.000	9.604	43.364	.000	18.44	2.30	177.121	99.832	276.953
12-08	28.0	74.197	382.741	.000	8.983	40.035	.000	18.43	2.29	165.587	91.714	257.300
12-09	28.0	66.990	344.256	.000	8.442	37.086	.000	18.43	2.28	155.558	84.598	240.155
12-10	27.3	60.985	299.591	.000	7.944	34.274	.000	18.42	2.27	146.335	77.825	224.160
12-11	25.2	50.931	250.008	.000	7.433	31.629	.000	18.41	2.26	136.849	71.486	208.335
12-12	23.3	43.840	215.311	.000	6.757	27.705	.000	18.47	2.37	124.820	65.678	190.498
12-13	21.8	35.818	190.522	.000	6.235	24.964	.000	18.50	2.43	115.382	60.737	176.119
S TOT	1.0	967.876	5952.666	.000	114.870	540.330	.000	18.46	2.35	2120.621	1269.253	3389.874
AFTER	1.0	228.326	1404.269	.000	56.098	173.078	.000	18.60	2.36	1043.494	407.867	1451.362
TOTAL	1.0	1196.202	7356.935	.000	170.969	713.408	.000	18.51	2.35	3164.116	1677.120	4841.236

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	12.000	14.790	9.385	80.581	304.052	4.59	.000	304.052	304.052	290.341
12-03	11.275	12.073	8.137	81.361	258.068	5.01	.000	258.068	562.120	514.390
12-04	12.516	10.461	8.466	84.816	261.578	5.13	.000	261.578	823.698	720.498
12-05	11.489	9.306	7.603	85.894	227.944	5.55	.000	227.944	1051.642	884.077
12-06	10.213	8.418	6.663	85.894	193.371	6.03	.000	193.371	1245.013	1010.204
12-07	9.308	7.692	6.000	85.894	168.059	6.47	.000	168.059	1413.072	1109.832
12-08	8.711	7.070	5.555	85.894	150.071	6.85	.000	150.071	1563.143	1190.702
12-09	8.186	6.525	5.174	85.894	134.377	7.23	.000	134.377	1697.520	1256.531
12-10	7.703	6.006	4.819	85.437	120.196	7.61	.000	120.196	1817.716	1310.062
12-11	7.210	5.520	4.463	84.726	106.416	8.02	.000	106.416	1924.132	1353.152
12-12	6.516	5.072	4.122	80.506	94.282	8.46	.000	94.282	2018.414	1387.856
12-13	5.993	4.692	3.830	78.346	83.259	8.93	.000	83.259	2101.673	1415.719
S TOT	111.120	97.625	74.217	1005.240	2101.673	17.10	.000	2101.673	2101.673	1415.719
AFTER	53.170	31.686	32.028	863.618	470.860	17.10	.000	470.860	2572.532	1517.202
TOTAL	164.290	129.311	106.245	1868.857	2572.532	17.10	.000	2572.532	2572.532	1517.202

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	17.0	11.0	LIFE, YRS	32.00	8.00	1652.567
GROSS ULT., MB & MMF	2505.315	16297.710	DISCOUNT %	10.00	10.00	1517.202
GROSS CUM., MB & MMF	1309.113	8940.770	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1403.190
GROSS RES., MB & MMF	1196.202	7356.935	DISCOUNTED PAYOUT, YRS.	.00	15.00	1262.674
NET RES., MB & MMF	170.969	713.408	UNDISCOUNTED NET/INVEST.	.00	20.00	1085.781
NET REVENUE, M$	3164.116	1677.120	DISCOUNTED NET/INVEST.	.00	25.00	956.201
INITIAL PRICE, $	19.045	2.819	RATE-OF-RETURN, PCT.	100.00	35.00	779.486
INITIAL N.I., PCT.	6.908	4.998	INITIAL W.I., PCT.	6.565	50.00	621.151
					70.00	499.828
					100.00	398.397

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	08:05:43
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	56.7	57.396	247.357	.000	7.301	23.198	.000	17.64	1.71	128.766	39.725	168.491
12-03	40.8	40.872	189.334	.000	4.926	20.670	.000	17.37	1.75	85.546	36.091	121.637
12-04	26.0	28.259	158.690	.000	3.972	17.035	.000	17.49	1.66	69.456	28.354	97.810
12-05	26.0	26.509	143.224	.000	3.727	15.727	.000	17.49	1.67	65.203	26.300	91.503
12-06	24.2	23.695	124.047	.000	2.908	11.803	.000	17.59	1.71	51.150	20.151	71.302
12-07	20.8	21.587	97.837	.000	2.431	7.444	.000	17.78	1.71	43.212	12.722	55.933
12-08	17.2	19.645	51.721	.000	2.045	4.271	.000	17.89	1.89	36.570	8.060	44.630
12-09	16.8	18.490	42.194	.000	1.942	3.813	.000	17.89	1.91	34.736	7.281	42.017
12-10	16.0	17.407	37.894	.000	1.844	3.440	.000	17.89	1.85	33.000	6.366	39.366
12-11	13.8	15.335	32.903	.000	1.542	3.160	.000	17.77	1.86	27.388	5.892	33.280
12-12	12.3	12.655	29.148	.000	.683	2.407	.000	17.03	2.12	11.628	5.098	16.726
12-13	8.6	9.666	21.854	.000	.376	1.667	.000	16.68	2.58	6.272	4.306	10.577
S TOT	1.0	291.515	1176.203	.000	33.696	114.636	.000	17.60	1.75	592.927	200.346	793.273
AFTER	1.0	84.500	164.801	.000	1.841	6.279	.000	17.29	2.76	31.840	17.299	49.139
TOTAL	1.0	376.015	1341.004	.000	35.537	120.914	.000	17.58	1.80	624.766	217.645	842.412

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	6.963	3.056	3.637	108.661	46.175	10.95	.000	46.175	46.175	44.136
12-03	4.880	2.779	2.397	74.666	36.917	10.12	.000	36.917	83.091	76.199
12-04	3.924	2.169	2.006	59.564	30.147	9.93	.000	30.147	113.238	100.001
12-05	3.677	2.012	1.881	59.564	24.369	10.58	.000	24.369	137.607	117.495
12-06	2.741	1.527	1.631	45.911	19.491	10.63	.000	19.491	157.098	130.214
12-07	2.330	.967	1.248	35.436	15.951	10.89	.000	15.951	173.049	139.675
12-08	1.909	.613	1.040	28.170	12.898	11.51	.000	12.898	185.947	146.631
12-09	1.812	.554	.981	28.019	10.650	12.17	.000	10.650	196.597	151.851
12-10	1.720	.485	.922	27.567	8.672	12.70	.000	8.672	205.269	155.717
12-11	1.451	.449	.759	24.141	6.479	12.96	.000	6.479	211.748	158.343
12-12	.630	.387	.374	10.104	5.231	10.60	.000	5.231	216.979	160.269
12-13	.337	.327	.247	5.305	4.362	9.51	.000	4.362	221.341	161.730
S TOT	32.375	15.326	17.123	507.108	221.341	1.35	.000	221.341	221.341	161.730
AFTER	2.023	1.339	.788	7.742	37.247	1.35	.000	37.247	258.588	168.230
TOTAL	34.398	16.665	17.911	514.851	258.588	1.35	.000	258.588	258.588	168.230

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	88.0	42.0	LIFE,YRS.	38.42	8.00	179.806
GROSS ULT., MB & MMF	18911.760	41146.960	DISCOUNT %	10.00	10.00	168.230
GROSS CUM., MB & MMF	18535.740	39805.960	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	158.354
GROSS RES., MB & MMF	376.015	1341.004	DISCOUNTED PAYOUT, YRS.	.00	15.00	145.944
NET RES., MB & MMF	35.537	120.914	UNDISCOUNTED NET/INVEST.	.00	20.00	129.794
NET REVENUE, M$	624.766	217.645	DISCOUNTED NET/INVEST.	.00	25.00	117.457
INITIAL PRICE, $	17.133	1.327	RATE-OF-RETURN,PCT.	100.00	35.00	99.723
INITIAL N.I., PCT.	10.316	13.957	INITIAL W.I., PCT.	12.189	50.00	82.717
					70.00	68.816
					100.00	56.513

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	08:05:43
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.1	1.157	2.313	.000	.068	.120	.000	17.92	1.22	1.218	.147	1.365
12-04	1.0	9.883	19.767	.000	.581	1.028	.000	17.92	1.22	10.405	1.254	11.659
12-05	1.0	6.434	12.867	.000	.378	.669	.000	17.92	1.22	6.773	.816	7.590
12-06	1.0	4.907	9.815	.000	.288	.510	.000	17.92	1.22	5.166	.623	5.789
12-07	1.0	4.021	8.042	.000	.236	.418	.000	17.92	1.22	4.233	.510	4.744
12-08	1.0	3.453	6.907	.000	.203	.359	.000	17.92	1.22	3.636	.438	4.074
12-09	1.0	3.038	6.076	.000	.178	.316	.000	17.92	1.22	3.198	.385	3.584
12-10	1.0	2.673	5.347	.000	.157	.278	.000	17.92	1.22	2.815	.339	3.154
12-11	1.0	2.353	4.705	.000	.138	.245	.000	17.92	1.22	2.477	.299	2.775
12-12	1.0	2.070	4.141	.000	.122	.215	.000	17.92	1.22	2.180	.263	2.442
12-13	1.0	1.822	3.644	.000	.107	.189	.000	17.92	1.22	1.918	.231	2.149
S TOT	1.0	41.812	83.624	.000	2.456	4.348	.000	17.92	1.22	44.019	5.305	49.325
AFTER	1.0	6.081	12.162	.000	.357	.632	.000	17.92	1.22	6.402	.772	7.173
TOTAL	1.0	47.893	95.785	.000	2.814	4.981	.000	17.92	1.22	50.421	6.077	56.498

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	000	.000
12-03	.085	.012	.013	.085	1.170	2.21	.000	1.170	1.170	.971
12-04	.728	.100	.108	1.014	9.708	2.59	.000	9.708	10.879	8.661
12-05	.474	.065	.071	1.014	5.966	3.32	.000	5.966	16.844	12.949
12-06	.362	.050	.054	1.014	4.310	3.96	.000	4.310	21.154	15.763
12-07	.296	.041	.044	1.014	3.348	4.56	.000	3.348	24.503	17.750
12-08	.254	.035	.038	1.014	2.732	5.11	.000	2.732	27.235	19.223
12-09	.224	.031	.033	1.014	2.282	5.63	.000	2.282	29.517	20.341
12-10	.197	.027	.029	1.014	1.886	6.23	.000	1.886	31.403	21.182
12-11	.173	.024	.026	1.014	1.538	6.91	.000	1.538	32.942	21.805
12-12	.153	.021	.023	1.014	1.232	7.68	.000	1.232	34.174	22.259
12-13	.134	.018	.020	1.014	.963	8.56	.000	.963	35.136	22.582
S TOT	3.081	.424	.458	10.225	35.136	14.89	.000	35.136	35.136	22.582
AFTER	.448	.062	.067	4.817	1.780	14.89	.000	1.780	36.916	23.076
TOTAL	3.529	.486	.525	15.041	36.916	14.89	.000	36.916	36.916	23.076

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE,YRS.	16.75	8.00	25.116
GROSS ULT., MB & MMF	47.893	126.862	DISCOUNT %	10.00	10.00	23.076
GROSS CUM., MB & MMF	.000	31.077	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	21.284
GROSS RES., MB & MMF	47.893	95.785	DISCOUNTED PAYOUT, YRS.	.00	15.00	18.976
NET RES., MB & MMF	2.814	4.981	UNDISCOUNTED NET/INVEST.	.00	20.00	15.910
NET REVENUE, M$	50.421	6.077	DISCOUNTED NET/INVEST.	.00	25.00	13.552
INITIAL PRICE, $	17.920	1.220	RATE-OF-RETURN, PCT.	100.00	35.00	10.203
INITIAL N.I., PCT.	5.875	5.200	INITIAL W.I., PCT.	6.500	50.00	7.131
					70.00	4.812
					100.00	2.990

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	08:05:43
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	56.7	57.396	247.357	.000	7.301	23.198	.000	17.64	1.71	128.766	39.725	168.491
12-03	40.8	42.029	191.647	.000	4.994	20.790	.000	17.37	1.74	86.764	36.238	123.002
12-04	27.0	38.143	178.457	.000	4.553	18.063	.000	17.54	1.64	79.861	29.608	109.470
12-05	27.0	32.943	156.092	.000	4.105	16.396	.000	17.53	1.65	71.977	27.117	99.093
12-06	25.2	28.602	133.861	.000	3.197	12.313	.000	17.62	1.69	56.316	20.774	77.091
12-07	21.8	25.608	105.879	.000	2.667	7.862	.000	17.79	1.68	47.445	13.232	60.677
12-08	18.2	23.098	58.628	.000	2.247	4.630	.000	17.89	1.84	40.206	8.498	48.704
12-09	17.8	21.528	48.270	.000	2.120	4.129	.000	17.89	1.86	37.934	7.666	45.600
12-10	17.0	20.080	43.241	.000	2.001	3.718	.000	17.89	1.80	35.815	6.705	42.520
12-11	14.8	17.687	37.608	.000	1.680	3.405	.000	17.78	1.82	29.865	6.190	36.055
12-12	13.3	14.726	33.289	.000	.805	2.623	.000	17.16	2.04	13.808	5.361	19.169
12-13	9.6	11.488	25.498	.000	.483	1.856	.000	16.95	2.44	8.190	4.537	12.726
S TOT	1.0	333.327	1259.826	.000	36.153	118.984	.000	17.62	1.73	636.946	205.651	842.597
AFTER	1.0	90.580	176.963	.000	2.199	6.911	.000	17.39	2.61	38.242	18.071	56.312
TOTAL	1.0	423.908	1436.789	.000	38.351	125.895	.000	17.61	1.78	675.188	223.722	898.909

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	6.963	3.056	3.637	108.661	46.175	10.95	.000	46.175	46.175	44.136
12-03	4.965	2.790	2.409	74.751	38.087	10.04	.000	38.087	84.261	77.170
12-04	4.652	2.269	2.114	60.578	39.855	9.20	.000	39.855	124.117	108.662
12-05	4.151	2.078	1.951	60.578	30.335	10.06	.000	30.335	154.452	130.445
12-06	3.103	1.577	1.685	46.925	23.801	10.15	.000	23.801	178.252	145.977
12-07	2.627	1.008	1.292	36.450	19.299	10.40	.000	19.299	197.552	157.425
12-08	2.163	.648	1.078	29.184	15.630	10.95	.000	15.630	213.182	165.853
12-09	2.036	.585	1.014	29.033	12.932	11.63	.000	12.932	226.114	172.193
12-10	1.917	.512	.952	28.581	10.558	12.19	.000	10.558	236.672	176.899
12-11	1.625	.473	.785	25.155	8.017	12.48	.000	8.017	244.689	180.148
12-12	.783	.408	.396	11.118	6.463	10.23	.000	6.463	251.152	182.528
12-13	.471	.345	.267	6.319	5.325	9.34	.000	5.325	256.477	184.312
S TOT	35.456	15.750	17.581	517.333	256.477	1.35	.000	256.477	256.477	184.312
AFTER	2.471	1.401	.855	12.559	39.027	1.35	.000	39.027	295.504	191.307
TOTAL	37.927	17.151	18.436	529.892	295.504	1.35	.000	295.504	295.504	191.307

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	89.0	42.0	LIFE, YRS.	38.42	8.00	204.922
GROSS ULT., MB & MMF	18959.650	41273.820	DISCOUNT %	10.00	10.00	191.307
GROSS CUM., MB & MMF	18535.740	39837.040	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	179.638
GROSS RES., MB & MMF	423.908	1436.789	DISCOUNTED PAYOUT,YRS.	.00	15.00	164.921
NET RES., MB & MMF	38.351	125.895	UNDISCOUNTED NET/INVEST.	.00	20.00	145.704
NET REVENUE, M$	675.188	223.722	DISCOUNTED NET/INVEST.	.00	25.00	131.008
INITIAL PRICE, $	17.219	1.321	RATE-OF-RETURN,PCT.	100.00	35.00	109.927
INITIAL N.I., PCT.	9.831	13.453	INITIAL W.I., PCT.	11.620	50.00	89.848
					70.00	73.628
					100.00	59.504

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	18:38:17
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	75.7	119.833	552.281	.000	19.346	78.953	.000	18.12	2.11	350.460	166.546	517.005
12-03	59.8	94.825	461.883	.000	16.058	72.150	.000	18.08	2.11	290.273	152.580	442.853
12-04	45.0	76.290	404.907	.000	14.355	64.737	.000	18.13	2.10	260.286	135.833	396.119
12-05	45.0	70.038	367.097	.000	13.460	60.021	.000	18.13	2.09	244.010	125.727	369.738
12-06	43.2	63.609	328.504	.000	12.060	52.991	.000	18.18	2.12	219.236	112.290	331.526
12-07	39.8	58.488	285.168	.000	11.055	45.784	.000	18.23	2.15	201.564	98.212	299.776
12-08	36.2	53.967	223.797	.000	10.184	39.989	.000	18.26	2.19	185.985	87.454	273.439
12-09	35.8	50.561	200.590	.000	9.631	37.109	.000	18.26	2.18	175.880	81.070	256.950
12-10	34.3	47.272	170.822	.000	9.113	34.335	.000	18.26	2.17	166.401	74.555	240.957
12-11	31.8	43.374	152.367	.000	8.419	31.951	.000	18.24	2.17	153.596	69.236	222.832
12-12	29.6	38.627	136.578	.000	6.968	27.647	.000	18.29	2.30	127.411	63.670	191.081
12-13	25.6	33.963	120.085	.000	6.217	24.416	.000	18.35	2.40	114.107	58.660	172.767
S TOT	1.0	750.848	3404.079	.000	136.867	570.084	.000	18.19	2.15	2489.211	1225.833	3715.044
AFTER	1.0	285.890	757.856	.000	56.946	157.739	.000	18.55	2.30	1056.212	362.593	1418.805
TOTAL	1.0	1036.737	4161.935	.000	193.813	727.823	.000	18.29	2.18	3545.423	1588.426	5133.849

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	18.703	12.848	11.010	187.363	287.081	7.07	.000	287.081	287.081	274.127
12-03	15.750	11.778	9.150	153.368	252.807	6.77	.000	252.807	539.888	493.546
12-04	14.071	10.477	8.254	138.266	225.052	6.80	.000	225.052	764.940	671.108
12-05	13.192	9.701	7.694	138.266	200.885	7.20	.000	200.885	965.825	815.196
12-06	11.689	8.655	7.060	124.613	179.511	7.28	.000	179.511	1145.336	932.244
12-07	10.760	7.582	6.330	114.138	160.965	7.43	.000	160.965	1306.301	1027.656
12-08	9.861	6.759	5.806	106.872	144.141	7.67	.000	144.141	1450.442	1105.330
12-09	9.322	6.267	5.457	106.721	129.183	8.08	.000	129.183	1579.625	1168.615
12-10	8.816	5.767	5.117	105.812	115.445	8.46	.000	115.445	1695.069	1220.030
12-11	8.161	5.357	4.704	102.234	102.376	8.76	.000	102.376	1797.446	1261.482
12-12	6.720	4.926	4.052	84.332	91.052	8.64	.000	91.052	1888.498	1294.995
12-13	5.973	4.539	3.694	77.601	80.960	8.92	.000	80.960	1969.458	1322.088
S TOT	133.015	94.655	78.330	1439.585	1969.458	1.35	.000	1969.458	1969.458	1322.088
AFTER	54.283	28.330	30.566	828.559	477.067	1.35	.000	477.067	2446.526	1423.519
TOTAL	187.298	122.985	108.896	2268.145	2446.526	1.35	.000	2446.526	2446.526	1423.519

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	98.0	51.0	LIFE, YRS	38.42	8.00	1553.102
GROSS ULT., MB & MMF	20876.210	52787.180	DISCOUNT %	10.00	10.00	1423.519
GROSS CUM., MB & MMF	19839.470	48625.240	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1314.791
GROSS RES., MB & MMF	1036.737	4161.935	DISCOUNTED PAYOUT, YRS.	.00	15.00	1181.334
NET RES., MB & MMF	193.813	727.823	UNDISCOUNTED NET/INVEST.	.00	20.00	1014.232
NET REVENUE, M$	3545.423	1588.426	DISCOUNTED NET/INVEST.	.00	25.00	892.494
INITIAL PRICE, $	17.724	1.854	RATE-OF-RETURN, PCT.	100.00	35.00	727.417
INITIAL N.I., PCT.	13.398	15.620	INITIAL W.I., PCT.	15.767	50.00	580.385
					70.00	468.133
					100.00	374.327

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	18:38:18
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.7	13.516	849.555	.000	.287	22.998	.000	19.72	2.90	5.657	66.637	72.293
12-03	4.9	37.122	598.692	.000	.520	14.382	.000	19.13	2.86	9.947	41.115	51.062
12-04	9.3	117.440	502.551	.000	3.235	11.062	.000	18.94	2.71	61.251	29.937	91.187
12-05	10.0	92.082	379.257	.000	2.594	8.209	.000	18.98	2.72	49.227	22.364	71.592
12-06	10.0	65.592	301.537	.000	1.705	6.530	.000	18.95	2.73	32.306	17.818	50.123
12-07	10.0	51.000	252.099	.000	1.216	5.442	.000	18.92	2.73	23.002	14.852	37.854
12-08	10.0	43.328	217.571	.000	1.047	4.676	.000	18.91	2.73	19.808	12.757	32.565
12-09	10.0	37.956	191.936	.000	.931	4.105	.000	18.91	2.73	17.612	11.194	28.806
12-10	10.0	33.793	172.010	.000	.833	3.658	.000	18.92	2.73	15.749	9.974	25.723
12-11	8.2	25.244	135.249	.000	.694	3.082	.000	18.91	2.74	13.117	8.441	21.558
12-12	7.0	19.939	112.021	.000	.593	2.681	.000	18.90	2.75	11.217	7.369	18.586
12-13	5.8	13.344	95.935	.000	.501	2.404	.000	18.88	2.75	9.465	6.614	16.078
S TOT	1.0	550.356	3808.413	.000	14.156	89.230	.000	18.96	2.79	268.357	249.071	517.427
AFTER	1.0	33.017	823.376	.000	1.351	22.251	.000	18.90	2.85	25.524	63.345	88.868
TOTAL	1.0	583.373	4631.789	.000	15.507	111.480	.000	18.95	2.80	293.880	312.415	606.296

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.260	4.998	2.011	1.879	63.145	2.22	.000	63.145	63.145	60.350
12-03	.490	3.085	1.396	2.744	43.348	2.64	.000	43.348	106.493	98.014
12-04	3.097	2.254	2.327	7.128	76.382	2.92	.000	76.382	182.875	158.052
12-05	2.448	1.683	1.860	8.206	57.394	3.58	.000	57.394	240.269	199.325
12-06	1.628	1.341	1.288	8.206	37.661	4.46	.000	37.661	277.930	223.937
12-07	1.175	1.118	.962	8.206	26.393	5.40	.000	26.393	304.323	239.601
12-08	1.013	.960	.827	8.206	21.560	6.02	.000	21.560	325.883	251.225
12-09	.900	.842	.731	8.206	18.126	6.61	.000	18.126	344.010	260.109
12-10	.804	.751	.653	8.206	15.309	7.22	.000	15.309	359.319	266.930
12-11	.674	.635	.544	7.647	12.057	7.87	.000	12.057	371.376	271.819
12-12	.579	.555	.467	7.292	9.693	8.55	.000	9.693	381.069	275.389
12-13	.492	.498	.402	7.064	7.623	9.38	.000	7.623	388.692	277.944
S TOT	13.561	18.719	13.467	82.988	388.692	17.10	.000	388.692	388.692	277.944
AFTER	1.358	4.757	2.317	47.617	32.819	17.10	.000	32.819	421.511	284.990
TOTAL	14.919	23.477	15.784	130.605	421.511	17.10	.000	421.511	421.511	284.990

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	8.0	2.0	LIFE, YRS	32.00	8.00	304.388
GROSS ULT., MB & MMF	588.756	4784.355	DISCOUNT %	10.00	10.00	284.990
GROSS CUM., MB & MMF	5.383	152.567	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	268.037
GROSS RES., MB & MMF	583.373	4631.788	DISCOUNTED PAYOUT, YRS.	.00	15.00	246.260
NET RES., MB & MMF	15.507	111.480	UNDISCOUNTED NET/INVEST.	.00	20.00	217.254
NET REVENUE, M$	293.880	312.415	DISCOUNTED NET/INVEST.	.00	25.00	194.715
INITIAL PRICE, $	19.080	2.836	RATE-OF-RETURN, PCT.	100.00	35.00	161.995
INITIAL N.I., PCT.	2.724	2.513	INITIAL W.I., PCT.	3.186	50.00	130.614
					70.00	105.322
					100.00	83.573

SW OIL & GAS INCOME FUND IX-A	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	18:38:18
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	78.3	133.349	1401.835	.000	19.633	101.951	.000	18.14	2.29	356.117	233.182	589.299
12-03	64.7	131.948	1060.575	.000	16.578	86.532	.000	18.11	2.24	300.220	193.695	493.915
12-04	54.3	193.730	907.458	.000	17.590	75.799	.000	18.28	2.19	321.537	165.769	487.307
12-05	55.0	162.119	746.354	.000	16.054	68.230	.000	18.27	2.17	293.238	148.092	441.329
12-06	53.2	129.201	630.041	.000	13.765	59.521	.000	18.27	2.19	251.542	130.108	381.650
12-07	49.8	109.488	537.267	.000	12.271	51.226	.000	18.30	2.21	224.566	113.064	337.630
12-08	46.2	97.295	441.368	.000	11.231	44.665	.000	18.32	2.24	205.793	100.212	306.004
12-09	45.8	88.517	392.526	.000	10.562	41.215	.000	18.32	2.24	193.492	92.264	285.756
12-10	44.3	81.065	342.833	.000	9.946	37.992	.000	18.31	2.22	182.150	84.530	266.680
12-11	39.9	68.618	287.616	.000	9.113	35.034	.000	18.29	2.22	166.713	77.677	244.390
12-12	36.6	58.566	248.599	.000	7.561	30.328	.000	18.33	2.34	138.628	71.038	209.667
12-13	31.4	47.307	216.020	.000	6.718	26.821	.000	18.39	2.43	123.572	65.273	188.845
S TOT	1.0	1301.203	7212.492	.000	151.023	659.314	.000	18.26	2.24	2757.567	1474.904	4232.471
AFTER	1.0	318.907	1581.232	.000	58.297	179.989	.000	18.56	2.37	1081.736	425.938	1507.674
TOTAL	1.0	1620.110	8793.724	.000	209.320	839.303	.000	18.34	2.26	3839.303	1900.842	5740.145

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	18.963	17.846	13.021	189.242	350.227	6.53	.000	350.227	350.227	334.478
12-03	16.240	14.863	10.546	156.112	296.155	6.38	.000	296.155	646.381	591.560
12-04	17.168	12.731	10.581	145.394	301.433	6.15	.000	301.433	947.815	829.160
12-05	15.640	11.384	9.554	146.472	258.279	6.67	.000	258.279	1206.094	1014.521
12-06	13.316	9.995	8.348	132.818	217.172	6.94	.000	217.172	1423.266	1156.181
12-07	11.935	8.700	7.292	122.344	187.359	7.22	.000	187.359	1610.624	1267.257
12-08	10.874	7.719	6.633	115.078	165.701	7.51	.000	165.701	1776.325	1356.555
12-09	10.222	7.110	6.188	114.927	147.309	7.94	.000	147.309	1923.634	1428.724
12-10	9.620	6.518	5.771	114.017	130.754	8.35	.000	130.754	2054.388	1486.960
12-11	8.835	5.993	5.248	109.881	114.434	8.69	.000	114.434	2168.822	1533.301
12-12	7.299	5.480	4.518	91.624	100.745	8.63	.000	100.745	2269.567	1570.384
12-13	6.464	5.037	4.096	84.665	88.583	8.96	.000	88.583	2358.150	1600.032
S TOT	146.576	113.375	91.797	1522.573	2358.150	1.35	.000	2358.150	2358.150	1600.032
AFTER	55.641	33.087	32.883	876.177	509.886	1.35	.000	509.886	2868.037	1708.509
TOTAL	202.217	146.462	124.680	2398.749	2868.037	1.35	.000	2868.037	2868.037	1708.509

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	106.0	53.0	LIFE, YRS	38.42	8.00	1857.489
GROSS ULT., MB & MMF	21464.960	57571.530	DISCOUNT %	10.00	10.00	1708.509
GROSS CUM., MB & MMF	19844.850	48777.810	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1582.828
GROSS RES., MB & MMF	1620.110	8793.723	DISCOUNTED PAYOUT, YRS.	.00	15.00	1427.594
NET RES., MB & MMF	209.320	839.303	UNDISCOUNTED NET/INVEST.	.00	20.00	1231.485
NET REVENUE, M$	3839.304	1900.842	DISCOUNTED NET/INVEST.	.00	25.00	1087.210
INITIAL PRICE, $	18.422	2.525	RATE-OF-RETURN, PCT.	100.00	35.00	889.413
INITIAL N.I., PCT.	7.905	6.658	INITIAL W.I., PCT.	7.658	50.00	710.999
					70.00	573.455
					100.00	457.901

APPENDIX B9

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWR Inst Income Fund IX-B (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 22 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 79.5 percent of the total net remaining liquid hydrocarbon reserves and 84.6 percent of the total net remaining gas reserves. The properties that we reviewed represent 86.4 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002 they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWR Inst Income Fund IX-B

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		147,785		0		2,589		149,774
Gas—MMCF		570		0		93		663
Income Data
Future Gross Revenue	$	3,763,476	$	0	$	296,761	$	4,060,237
Deductions		1,705,859		0		63,466		1,769,325
Future Net Income (FNI)	$	2,057,617	$	0	$	233,295	$	2,290,912
Discounted FNI @ 10%	$	1,182,141	$	0	$	160,643	$	1,342,784

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		36,009		0		2,598		38,607
Gas—MMCF		116		0		5		121
Income Data
Future Gross Revenue	$	792,526	$	0	$	48,452	$	840,978
Deductions		498,951		0		14,369		513,320
Future Net Income (FNI)	$	293,575	$	0	$	34,083	$	327,658
Discounted FNI @ 10%	$	190,698	$	0	$	21,306	$	212,004
Total Net Reserves
Oil/Condensate—Barrels		183,194		0		5,187		188,381
Gas—MMCF		686		0		98		784
Income Data
Future Gross Revenue	$	4,556,002	$	0	$	345,213	$	4,901,215
Deductions		2,204,810		0		77,835		2,282,645
Future Net Income (FNI)	$	2,351,192	$	0	$	267,378	$	2,618,570
Discounted FNI @ 10%	$	1,372,839	$	0	$	181,949	$	1,554,788

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)  Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A)  that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B)  the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? . . . The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 20.5 percent of the total net remaining liquid hydrocarbon reserves and 15.4 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

		Very truly yours,
		RYDER SCOTT COMPANY, L.P.
		By:	/s/    C. PATRICK MCINTURFF
			C. Patrick McInturff, P.E. Petroleum Engineer
CPM/sw
Approved:
/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

SWR INST INCOME FUND IX-B	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:15
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	20.0	64.705	266.707	.000	11.253	52.135	.000	18.42	2.27	207.245	118.335	325.579
12-03	20.0	56.112	241.214	.000	10.402	48.209	.000	18.40	2.26	191.412	108.866	300.278
12-04	20.0	50.082	220.767	.000	9.702	44.734	.000	18.39	2.25	178.424	100.598	279.022
12-05	20.0	45.475	203.452	.000	9.094	41.596	.000	18.38	2.24	167.175	93.201	260.376
12-06	20.0	41.757	188.324	.000	8.551	38.731	.000	18.38	2.23	157.137	86.494	243.631
12-07	20.0	38.644	174.847	.000	8.057	36.100	.000	18.37	2.23	148.020	80.364	228.384
12-08	20.0	35.968	162.692	.000	7.602	33.673	.000	18.37	2.22	139.646	74.736	214.382
12-09	20.0	33.624	151.637	.000	7.181	31.429	.000	18.37	2.21	131.895	69.551	201.447
12-10	20.0	31.540	141.525	.000	6.790	29.350	.000	18.36	2.21	124.686	64.765	189.451
12-11	20.0	29.666	132.235	.000	6.424	27.422	.000	18.36	2.20	117.953	60.339	178.293
12-12	19.3	27.485	119.689	.000	5.871	24.104	.000	18.43	2.32	108.228	55.842	164.071
12-13	17.0	24.297	98.231	.000	5.392	21.224	.000	18.46	2.40	99.540	50.904	150.444
S TOT	1.0	479.354	2101.319	.000	96.319	428.707	.000	18.39	2.25	1771.361	963.995	2735.356
AFTER	1.0	201.390	593.055	.000	50.866	141.590	.000	18.59	2.29	945.569	324.534	1270.103
TOTAL	1.0	680.744	2694.374	.000	147.185	570.298	.000	18.46	2.26	2716.930	1288.530	4005.459

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	10.957	9.134	6.900	72.400	226.189	4.98	.000	226.189	226.189	215.937
12-03	10.146	8.408	6.326	72.400	202.998	5.28	.000	202.998	429.186	392.102
12-04	9.471	7.773	5.857	72.400	183.522	5.57	.000	183.522	612.708	536.882
12-05	8.880	7.204	5.454	72.400	166.438	5.86	.000	166.438	779.146	656.246
12-06	8.350	6.687	5.096	72.400	151.098	6.17	.000	151.098	930.244	754.757
12-07	7.866	6.215	4.773	72.400	137.130	6.48	.000	137.130	1067.374	836.035
12-08	7.420	5.781	4.479	72.400	124.302	6.82	.000	124.302	1191.676	903.012
12-09	7.006	5.381	4.208	72.400	112.451	7.17	.000	112.451	1304.127	958.096
12-10	6.621	5.012	3.958	72.400	101.460	7.53	.000	101.460	1405.587	1003.280
12-11	6.260	4.671	3.726	72.400	91.236	7.92	.000	91.236	1496.823	1040.217
12-12	5.683	4.323	3.475	68.833	81.758	8.32	.000	81.758	1578.581	1070.309
12-13	5.202	3.943	3.195	67.049	71.054	8.89	.000	71.054	1649.635	1094.085
S TOT	93.862	74.532	57.446	859.881	1649.635	19.99	.000	1649.635	1649.635	1094.085
AFTER	48.240	25.350	27.577	760.955	407.982	19.99	.000	407.982	2057.617	1182.141
TOTAL	142.102	99.881	85.023	1620.836	2057.617	19.99	.000	2057.617	2057.617	1182.141

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	11.0	9.0	LIFE, YRS.	31.0	8.00	1293.115
GROSS ULT., MB & MMF	2131.270	11784.360	DISCOUNT %	10.00	10.00	1182.141
GROSS CUM., MB & MMF	1450.526	9089.989	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1089.127
GROSS RES., MB & MMF	680.744	2694.374	DISCOUNTED PAYOUT, YRS.	.00	15.00	975.160
NET RES., MB & MMF	147.185	570.297	UNDISCOUNTED NET/INVEST.	.00	20.00	832.935
NET REVENUE, M$	2716.930	1288.530	DISCOUNTED NET/INVEST.	.00	25.00	729.798
INITIAL PRICE, $	18.737	2.524	RATE-OF-RETURN, PCT.	100.00	35.00	590.837
INITIAL N.I., PCT.	16.762	19.281	INITIAL W.I. , PCT.	19.283	50.00	468.209
					70.00	375.498
					100.00	298.724

SWR INST INCOME FUND IX-B	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:15
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.7	8.966	831.352	.000	.221	21.056	.000	19.84	2.90	4.394	61.062	65.456
12-03	2.1	6.348	477.909	.000	.135	12.037	.000	19.76	2.90	2.672	34.895	37.567
12-04	4.5	62.046	391.657	.000	.450	8.395	.000	19.21	2.89	8.640	24.229	32.869
12-05	5.0	48.494	295.673	.000	.349	6.286	.000	19.22	2.89	6.712	18.146	24.859
12-06	5.0	34.372	233.211	.000	.252	4.999	.000	19.21	2.89	4.835	14.430	19.264
12-07	5.0	26.943	193.774	.000	.199	4.158	.000	19.20	2.89	3.822	11.999	15.820
12-08	5.0	22.318	166.351	.000	.166	3.563	.000	19.20	2.88	3.180	10.279	13.459
12-09	5.0	19.147	146.101	.000	.143	3.119	.000	19.19	2.88	2.735	8.996	11.731
12-10	5.0	16.830	130.506	.000	.125	2.775	.000	19.18	2.88	2.407	8.002	10.409
12-11	5.0	15.049	118.083	.000	.112	2.501	.000	19.17	2.88	2.153	7.209	9.362
12-12	5.0	13.614	107.880	.000	.102	2.276	.000	19.16	2.88	1.948	6.560	8.507
12-13	3.8	7.691	92.291	.000	.063	2.045	.000	19.13	2.88	1.210	5.891	7.101
S TOT	1.0	281.818	3184.788	.000	2.317	73.210	.000	19.29	2.89	44.707	211.697	256.404
AFTER	1.0	18.716	811.214	.000	.272	19.955	.000	19.49	2.89	5.300	57.760	63.060
TOTAL	1.0	300.534	3996.002	.000	2.589	93.166	.000	19.31	2.89	50.006	269.457	319.463

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.202	4.580	1.820	1.453	57.401	2.16	.000	57.401	57.401	54.901
12-03	.126	2.617	1.041	1.681	32.101	2.55	.000	32.101	89.501	82.848
12-04	.425	1.819	.889	2.086	27.650	2.82	.000	27.650	117.151	104.657
12-05	.329	1.363	.674	2.176	20.318	3.25	.000	20.318	137.469	119.254
12-06	.239	1.084	.521	2.176	15.245	3.70	.000	15.245	152.714	129.206
12-07	.190	.901	.426	2.176	12.127	4.14	.000	12.127	164.841	136.400
12-08	.159	.772	.362	2.176	9.990	4.57	.000	9.990	174.831	141.786
12-09	.138	.676	.315	2.176	8.427	4.99	.000	8.427	183.258	145.916
12-10	.122	.601	.279	2.176	7.232	5.40	.000	7.232	190.490	149.138
12-11	.110	.541	.250	2.176	6.285	5.82	.000	6.285	196.775	151.683
12-12	.100	.493	.227	2.176	5.513	6.23	.000	5.513	202.287	153.712
12-13	.065	.443	.188	1.966	4.440	6.59	.000	4.440	206.727	155.201
S TOT	2.204	15.889	6.992	24.591	206.727	17.10	.000	206.727	206.727	155.201
AFTER	.272	4.334	1.724	30.159	26.571	17.10	.000	26.571	233.298	160.643
TOTAL	2.476	20.223	8.716	54.750	233.298	17.10	.000	233.298	233.298	160.643

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	3.0	2.0	LIFE, YRS.	32.00	8.00	170.414
GROSS ULT., MB & MMF	305.917	4062.201	DISCOUNT %	10.00	10.00	160.643
GROSS CUM., MB & MMF	5.383	66.199	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	152.233
GROSS RES., MB &MMF	300.534	3996.002	DISCOUNTED PAYOUT, YRS.	.00	15.00	141.589
NET RES., MB &MMF	2.589	93.166	UNDISCOUNTED NET/INVEST.	.00	20.00	127.634
NET REVENUE, M$	50.006	269.457	DISCOUNTED NET/INVEST.	.00	25.00	116.906
INITIAL PRICE, $	19.195	2.883	RATE-OF-RETURN, PCT.	100.00	35.00	101.365
INITIAL N.I., PCT.	.873	2.376	INITIAL W.I., PCT.	2.324	50.00	86.249
					70.00	73.631
					100.00	62.149

SWR INST INCOME FUND IX-B	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:16
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES   M$
12-02	21.7	73.670	1098.059	.000	11.474	73.191	.000	18.44	2.45	211.639	179.396	391.035
12-03	22.1	62.460	719.123	.000	10.537	60.246	.000	18.42	2.39	194.084	143.761	337.844
12-04	24.5	12.128	612.424	.000	10.152	53.129	.000	18.43	2.35	187.064	124.827	311.891
12-05	25.0	93.969	499.124	.000	9.443	47.882	.000	18.41	2.33	173.887	111.347	285.234
12-06	25.0	76.129	421.534	.000	8.802	43.731	.000	18.40	2.31	161.972	100.923	262.895
12-07	25.0	65.587	368.621	.000	8.256	40.258	.000	18.39	2.29	151.842	92.363	244.205
12-08	25.0	58.287	329.043	.000	7.768	37.236	.000	18.39	2.28	142.826	85.015	227.840
12-09	25.0	52.771	297.738	.000	7.324	34.548	.000	18.38	2.27	134.630	78.547	213.178
12-10	25.0	48.370	272.031	.000	6.915	32.126	.000	18.38	2.27	127.092	72.767	199.860
12-11	25.0	44.716	250.317	.000	6.536	29.923	.000	18.38	2.26	120.106	67.548	187.654
12-12	24.3	41.098	227.570	.000	5.973	26.380	.000	18.45	2.37	110.176	62.402	172.578
12-13	20.8	31.987	190.522	.000	5.455	23.268	.000	18.47	2.44	100.750	56.795	157.545
S TOT	1.0	761.172	5286.107	.000	98.636	501.918	.000	18.41	2.34	1816.068	1175.692	2991.760
AFTER	1.0	220.106	1404.269	.000	51.138	161.545	.000	18.59	2.37	950.869	382.294	1333.163
TOTAL	1.0	981.278	6690.376	.000	149.774	663.463	.000	18.47	2.35	2766.937	1557.987	4324.923

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX   M$	LEASE OP EXPENSES M$	NET REVENUE   M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	11.159	13.714	8.720	73.853	283.589	4.54	.000	283.589	283.589	270.838
12-03	10.272	11.025	7.367	74.081	235.099	4.99	.000	235.099	518.688	474.950
12-04	9.896	9.592	6.747	74.486	211.171	5.30	.000	211.171	729.859	641.538
12-05	9.209	8.566	6.128	74.576	186.756	5.65	.000	186.756	916.615	775.500
12-06	8.589	7.771	5.617	74.576	166.343	6.00	.000	166.343	1082.958	883.963
12-07	8.056	7.116	5.199	74.576	149.257	6.34	.000	149.257	1232.215	972.434
12-08	7.579	6.553	4.840	74.576	134.292	6.69	.000	134.292	1366.507	1044.798
12-09	7.144	6.057	4.523	74.576	120.878	7.06	.000	120.878	1487.386	1104.013
12-10	6.743	5.613	4.236	74.576	108.692	7.43	.000	108.692	1596.077	1152.417
12-11	6.370	5.212	3.976	74.576	97.521	7.82	.000	97.521	1693.598	1191.900
12-12	5.783	4.815	3.702	71.008	87.270	8.23	.000	87.270	1780.868	1224.021
12-13	5.267	4.385	3.383	69.015	75.495	8.79	.000	75.495	1856.362	1249.285
S TOT	96.067	90.421	64.438	884.472	1856.362	17.10	.000	1856.362	1856.362	1249.285
AFTER	48.512	29.684	29.301	791.114	434.552	17.10	.000	434.552	2290.915	1342.783
TOTAL	144.578	120.105	93.739	1675.587	2290.915	17.10	.000	2290.915	2290.915	1342.783

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	14.0	11.0	LIFE, YRS.	32.00	8.00	1463.529
GROSS ULT., MB & MMF	2437.187	15846.560	DISCOUNT %	10.00	10.00	1342.784
GROSS CUM., MB & MMF	1455.909	9156.188	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1241.361
GROSS RES., MB & MMF	981.278	6690.376	DISCOUNTED PAYOUT, YRS.	.00	15.00	1116.749
NET RES., MB & MMF	149.774	663.463	UNDISCOUNTED NET/INVEST.	.00	20.00	960.569
NET REVENUE, M$	2766.937	1557.986	DISCOUNTED NET/INVEST.	.00	25.00	846.705
INITIAL PRICE, $	19.021	2.828	RATE-OF-RETURN, PCT.	100.00	35.00	692.202
INITIAL N.I., PCT.	6.925	4.984	INITIAL W.I., PCT.	6.287	50.00	554.458
					70.00	449.129
					100.00	360.873

SWR INST INCOME FUND IX-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	08:05:47
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD   MMCF	GROSS NGL PROD   MBBLS	NET OIL PROD MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE   $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M/$	NET GAS SALES M$	TOTAL NET SALES   M$
12-02	266.2	1475.491	569.910	.000	5.968	22.375	.000	17.37	1.73	103.671	38.678	142.349
12-03	263.3	1356.632	495.484	.000	5.215	20.009	.000	17.47	1.76	91.120	35.250	126.370
12-04	261.0	1247.109	449.102	.000	4.328	16.624	.000	17.59	1.69	76.155	28.042	104.197
12-05	259.0	1144.173	410.212	.000	4.062	15.365	.000	17.61	1.69	71.517	26.034	97.551
12-06	256.5	1051.470	370.433	.000	3.078	11.255	.000	17.62	1.72	54.230	19.344	73.573
12-07	252.8	967.086	326.122	.000	2.519	6.985	.000	17.74	1.71	44.697	11.971	56.668
12-08	249.2	889.868	264.198	.000	2.146	4.045	.000	17.83	1.89	38.276	7.643	45.920
12-09	248.8	819.436	239.973	.000	2.036	3.610	.000	17.84	1.91	36.311	6.896	43.207
12-10	248.0	754.595	222.007	.000	1.931	3.249	.000	17.84	1.85	34.456	6.002	40.458
12-11	244.7	691.889	203.495	.000	1.636	2.984	.000	17.73	1.86	29.007	5.554	34.561
12-12	231.3	614.726	179.263	.000	.811	2.275	.000	17.14	2.11	13.901	4.789	18.690
12-13	227.3	661.927	161.892	.000	.416	1.575	.000	16.77	2.57	6.978	4.047	11.024
S TOT	1.0	11574.400	3892.091	.000	34.146	110.351	.000	17.58	1.76	600.320	194.249	794.569
AFTER	1.0	1617.572	525.970	.000	1.864	5.851	.000	17.28	2.75	32.211	16.111	48.323
TOTAL	1.0	13191.970	4418.061	.000	36.009	116.202	.000	17.57	1.81	632.532	210.360	842.892

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	5.698	2.971	3.002	81.213	49.465	9.58	.000	49.465	49.465	47.254
12-03	5.049	2.710	2.624	75.157	40.830	10.01	.000	40.830	90.295	82.712
12-04	4.176	2.142	2.246	61.798	33.834	9.91	.000	33.834	124.129	109.421
12-05	3.915	1.989	2.107	61.798	27.741	10.54	.000	27.741	151.870	129.334
12-06	2.853	1.465	1.726	44.886	22.644	10.28	.000	22.644	174.514	144.107
12-07	2.372	.910	1.295	33.048	19.042	10.21	.000	19.042	193.556	155.399
12-08	1.970	.581	1.094	26.337	15.938	10.63	.000	15.938	209.494	163.992
12-09	1.868	.525	1.031	26.186	13.597	11.23	.000	13.597	223.091	170.655
12-10	1.772	.457	.969	25.733	11.527	11.70	.000	11.527	234.618	175.791
12-11	1.511	.423	.810	22.571	9.245	11.87	.000	9.245	243.863	179.537
12-12	.728	.364	.437	9.610	7.552	9.36	.000	7.552	251.415	182.317
12-13	.366	.307	.264	4.998	5.090	8.74	.000	5.090	256.505	184.023
S TOT	32.277	14.845	17.606	473.337	256.505	1.35	.000	256.505	256.505	184.023
AFTER	1.997	1.247	.812	7.196	37.071	1.35	.000	37.071	293.576	190.698
TOTAL	34.274	16.092	18.418	480.533	293.576	1.35	.000	293.576	293.576	190.698

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	266.0	17.0	LIFE, YRS.	38.42	8.00	204.168
GROSS ULT., MB & MMF	137058.200	52231.550	DISCOUNT %	10.00	10.00	190.698
GROSS CUM.,MB & MMF	123866.300	47813.490	UNDISCOUNTED PAYOUT,YRS.	.00	12.00	179.161
GROSS RES., MB & MMF	13191.970	4418.062	DISCOUNTED PAYOUT, YRS.	.00	15.00	164.626
NET RES., MB & MMF	36.009	116.202	UNDISCOUNTED NET/INVEST.	.00	20.00	145.693
NET REVENUE, M$	632.532	210.360	DISCOUNTED NET/INVEST.	.00	25.00	131.262
INITIAL PRICE, $	17.092	1.523	RATE-OF-RETURN, PCT.	100.00	35.00	110.640
INITIAL N.I., PCT.	.530	8.125	INITIAL W.I., PCT.	.791	50.00	91.073
					70.00	75.270
					100.00	61.436

SWR INST INCOME FUND IX-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	08:05:47
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.1	1.157	2.313	.000	.063	.111	.000	17.92	1.22	1.124	.135	1.260
12-04	1.0	9.883	19.767	.000	.536	.949	.000	17.92	1.22	9.606	1.158	10.764
12-05	1.0	6.434	12.867	.000	.349	.618	.000	17.92	1.22	6.253	.754	7.007
12-06	1.0	4.907	9.815	.000	.266	.471	.000	17.92	1.22	4.770	.575	5.345
12-07	1.0	4.021	8.042	.000	.218	.386	.000	17.92	1.22	3.908	.471	4.379
12-08	1.0	3.453	6.907	.000	.187	.332	.000	17.92	1.22	3.357	.404	3.761
12-09	1.0	3.038	6.076	.000	.165	.292	.000	17.92	1.22	2.953	.356	3.309
12-10	1.0	2.673	5.347	.000	.145	.257	.000	17.92	1.22	2.599	.313	2.912
12-11	1.0	2.353	4.705	.000	.128	.226	.000	17.92	1.22	2.287	.276	2.562
12-12	1.0	2.070	4.141	.000	.112	.199	.000	17.92	1.22	2.012	.242	2.255
12-13	1.0	1.822	3.644	.000	.099	.175	.000	17.92	1.22	1.771	.213	1.984
S TOT	1.0	41.812	83.624	.000	2.268	4.014	.000	17.92	1.22	40.640	4.897	45.537
AFTER	1.0	6.081	12.162	.000	.330	.584	.000	17.92	1.22	5.910	.712	6.623
TOTAL	1.0	47.893	95.785	.000	2.598	4.598	.000	17.92	1.22	46.551	5.609	52.160

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.079	.011	.012	.078	1.081	2.21	.000	1.081	1.081	.897
12-04	.672	.093	.100	.936	8.963	2.59	.000	8.963	10.043	7.996
12-05	.438	.060	.065	.936	5.508	3.32	.000	5.508	15.551	11.955
12-06	.334	.046	.050	.936	3.979	3.96	.000	3.979	19.530	14.553
12-07	.274	.038	.041	.936	3.091	4.56	.000	3.091	22.622	16.387
12-08	.235	.032	.035	.936	2.523	5.10	.000	2.523	25.145	17.747
12-09	.207	.028	.031	.936	2.107	5.63	.000	2.107	27.251	18.780
12-10	.182	.025	.027	.936	1.742	6.23	.000	1.742	28.993	19.556
12-11	.160	.022	.024	.936	1.420	6.91	.000	1.420	30.413	20.132
12-12	.141	.019	.021	.936	1.138	7.68	.000	1.138	31.551	20.551
12-13	.124	.017	.018	.936	.889	8.56	.000	.889	32.440	20.849
S TOT	2.845	.392	.423	9.438	32.440	14.89	.000	32.440	32.440	20.849
AFTER	.414	.057	.062	4.446	1.644	14.89	.000	1.644	34.084	21.306
TOTAL	3.259	.449	.485	13.884	34.084	14.89	.000	34.084	34.084	21.306

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	16.75	8.00	23.188
GROSS ULT., MB & MMF	47.893	126.862	DISCOUNT %	10.00	10.00	21.306
GROSS CUM., MB & MMF	.000	31.077	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	19.651
GROSS RES., MB & MMF	47.893	95.785	DISCOUNTED PAYOUT, YRS.	.00	15.00	17.520
NET RES., MB & MMF	2.598	4.598	UNDISCOUNTED NET/INVEST.	.00	20.00	14.689
NET REVENUE, M$	46.551	5.609	DISCOUNTED NET/INVEST.	.00	25.00	12.512
INITIAL PRICE, $	17.920	1.220	RATE-OF-RETURN, PCT.	100.00	35.00	9.420
INITIAL N.I., PCT.	5.424	4.800	INITIAL W.I., PCT.	6.000	50.00	6.584
					70.00	4.442
					100.00	2.761

SWR INST INCOME FUND IX-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	08:05:47
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	266.2	1475.491	569.910	.000	5.968	22.375	.000	17.37	1.73	103.671	38.678	142.349
12-03	263.3	1357.789	497.797	.000	5.277	20.120	.000	17.48	1.76	92.245	35.386	127.630
12-04	262.0	1256.993	468.869	.000	4.865	17.573	.000	17.63	1.66	85.761	29.199	114.961
12-05	260.0	1150.607	423.079	.000	4.411	15.983	.000	17.63	1.68	77.771	26.788	104.558
12-06	257.5	1056.377	380.248	.000	3.344	11.726	.000	17.64	1.70	58.999	19.919	78.918
12-07	253.8	971.107	334.164	.000	2.737	7.371	.000	17.76	1.69	48.606	12.442	61.047
12-08	250.2	893.321	271.105	.000	2.333	4.376	.000	17.84	1.84	41.633	8.048	49.681
12-09	249.8	822.474	246.049	.000	2.200	3.902	.000	17.84	1.86	39.264	7.251	46.515
12-10	249.0	757.268	227.354	.000	2.076	3.506	.000	17.85	1.80	37.055	6.315	43.370
12-11	245.7	694.242	208.200	.000	1.764	3.210	.000	17.74	1.82	31.294	5.830	37.124
12-12	232.3	616.796	183.404	.000	.923	2.474	.000	17.24	2.03	15.914	5.031	20.945
12-13	228.3	563.749	165.535	.000	.515	1.750	.000	16.99	2.43	8.749	4.260	13.009
S TOT	1.0	11616.210	3975.714	.000	36.413	114.364	.000	17.60	1.74	640.961	199.146	840.107
AFTER	1.0	1623.653	538.132	.000	2.193	6.435	.000	17.38	2.61	38.122	16.824	54.945
TOTAL	1.0	13239.870	4513.846	.000	38.607	120.799	.000	17.59	1.79	679.082	215.970	895.052

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	5.698	2.971	3.002	81.213	49.465	9.58	.000	49.465	49.465	47.254
12-03	5.128	2.721	2.636	75.235	41.911	9.93	.000	41.911	91.376	83.608
12-04	4.848	2.235	2.346	62.734	42.797	9.26	.000	42.797	134.172	117.418
12-05	4.353	2.050	2.172	62.734	33.249	10.08	.000	33.249	167.421	141.289
12-06	3.187	1.511	1.775	45.822	26.623	9.87	.000	26.623	194.044	158.660
12-07	2.646	.948	1.336	33.984	22.134	9.81	.000	22.134	216.178	171.786
12-08	2.205	.614	1.129	27.273	18.460	10.19	.000	18.460	234.638	181.739
12-09	2.075	.553	1.062	27.122	15.704	10.81	.000	15.704	250.342	189.435
12-10	1.954	.482	.996	26.669	13.269	11.31	.000	13.269	263.611	195.348
12-11	1.671	.445	.834	23.507	10.666	11.51	.000	10.666	274.277	199.669
12-12	.868	.383	.458	10.546	8.689	9.18	.000	8.689	282.966	202.868
12-13	.490	.324	.282	5.934	5.979	8.72	.000	5.979	288.944	204.872
S TOT	35.122	15.237	18.029	482.775	288.944	1.35	.000	288.944	288.944	204.872
AFTER	2.411	1.304	.873	11.642	38.715	1.35	.000	38.715	327.660	212.004
TOTAL	37.533	16.540	18.902	494.417	327.660	1.35	.000	327.660	327.660	212.004

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	267.0	17.0	LIFE, YRS.	38.42	8.00	227.356
GROSS ULT.,MB & MMF	137106.100	52358.410	DISCOUNT %	10.00	10.00	212.004
GROSS CUM., MB & MMF	123866.300	47844.560	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	198.811
GROSS RES., MB & MMF	13239.870	4513.846	DISCOUNTED PAYOUT, YRS.	.00	15.00	182.146
NET RES., MB & MMF	38.607	120.799	UNDISCOUNTED NET/INVEST.	.00	20.00	160.382
NET REVENUE, M$	679.082	215.970	DISCOUNTED NET/INVEST.	.00	25.00	143.773
INITIAL PRICE, $	17.100	1.512	RATE-OF-RETURN, PCT.	100.00	35.00	120.060
INITIAL N.I., PCT.	.574	8.004	INITIAL W.I., PCT.	.844	50.00	97.657
					70.00	79.712
					100.00	64.197

SWR INST INCOME FUND IX-B	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	18:38:24
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	286.2	1540.195	836.617	.000	17.221	74.509	.000	18.05	2.11	310.916	157.012	467.929
12-03	283.3	1412.744	736.698	.000	15.617	68.218	.000	18.09	2.11	282.532	144.116	426.648
12-04	281.0	1297.191	669.870	.000	14.030	61.359	.000	18.14	2.10	254.579	128.640	383.219
12-05	279.0	1189.648	613.663	.000	13.156	56.961	.000	18.14	2.09	238.692	119.235	357.927
12-06	276.5	1093.227	558.757	.000	11.628	49.986	.000	18.18	2.12	211.367	105.838	317.204
12-07	272.8	1005.730	500.969	.000	10.576	43.085	.000	18.22	2.14	192.718	92.335	285.053
12-08	269.2	925.837	426.890	.000	9.748	37.718	.000	18.25	2.18	177.922	82.379	260.301
12-09	268.8	853.060	391.610	.000	9.217	35.039	.000	18.25	2.18	168.207	76.447	244.654
12-10	268.0	786.135	363.532	.000	8.721	32.599	.000	18.25	2.17	159.142	70.767	229.909
12-11	264.7	721.556	335.729	.000	8.060	30.406	.000	18.23	2.17	146.960	65.894	212.854
12-12	250.6	642.211	298.953	.000	6.682	26.379	.000	18.28	2.30	122.130	60.631	182.761
12-13	244.3	586.224	260.122	.000	5.808	22.799	.000	18.34	2.41	106.518	54.950	161.468
S TOT	1.0	12053.760	5993.411	.000	130.465	539.058	.000	18.18	2.15	2371.681	1158.244	3529.925
AFTER	1.0	1818.962	1119.025	.000	52.730	147.441	.000	18.54	2.31	977.780	340.646	1318.426
TOTAL	1.0	13872.720	7112.436	.000	183.194	686.499	.000	18.28	2.18	3349.462	1498.890	4848.351

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	16.654	12.105	9.903	153.613	275.653	6.49	.000	275.653	275.653	263.192
12-03	15.195	11.118	8.950	147.557	243.828	6.77	.000	243.828	519.481	474.814
12-04	13.647	9.915	8.103	134.198	217.356	6.84	.000	217.356	736.837	646.303
12-05	12.796	9.193	7.561	134.198	194.179	7.23	.000	194.179	931.016	785.580
12-06	11.203	8.153	6.822	117.285	173.741	7.19	.000	173.741	1104.758	898.864
12-07	10.238	7.125	6.068	105.448	156.173	7.26	.000	156.173	1260.930	991.434
12-08	9.390	6.363	5.573	98.737	140.239	7.49	.000	140.239	1401.170	1067.004
12-09	8.874	5.906	5.239	98.586	126.048	7.88	.000	126.048	1527.218	1128.752
12-10	8.393	5.470	4.926	98.133	112.987	8.26	.000	112.987	1640.205	1179.071
12-11	7.771	5.094	4.536	94.971	100.481	8.56	.000	100.481	1740.686	1219.755
12-12	6.411	4.686	3.912	78.443	89.309	8.44	.000	89.309	1829.996	1252.626
12-13	5.568	4.250	3.459	72.047	76.144	8.88	.000	76.144	1906.140	1278.108
S TOT	126.139	89.377	75.052	1333.218	1906.140	1.35	.000	1906.140	1906.140	1278.108
AFTER	50.237	26.597	28.388	768.151	445.053	1.35	.000	445.053	2351.192	1372.839
TOTAL	176.377	115.973	103.441	2101.369	2351.193	1.35	.000	2351.193	2351.192	1372.839

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	277.0	26.0	LIFE, YRS.	38.42	8.00	1497.283
GROSS ULT., MB & MMF	139189.500	64015.920	DISCOUNT %	10.00	10.00	1372.839
GROSS CUM., MB & MMF	125316.800	56903.480	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1268.288
GROSS RES., MB & MMF	13872.720	7112.437	DISCOUNTED PAYOUT, YRS.	.00	15.00	1139.786
NET RES., MB & MMF	183.194	686.499	UNDISCOUNTED NET/INVEST.	.00	20.00	978.629
NET REVENUE, M$	3349.462	1498.890	DISCOUNTED NET/INVEST.	.00	25.00	861.060
INITIAL PRICE, $	17.164	1.799	RATE-OF-RETURN, PCT.	100.00	35.00	701.477
INITIAL N.I., PCT.	1.234	11.203	INITIAL W.I., PCT.	2.057	50.00	559.282
					70.00	450.768
					100.00	360.160

SWR INST INCOME FUND IX-B	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	18:38:24
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.7	8.966	831.352	.000	.221	21.056	.000	19.84	2.90	4.394	61.062	65.456
12-03	2.2	7.505	480.222	.000	.198	12.148	.000	19.18	2.88	3.796	35.030	38.827
12-04	5.5	71.929	411.424	.000	.986	9.343	.000	18.51	2.72	18.247	25.386	43.633
12-05	6.0	54.928	308.540	.000	.698	6.904	.000	18.57	2.74	12.966	18.900	31.866
12-06	6.0	39.279	243.025	.000	.518	5.470	.000	18.55	2.74	9.605	15.004	24.609
12-07	6.0	30.964	201.816	.000	.417	4.544	.000	18.53	2.74	7.730	12.470	20.200
12-08	6.0	25.772	173.258	.000	.353	3.895	.000	18.52	2.74	6.537	10.683	17.220
12-09	6.0	22.185	152.177	.000	.307	3.411	.000	18.51	2.74	5.688	9.352	15.040
12-10	6.0	19.504	135.853	.000	.270	3.032	.000	18.50	2.74	5.005	8.315	13.320
12-11	6.0	17.402	122.788	.000	.240	2.727	.000	18.50	2.74	4.439	7.484	11.924
12-12	6.0	15.684	112.021	.000	.214	2.475	.000	18.51	2.75	3.960	6.802	10.762
12-13	4.8	9.513	95.935	.000	.162	2.219	.000	18.39	2.75	2.981	6.105	9.085
S TOT	1.0	323.630	3268.411	.000	4.585	77.224	.000	18.61	2.80	85.347	216.594	301.941
AFTER	1.0	24.797	823.376	.000	.602	20.539	.000	18.63	2.85	11.210	58.472	69.682
TOTAL	1.0	348.426	4091.787	.000	5.187	97.763	.000	18.62	2.81	96.557	275.066	371.623

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.202	4.580	1.820	1.453	57.401	2.16	.000	57.401	57.401	54.901
12-03	.205	2.628	1.053	1.759	33.181	2.54	.000	33.181	90.582	83.745
12-04	1.097	1.912	.989	3.022	36.613	2.76	.000	36.613	127.194	112.653
12-05	.766	1.423	.739	3.112	25.826	3.27	.000	25.826	153.020	131.210
12-06	.573	1.129	.570	3.112	19.224	3.77	.000	19.224	172.245	143.759
12-07	.464	.939	.467	3.112	15.218	4.24	.000	15.218	187.463	152.787
12-08	.394	.804	.397	3.112	12.513	4.70	.000	12.513	199.976	159.534
12-09	.345	.704	.345	3.112	10.534	5.14	.000	10.534	210.510	164.696
12-10	.304	.626	.306	3.112	8.973	5.60	.000	8.973	219.483	168.694
12-11	.270	.564	.274	3.112	7.705	6.08	.000	7.705	227.188	171.815
12-12	.240	.512	.248	3.112	6.650	6.56	.000	6.650	233.838	174.263
12-13	.189	.460	.206	2.902	5.329	7.06	.000	5.329	239.167	176.049
S TOT	5.049	16.281	7.415	34.029	239.167	17.10	.000	239.167	239.167	176.049
AFTER	.685	4.391	1.785	34.605	28.215	17.10	.000	28.215	267.382	181.948
TOTAL	5.735	20.672	9.200	68.634	267.382	17.10	.000	267.382	267.382	181.948

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	4.0	2.0	LIFE, YRS.	32.00	8.00	193.602
GROSS ULT., MB & MMF	353.809	4189.063	DISCOUNT %	10.00	10.00	181.948
GROSS CUM., MB & MMF	5.383	97.276	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	171.884
GROSS RES., MB & MMF	348.426	4091.787	DISCOUNTED PAYOUT, YRS.	.00	15.00	159.109
NET RES., MB & MMF	5.187	97.763	UNDISCOUNTED NET/INVEST.	.00	20.00	142.323
NET REVENUE, M$	96.557	275.066	DISCOUNTED NET/INVEST.	.00	25.00	129.418
INITIAL PRICE, $	19.056	2.854	RATE-OF-RETURN, PCT.	100.00	35.00	110.785
INITIAL N.I., PCT.	1.369	2.419	INITIAL W.I., PCT.	2.475	50.00	92.833
					70.00	78.073
					100.00	64.910

SWR INST INCOME FUND IX-B	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	18:38:24
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IF9B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	287.8	1549.161	1667.969	.000	17.442	95.565	.000	18.08	2.28	315.310	218.074	533.385
12-03	285.4	1420.249	1216.921	.000	15.815	80.366	.000	18.11	2.23	286.328	179.146	465.474
12-04	286.5	1369.121	1081.294	.000	15.016	70.702	.000	18.17	2.18	272.825	154.026	426.852
12-05	285.0	1244.576	922.203	.000	13.854	63.865	.000	18.16	2.16	251.658	138.135	389.793
12-06	282.5	1132.506	801.782	.000	12.146	55.457	.000	18.19	2.18	220.971	120.842	341.813
12-07	278.8	1036.694	702.785	.000	10.993	47.629	.000	18.23	2.20	200.448	104.805	305.252
12-08	275.2	951.608	600.148	.000	10.101	41.612	.000	18.26	2.24	184.458	93.062	277.521
12-09	274.8	875.245	543.787	.000	9.524	38.450	.000	18.26	2.23	173.894	85.799	259.693
12-10	274.0	805.638	499.385	.000	8.991	35.631	.000	18.26	2.22	164.147	79.083	243.229
12-11	270.7	738.957	458.517	.000	8.300	33.133	.000	18.24	2.21	151.400	73.378	224.778
12-12	256.6	657.894	410.974	.000	6.896	28.854	.000	18.28	2.34	126.090	67.433	193.523
12-13	249.2	595.737	356.057	.000	5.970	25.018	.000	18.34	2.44	109.498	61.055	170.553
S TOT	1.0	12377.390	9261.821	.000	135.050	616.282	.000	18.19	2.23	2457.028	1374.839	3831.867
AFTER	1.0	1843.759	1942.401	.000	53.331	167.980	.000	18.54	2.38	988.990	399.118	1388.108
TOTAL	1.0	14221.140	11204.220	.000	188.381	784.262	.000	18.29	2.26	3446.019	1773.956	5219.975

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	16.856	16.685	11.723	155.066	333.054	6.00	.000	333.054	333.054	318.093
12-03	15.399	13.746	10.004	149.316	277.009	6.45	.000	277.009	610.063	558.559
12-04	14.744	11.827	9.093	137.220	253.968	6.45	.000	253.968	864.031	758.956
12-05	13.562	10.616	8.300	137.310	220.005	6.93	.000	220.005	1084.036	916.790
12-06	11.776	9.282	7.392	120.397	192.966	6.96	.000	192.966	1277.002	1042.623
12-07	10.702	8.064	6.535	108.560	171.391	7.07	.000	171.391	1448.393	1144.221
12-08	9.784	7.167	5.969	101.849	152.752	7.32	.000	152.752	1601.145	1226.537
12-09	9.219	6.610	5.584	101.698	136.582	7.73	.000	136.582	1737.728	1293.448
12-10	8.696	6.096	5.232	101.245	121.960	8.12	.000	121.960	1859.688	1347.765
12-11	8.041	5.658	4.810	98.083	108.186	8.44	.000	108.186	1967.874	1391.569
12-12	6.651	5.198	4.160	81.554	95.959	8.34	.000	95.959	2063.834	1426.889
12-13	5.757	4.709	3.665	74.949	81.473	8.79	.000	81.473	2145.307	1454.157
S TOT	131.189	105.657	82.467	1367.247	2145.307	1.35	.000	2145.307	2145.307	1454.157
AFTER	50.923	30.988	30.174	802.756	473.268	1.35	.000	473.268	2618.575	1554.787
TOTAL	182.111	136.645	112.641	2170.004	2618.575	1.35	.000	2618.575	2618.575	1554.787

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	281.0	28.0	LIFE, YRS.	38.42	8.00	1690.885
GROSS ULT., MB & MMF	139543.300	68204.980	DISCOUNT %	10.00	10.00	1554.787
GROSS CUM., MB & MMF	125322.200	57000.760	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1440.172
GROSS RES., MB & MMF	14221.140	11204.220	DISCOUNTED PAYOUT, YRS.	.00	15.00	1298.895
NET RES., MB & MMF	188.381	784.262	UNDISCOUNTED NET/INVEST.	.00	20.00	1120.952
NET REVENUE, M$	3446.019	1773.956	DISCOUNTED NET/INVEST.	.00	25.00	990.478
INITIAL PRICE, $	17.302	2.438	RATE-OF-RETURN, PCT.	100.00	35.00	812.262
INITIAL N.I., PCT.	1.244	5.877	INITIAL W.I., PCT.	2.136	50.00	652.115
					70.00	528.841
					100.00	425.070

APPENDIX B10

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund X-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 12 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 86.3 percent of the total net remaining liquid hydrocarbon reserves and 90.4 percent of the total net remaining gas reserves. The properties that we reviewed represent 87.3 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund X-A

As of January 1, 2002

	Proved
	Developed
	Producing		Non-Producing		Undeveloped		Total Proved
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		107,489		709		3,180		111,378
Gas—MMCF		87		4		13		104
Income Data
Future Gross Revenue	$	1,878,569	$	20,736	$	85,399	$	1,984,704
Deductions		1,063,761		2,653		15,720		1,082,134
Future Net Income (FNI)	$	814,808	$	18,083	$	69,679	$	902,570
Discounted FNI @ 10%	$	448,021	$	13,672	$	43,797	$	505,490

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed
	Producing		Non-Producing		Undeveloped		Total Proved
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		17,618		0		0		17,618
Gas—MMCF		11		0		0		11
Income Data
Future Gross Revenue	$	311,594	$	0	$	0	$	311,594
Deductions		173,634		0		0		173,634
Future Net Income (FNI)	$	137,960	$	0	$	0	$	137,960
Discounted FN1 @ 10%	$	73,236	$	0	$	0	$	73,236
Total Net Reserves
Oil/Condensate—Barrels		125,107		709		3,180		128,996
Gas—MMCF		98		4		13		115
Income Data
Future Gross Revenue	$	2,190,163	$	20,736	$	85,399	$	2,296,298
Deductions		1,237,395		2,653		15,720		1,255,768
Future Net Income (FNI)	$	952,768	$	18,083	$	69,679	$	1,040,530
Discounted FNI @ 10%	$	521,257	$	13,672	$	43,797	$	578,726

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 13.7 percent of the total net remaining liquid hydrocarbon reserves and 9.6 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:23
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	90.7	136.711	264.321	.000	9.440	10.419	.000	16.88	2.44	159.311	25.399	184.710
12-03	79.1	127.726	291.436	.000	8.837	11.618	.000	16.80	2.43	148.444	28.211	176.654
12-04	67.0	111.425	270.549	.000	8.228	10.896	.000	16.76	2.44	137.907	26.574	164.482
12-05	66.3	100.884	239.717	.000	7.726	9.541	.000	16.73	2.43	129.266	23.177	152.443
12-06	63.8	87.613	217.389	.000	7.202	8.581	.000	16.69	2.42	120.237	20.786	141.023
12-07	53.9	61.774	198.597	.000	6.521	7.847	.000	16.63	2.42	108.434	18.963	127.397
12-08	51.3	53.855	177.544	.000	6.162	6.948	.000	16.60	2.40	102.291	16.708	118.999
12-09	49.9	49.171	161.155	.000	5.810	6.208	.000	16.59	2.41	96.385	14.956	111.341
12-10	48.1	45.349	148.404	.000	5.533	5.700	.000	16.58	2.41	91.722	13.729	105.450
12-11	47.0	41.861	137.819	.000	5.286	5.235	.000	16.57	2.41	87.562	12.599	100.161
12-12	46.0	39.352	126.478	.000	5.062	4.702	.000	16.56	2.41	83.814	11.314	95.128
12-13	46.0	37.315	118.433	.000	4.853	4.367	.000	16.55	2.40	80.327	10.498	90.825
S TOT	1.4	893.034	2351.841	.000	80.661	92.062	.000	16.68	2.42	1345.700	222.913	1568.613
AFTER	1.4	293.746	896.305	.000	48.335	23.143	.000	16.48	2.31	796.776	53.494	850.270
TOTAL	1.4	1186.781	3248.147	.000	128.995	115.205	.000	16.61	2.40	2142.476	276.407	2418.883

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	7.857	1.977	4.489	75.143	95.244	8.00	.000	95.244	95.244	90.898
12-03	7.191	2.180	4.428	61.184	101.671	6.96	.000	101.671	196.915	178.960
12-04	6.563	2.051	4.229	56.708	94.931	6.92	.000	94.931	291.847	253.871
12-05	6.148	1.791	3.927	56.478	84.099	7.34	.000	84.099	375.946	314.192
12-06	5.717	1.608	3.645	54.500	75.553	7.58	.000	75.553	451.498	363.452
12-07	5.160	1.467	3.314	48.910	68.546	7.52	.000	68.546	520.045	404.079
12-08	4.865	1.294	3.101	48.660	61.079	7.91	.000	61.079	581.124	436.998
12-09	4.559	1.159	2.927	47.498	55.198	8.20	.000	55.198	636.322	464.035
12-10	4.327	1.064	2.786	46.965	50.308	8.51	.000	50.308	686.630	486.437
12-11	4.128	.976	2.658	46.830	45.569	8.86	.000	45.569	732.200	504.885
12-12	3.948	.877	2.532	46.476	41.295	9.21	.000	41.295	773.495	520.083
12-13	3.781	.814	2.423	46.476	37.331	9.59	.000	37.331	810.826	532.573
S TOT	64.241	17.259	40.459	635.827	810.826	2.77	.000	810.826	810.826	532.573
AFTER	36.968	4.116	23.650	555.832	229.705	2.77	.000	229.705	1040.531	578.725
TOTAL	101.209	21.374	64.108	1191.659	1040.531	2.77	.000	1040.531	1040.531	578.725

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	131.0	31.0	LIFE, YRS.	59.08	8.00	635.389
GROSS ULT. MB & MMF	26116.520	48808.020	DISCOUNT %	10.00	10.00	578.725
GROSS CUM., MB & MMF	24929.740	45559.870	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	531.504
GROSS RES., MB & MMF	1186.781	3248.147	DISCOUNTED PAYOUT, YRS.	.00	15.00	473.923
NET RES., MB & MMF	128.995	115.205	UNDISCOUNTED NET/INVEST.	.00	20.00	402.405
NET REVENUE, M$	2142.475	276.407	DISCOUNTED NET/INVEST.	.00	25.00	350.725
INITIAL PRICE, $	17.504	2.371	RATE-OF-RETURN, PCT.	100.00	35.00	281.295
INITIAL N.I., PCT.	6.752	3.981	INITIAL W.I., PCT.	7.224	50.00	220.232
					70.00	174.272
					100.00	136.473

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:23
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	90.6	136.264	262.088	.000	9.419	10.314	.000	16.87	2.44	158.930	25.125	184.055
12-03	77.5	114.553	234.431	.000	8.209	8.901	.000	16.70	2.38	137.089	21.146	158.235
12-04	65.0	97.470	211.563	.000	7.561	8.080	.000	16.65	2.38	125.862	19.253	145.115
12-05	64.3	90.310	194.876	.000	7.221	7.401	.000	16.64	2.38	120.140	17.612	137.753
12-06	61.8	78.969	180.667	.000	6.789	6.829	.000	16.61	2.38	112.778	16.229	129.008
12-07	51.9	54.401	167.233	.000	6.169	6.350	.000	16.55	2.37	102.072	15.071	117.143
12-08	50.0	48.543	155.787	.000	5.907	5.907	.000	16.54	2.37	97.697	14.001	111.698
12-09	48.9	44.893	144.041	.000	5.605	5.388	.000	16.53	2.38	92.680	12.823	105.504
12-10	47.1	41.479	132.925	.000	5.347	4.958	.000	16.53	2.38	88.371	11.800	100.170
12-11	46.0	38.320	123.655	.000	5.116	4.556	.000	16.52	2.38	84.496	10.834	95.330
12-12	45.0	36.094	113.448	.000	4.906	4.077	.000	16.51	2.38	80.993	9.691	90.684
12-13	45.0	34.318	106.446	.000	4.709	3.792	.000	16.51	2.37	77.732	9.004	86.736
S TOT	1.4	815.614	2027.160	.000	76.960	76.553	.000	16.62	2.39	1278.839	182.590	1461.429
AFTER	1.4	289.822	880.607	.000	48.146	22.391	.000	16.48	2.30	793.377	51.538	844.915
TOTAL	1.4	1105.435	2907.766	.000	125.107	98.943	.000	16.56	2.37	2072.216	234.128	2306.345

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	7.839	1.957	4.470	75.112	94.676	8.02	.000	94.676	94.676	90.380
12-03	6.668	1.651	3.907	60.174	85.835	7.47	.000	85.835	180.512	164.862
12-04	6.009	1.502	3.681	55.244	78.679	7.46	.000	78.679	259.191	226.926
12-05	5.728	1.374	3.511	55.014	72.126	7.76	.000	72.126	331.316	278.648
12-06	5.374	1.266	3.306	53.036	66.027	7.94	.000	66.027	397.343	321.692
12-07	4.867	1.175	3.024	47.446	60.631	7.82	.000	60.631	457.975	357.625
12-08	4.653	1.091	2.894	47.446	55.614	8.14	.000	55.614	513.588	387.588
12-09	4.388	.999	2.762	46.409	50.945	8.39	.000	50.945	564.533	412.542
12-10	4.173	.919	2.637	45.876	46.566	8.68	.000	46.566	611.099	433.276
12-11	3.987	.844	2.521	45.741	42.237	9.04	.000	42.237	653.336	450.376
12-12	3.818	.756	2.406	45.387	38.317	9.38	.000	38.317	691.653	464.477
12-13	3.661	.702	2.307	45.387	34.678	9.75	.000	34.678	726.331	476.080
S TOT	61.166	14.235	37.426	622.271	726.331	2.77	.000	726.331	726.331	476.080
AFTER	36.812	3.969	23.498	554.198	226.438	2.77	.000	226.438	952.770	521.257
TOTAL	97.978	18.203	60.924	1176.470	952.770	2.77	.000	952.770	952.770	521.257

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	129.0	31.0	LIFE, YRS.	59.08	8.00	573.405
GROSS ULT. MB & MMF	26035.180	48443.830	DISCOUNT %	10.00	10.00	521.257
GROSS CUM., MB & MMF	24929.740	45536.060	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	478.022
GROSS RES., MB & MMF	1105.435	2907.767	DISCOUNTED PAYOUT, YRS.	.00	15.00	425.604
NET RES., MB & MMF	125.107	98.943	UNDISCOUNTED NET/INVEST.	.00	20.00	361.007
NET REVENUE, M$	2072.216	234.128	DISCOUNTED NET/INVEST.	.00	25.00	314.710
INITIAL PRICE, $	17.438	2.312	RATE-OF-RETURN, PCT.	100.00	35.00	253.050
INITIAL N.I., PCT.	6.984	3.777	INITIAL W.I., PCT.	7.398	50.00	199.323
					70.00	159.134
					100.00	126.130

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:23
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.447	2.233	.000	.021	.105	.000	18.07	2.60	.381	.274	.655
12-03	1.0	4.311	21.553	.000	.204	1.018	.000	18.07	2.60	3.680	2.647	6.327
12-04	1.0	3.167	15.836	.000	.150	.748	.000	18.07	2.60	2.704	1.945	4.649
12-05	1.0	2.546	12.730	.000	.120	.601	.000	18.07	2.60	2.173	1.564	3.737
12-06	1.0	2.149	10.745	.000	.102	.508	.000	18.07	2.60	1.834	1.320	3.154
12-07	1.0	1.871	9.354	.000	.088	.442	.000	18.07	2.60	1.597	1.149	2.746
12-08	1.0	.510	2.548	.000	.024	.120	.000	18.07	2.60	.435	.313	.748
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.018	.021	.019	.031	.568	2.27	.000	.568	.568	.518
12-03	.169	.199	.179	.375	5.405	2.47	.000	5.405	5.973	5.220
12-04	.124	.146	.131	.375	3.872	2.83	.000	3.872	9.845	8.279
12-05	.100	.117	.106	.375	3.039	3.16	.000	3.039	12.884	10.460
12-06	.084	.099	.089	.375	2.507	3.48	.000	2.507	15.391	12.096
12-07	.073	.086	.078	.375	2.134	3.78	.000	2.134	17.524	13.361
12-08	.020	.023	.021	.125	.558	4.30	.000	.558	18.083	13.672
12-09
12-10
12-11
12-12
12-13
S TOT	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672
AFTER	.000	.000	.000	.000	.000	4.30	.000	.000	18.083	13.672
TOTAL	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	6.33	8.00	14.405
GROSS ULT. MB & MMF	15.000	98.806	DISCOUNT %	10.00	10.00	13.672
GROSS CUM., MB & MMF	.000	23.806	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	12.997
GROSS RES., MB & MMF	15.000	75.000	DISCOUNTED PAYOUT, YRS.	.00	15.00	12.083
NET RES., MB & MMF	.709	3.543	UNDISCOUNTED NET/INVEST.	.00	20.00	10.776
NET REVENUE, M$	12.804	9.212	DISCOUNTED NET/INVEST.	.00	25.00	9.688
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	7.995
INITIAL N.I., PCT.	4.724	4.724	INITIAL W.I., PCT.	6.250	50.00	6.248
					70.00	4.762
					100.00	3.443

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:23
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.6	8.863	35.452	.000	.425	1.699	.000	18.07	2.60	7.675	4.417	12.093
12-04	1.0	10.787	43.150	.000	.517	2.068	.000	18.07	2.60	9.342	5.377	14.718
12-05	1.0	8.028	32.111	.000	.385	1.539	.000	18.07	2.60	6.952	4.001	10.953
12-06	1.0	6.494	25.977	.000	.311	1.245	.000	18.07	2.60	5.624	3.237	8.861
12-07	1.0	5.503	22.010	.000	.264	1.055	.000	18.07	2.60	4.765	2.743	7.508
12-08	1.0	4.802	19.209	.000	.230	.921	.000	18.07	2.60	4.159	2.394	6.552
12-09	1.0	4.278	17.113	.000	.205	.820	.000	18.07	2.60	3.705	2.132	5.837
12-10	1.0	3.870	15.479	.000	.185	.742	.000	18.07	2.60	3.351	1.929	5.280
12-11	1.0	3.541	14.163	.000	.170	.679	.000	18.07	2.60	3.066	1.765	4.831
12-12	1.0	3.258	13.030	.000	.156	.624	.000	18.07	2.60	2.821	1.624	4.445
12-13	1.0	2.997	11.988	.000	.144	.575	.000	18.07	2.60	2.595	1.494	4.089
S TOT	1.0	62.420	249.682	.000	2.991	11.966	.000	18.07	2.60	54.056	31.111	85.167
AFTER	1.0	3.925	15.699	.000	.188	.752	.000	18.07	2.60	3.399	1.956	5.355
TOTAL	1.0	66.345	265.381	.000	3.180	12.718	.000	18.07	2.60	57.455	33.067	90.522

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.353	.331	.342	.635	10.431	2.35	.000	10.431	10.431	8.878
12-04	.430	.403	.417	1.089	12.380	2.71	.000	12.380	22.811	18.667
12-05	.320	.300	.310	1.089	8.934	3.15	.000	8.934	31.745	25.083
12-06	.259	.243	.251	1.089	7.020	3.55	.000	7.020	38.765	29.664
12-07	.219	.206	.212	1.089	5.781	3.93	.000	5.781	44.546	33.093
12-08	.191	.180	.185	1.089	4.907	4.29	.000	4.907	49.453	35.738
12-09	.170	.160	.165	1.089	4.253	4.64	.000	4.253	53.706	37.822
12-10	.154	.145	.149	1.089	3.743	4.97	.000	3.743	57.449	39.489
12-11	.141	.132	.137	1.089	3.332	5.30	.000	3.332	60.781	40.838
12-12	.130	.122	.126	1.089	2.978	5.64	.000	2.978	63.759	41.934
12-13	.119	.112	.116	1.089	2.653	6.00	.000	2.653	66.412	42.822
S TOT	2.487	2.333	2.410	11.525	66.412	7.29	.000	66.412	66.412	42.822
AFTER	.156	.147	.152	1.633	3.267	7.29	.000	3.267	69.679	43.797
TOTAL	2.643	2.480	2.562	13.158	69.679	7.29	.000	69.679	69.679	43.797

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	13.50	8.00	47.579
GROSS ULT. MB & MMF	66.345	265.381	DISCOUNT %	10.00	10.00	43.797
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	40.485
GROSS RES., MB & MMF	66.345	265.381	DISCOUNTED PAYOUT, YRS.	.00	15.00	36.237
NET RES., MB & MMF	3.180	12.718	UNDISCOUNTED NET/INVEST.	.00	20.00	30.623
NET REVENUE, M$	53.455	33.067	DISCOUNTED NET/INVEST.	.00	25.00	26.327
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	20.250
INITIAL N.I., PCT.	4.792	4.792	INITIAL W.I., PCT.	6.050	50.00	14.661
					70.00	10.377
					100.00	6.900

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	08:59:46
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	18.1	52.342	62.721	.000	7.026	8.195	.000	16.62	2.38	116.790	19.523	136.313
12-03	19.6	61.396	113.318	.000	7.317	10.215	.000	16.74	2.44	122.450	24.889	147.339
12-04	20.0	59.794	111.508	.000	7.054	9.776	.000	16.74	2.44	118.099	23.848	141.946
12-05	20.0	53.685	93.850	.000	6.606	8.601	.000	16.71	2.43	110.393	20.890	131.284
12-06	17.8	44.074	82.469	.000	6.131	7.752	.000	16.67	2.42	102.199	18.771	120.970
12-07	11.0	25.870	74.079	.000	5.494	7.068	.000	16.59	2.42	91.161	17.077	108.238
12-08	10.3	22.869	61.655	.000	5.179	6.215	.000	16.56	2.40	85.790	14.939	100.729
12-09	10.0	20.955	54.391	.000	4.923	5.627	.000	16.55	2.40	81.469	13.482	94.951
12-10	9.1	19.226	49.448	.000	4.698	5.193	.000	16.54	2.39	77.694	12.419	90.112
12-11	9.0	18.142	45.896	.000	4.495	4.814	.000	16.53	2.39	74.297	11.499	85.796
12-12	9.0	17.190	42.752	.000	4.302	4.468	.000	16.53	2.39	71.097	10.661	81.758
12-13	9.0	16.298	39.833	.000	4.119	4.147	.000	16.52	2.38	68.052	9.885	77.937
S TOT	1.0	412.382	831.920	.000	67.345	82.072	.000	16.62	2.41	1119.491	197.883	1317.374
AFTER	1.0	140.996	258.256	.000	44.032	21.656	.000	16.42	2.28	723.101	49.484	772.585
TOTAL	1.0	553.378	1090.176	.000	111.377	103.728	.000	16.54	2.38	1842.592	247.366	2089.959

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	5.516	1.527	3.486	45.573	80.212	6.69	.000	80.212	80.212	76.532
12-03	5.764	1.924	3.828	46.552	89.270	6.44	.000	89.270	169.482	153.830
12-04	5.554	1.842	3.703	47.006	83.842	6.69	.000	83.842	253.325	219.993
12-05	5.189	1.616	3.427	47.006	74.046	7.12	.000	74.046	327.371	273.103
12-06	4.803	1.453	3.168	45.142	66.404	7.35	.000	66.404	393.775	316.399
12-07	4.287	1.322	2.854	39.552	60.222	7.20	.000	60.222	453.997	352.092
12-08	4.032	1.158	2.660	39.302	53.576	7.59	.000	53.576	507.573	380.969
12-09	3.827	1.046	2.512	39.177	48.389	7.94	.000	48.389	555.962	404.670
12-10	3.646	.964	2.390	38.990	44.122	8.27	.000	44.122	600.084	424.317
12-11	3.484	.892	2.282	38.973	40.165	8.61	.000	40.165	640.249	440.577
12-12	3.332	.827	2.180	38.973	36.447	8.98	.000	36.447	676.696	453.990
12-13	3.187	.767	2.084	38.973	32.928	9.36	.000	32.928	709.624	465.007
S TOT	52.621	15.337	34.574	505.218	709.624	9.37	.000	709.624	709.624	465.007
AFTER	33.485	3.811	21.519	520.823	192.947	9.37	.000	192.947	902.571	505.490
TOTAL	86.105	19.148	56.093	1026.042	902.570	9.37	.000	902.570	902.571	505.490

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	20..0	1.0	LIFE, YRS.	59.08	8.00	555.057
GROSS ULT., MB & MMF	9163.523	4807.131	DISCOUNT %	10.00	10.00	505.490
GROSS CUM., MB & MMF	8610.145	3716.955	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	464.092
GROSS RES., MB & MMF	553.378	1090.176	DISCOUNTED PAYOUT, YRS.	.00	15.00	413.538
NET RES., MB & MMF	111.377	103.728	UNDISCOUNTED NET/INVEST.	.00	20.00	350.691
NET REVENUE, M$	1842.592	247.366	DISCOUNTED NET/INVEST.	.00	25.00	305.269
INITIAL PRICE, $	17.587	2.513	RATE-OF-RETURN, PCT.	100.00	35.00	244.272
INITIAL N.I., PCT.	10.676	8.126	INITIAL W.I., PCT.	12.346	50.00	190.673
					70.00	150.377
					100.00	117.290

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	08:59:46
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	18.0	51.896	60.488	.000	7.005	8.090	.000	16.62	2.38	116.409	19.249	135.658
12-03	18.0	48.763	56.314	.000	6.688	7.498	.000	16.61	2.38	111.095	17.825	128.920
12-04	18.0	45.840	52.522	.000	6.387	6.959	.000	16.60	2.37	106.053	16.526	122.579
12-05	18.0	43.112	49.009	.000	6.101	6.461	.000	16.60	2.37	101.268	15.326	116.594
12-06	15.8	35.431	45.747	.000	5.718	5.999	.000	16.57	2.37	94.741	14.214	108.955
12-07	9.0	18.497	42.715	.000	5.142	5.571	.000	16.49	2.37	84.799	13.185	97.984
12-08	9.0	17.557	39.898	.000	4.925	5.174	.000	16.49	2.36	81.196	12.233	93.428
12-09	9.0	16.677	37.277	.000	4.718	4.807	.000	16.48	2.36	77.764	11.350	89.114
12-10	8.1	15.357	33.970	.000	4.513	4.451	.000	16.47	2.36	74.343	10.490	84.833
12-11	8.0	14.601	31.732	.000	4.325	4.135	.000	16.47	2.35	71.231	9.734	80.965
12-12	8.0	13.932	29.722	.000	4.146	3.844	.000	16.47	2.35	68.276	9.037	77.313
12-13	8.0	13.301	27.845	.000	3.976	3.573	.000	16.46	2.35	65.457	8.391	73.848
S TOT	1.0	334.962	507.238	.000	63.645	66.563	.000	16.54	2.37	1052.631	157.560	1210.190
AFTER	1.0	137.071	242.557	.000	43.844	20.904	.000	16.42	2.27	719.703	47.527	767.230
TOTAL	1.0	472.033	749.796	.000	107.489	87.467	.000	16.49	2.34	1772.333	205.087	1977.420

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	5.498	1.506	3.467	45.542	79.644	6.71	.000	79.644	79.644	76.014
12-03	5.242	1.394	3.307	45.542	73.434	6.99	.000	73.434	153.079	139.731
12-04	4.999	1.292	3.155	45.542	67.590	7.29	.000	67.590	220.669	193.047
12-05	4.769	1.198	3.012	45.542	62.073	7.60	.000	62.073	282.742	237.560
12-06	4.460	1.111	2.828	43.678	56.878	7.75	.000	56.878	339.619	274.639
12-07	3.994	1.030	2.564	38.088	52.307	7.52	.000	52.307	391.926	305.638
12-08	3.821	.955	2.453	38.088	48.111	7.83	.000	48.111	440.037	331.559
12-09	3.656	.886	2.347	38.088	44.136	8.15	.000	44.136	484.173	353.177
12-10	3.492	.819	2.241	37.901	40.380	8.46	.000	40.380	524.553	371.157
12-11	3.343	.760	2.145	37.884	36.833	8.80	.000	36.833	561.386	386.067
12-12	3.202	.705	2.054	37.884	33.468	9.16	.000	33.468	594.854	398.384
12-13	3.067	.654	1.968	37.884	30.275	9.53	.000	30.275	625.129	408.514
S TOT	49.545	12.312	31.542	491.662	625.129	9.37	.000	625.129	625.129	408.514
AFTER	33.328	3.665	21.367	519.190	189.680	9.37	.000	189.680	814.809	448.021
TOTAL	82.874	15.977	52.909	1010.852	814.809	9.37	.000	814.809	814.809	448.021

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	18.0	1.0	LIFE, YRS.	59.08	8.00	493.073
GROSS ULT., MB & MMF	9082.178	4442.178	DISCOUNT %	10.00	10.00	448.021
GROSS CUM., MB & MMF	8610.145	3693.149	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	410.610
GROSS RES., MB & MMF	472.033	749.796	DISCOUNTED PAYOUT, YRS.	.00	15.00	365.219
NET RES., MB & MMF	107.489	87.467	UNDISCOUNTED NET/INVEST.	.00	20.00	309.292
NET REVENUE, M$	1772.333	205.087	DISCOUNTED NET/INVEST.	.00	25.00	269.254
INITIAL PRICE, $	17.388	2.383	RATE-OF-RETURN, PCT.	100.00	35.00	216.027
INITIAL N.I., PCT.	13.097	13.115	INITIAL W.I, PCT.	16.042	50.00	169.764
					70.00	135.238
					100.00	106.947

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	08:59:46
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.447	2.233	.000	.021	.105	.000	18.07	2.60	.381	.274	.655
12-03	1.0	4.311	21.553	.000	.204	1.018	.000	18.07	2.60	3.680	2.647	6.327
12-04	1.0	3.167	15.836	.000	.150	.748	.000	18.07	2.60	2.704	1.945	4.649
12-05	1.0	2.546	12.730	.000	.120	.601	.000	18.07	2.60	2.173	1.564	3.737
12-06	1.0	2.149	10.745	.000	.102	.508	.000	18.07	2.60	1.834	1.320	3.154
12-07	1.0	1.871	9.354	.000	.088	.442	.000	18.07	2.60	1.597	1.149	2.746
12-08	1.0	.510	2.548	.000	.024	.120	.000	18.07	2.60	.435	.313	.748
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.018	.021	.019	.031	.568	2.27	.000	.568	.568	.518
12-03	.169	.199	.179	.375	5.405	2.47	.000	5.405	5.973	5.220
12-04	.124	.146	.131	.375	3.872	2.83	.000	3.872	9.845	8.279
12-05	.100	.117	.106	.375	3.039	3.16	.000	3.039	12.884	10.460
12-06	.084	.099	.089	.375	2.507	3.48	.000	2.507	15.391	12.096
12-07	.073	.086	.078	.375	2.134	3.78	.000	2.134	17.524	13.361
12-08	.020	.023	.021	.125	.558	4.30	.000	.558	18.083	13.672
12-09
12-10
12-11
12-12
12-13
S TOT	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672
AFTER	.000	.000	.000	.000	.000	4.30	.000	.000	18.083	13.672
TOTAL	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	6.33	8.00	14.405
GROSS ULT. MB & MMF	15.000	98.806	DISCOUNT %	10.00	10.00	13.672
GROSS CUM., MB & MMF	.000	23.806	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	12.997
GROSS RES., MB & MMF	15.000	75.000	DISCOUNTED PAYOUT, YRS.	.00	15.00	12.083
NET RES., MB & MMF	.709	3.543	UNDISCOUNTED NET/INVEST.	.00	20.00	10.776
NET REVENUE, M$	12.804	9.212	DISCOUNTED NET/INVEST.	.00	25.00	9.688
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	7.995
INITIAL N.I., PCT.	4.724	4.724	INITIAL W.I., PCT.	6.250	50.00	6.248
					70.00	4.762
					100.00	3.443

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	08:59:46
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.6	8.863	35.452	.000	.425	1.699	.000	18.07	2.60	7.675	4.417	12.093
12-04	1.0	10.787	43.150	.000	.517	2.068	.000	18.07	2.60	9.342	5.377	14.718
12-05	1.0	8.028	32.111	.000	.385	1.539	.000	18.07	2.60	6.952	4.001	10.953
12-06	1.0	6.494	25.977	.000	.311	1.245	.000	18.07	2.60	5.624	3.237	8.861
12-07	1.0	5.503	22.010	.000	.264	1.055	.000	18.07	2.60	4.765	2.743	7.508
12-08	1.0	4.802	19.209	.000	.230	.921	.000	18.07	2.60	4.159	2.394	6.552
12-09	1.0	4.278	17.113	.000	.205	.820	.000	18.07	2.60	3.705	2.132	5.837
12-10	1.0	3.870	15.479	.000	.185	.742	.000	18.07	2.60	3.351	1.929	5.280
12-11	1.0	3.541	14.163	.000	.170	.679	.000	18.07	2.60	3.066	1.765	4.831
12-12	1.0	3.258	13.030	.000	.156	.624	.000	18.07	2.60	2.821	1.624	4.445
12-13	1.0	2.997	11.988	.000	.144	.575	.000	18.07	2.60	2.595	1.494	4.089
S TOT	1.0	62.420	249.682	.000	2.991	11.966	.000	18.07	2.60	54.056	31.111	85.167
AFTER	1.0	3.925	15.699	.000	.188	.752	.000	18.07	2.60	3.399	1.956	5.355
TOTAL	1.0	66.345	265.381	.000	3.180	12.718	.000	18.07	2.60	57.455	33.067	90.522

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.353	.331	.342	.635	10.431	2.35	.000	10.431	10.431	8.878
12-04	.430	.403	.417	1.089	12.380	2.71	.000	12.380	22.811	18.667
12-05	.320	.300	.310	1.089	8.934	3.15	.000	8.934	31.745	25.083
12-06	.259	.243	.251	1.089	7.020	3.55	.000	7.020	38.765	29.664
12-07	.219	.206	.212	1.089	5.781	3.93	.000	5.781	44.546	33.093
12-08	.191	.180	.185	1.089	4.907	4.29	.000	4.907	49.453	35.738
12-09	.170	.160	.165	1.089	4.253	4.64	.000	4.253	53.706	37.822
12-10	.154	.145	.149	1.089	3.743	4.97	.000	3.743	57.449	39.489
12-11	.141	.132	.137	1.089	3.332	5.30	.000	3.332	60.781	40.838
12-12	.130	.122	.126	1.089	2.978	5.64	.000	2.978	63.759	41.934
12-13	.119	.112	.116	1.089	2.653	6.00	.000	2.653	66.412	42.822
S TOT	2.487	2.333	2.410	11.525	66.412	7.29	.000	66.412	66.412	42.822
AFTER	.156	.147	.152	1.633	3.267	7.29	.000	3.267	69.679	43.797
TOTAL	2.643	2.480	2.562	13.158	69.679	7.29	.000	69.679	69.679	43.797

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	13.50	8.00	47.579
GROSS ULT. MB & MMF	66.345	265.381	DISCOUNT %	10.00	10.00	43.797
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	40.485
GROSS RES., MB & MMF	66.345	265.381	DISCOUNTED PAYOUT, YRS.	.00	15.00	36.237
NET RES., MB & MMF	3.180	12.718	UNDISCOUNTED NET/INVEST.	.00	20.00	30.623
NET REVENUE, M$	57.455	33.067	DISCOUNTED NET/INVEST.	.00	25.00	26.327
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	20.250
INITIAL N.I., PCT.	4.792	4.792	INITIAL W.I., PCT.	6.050	50.00	14.661
					70.00	10.377
					100.00	6.900

SW OIL & GAS INCOME FUND X-A	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	09:16:00
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	72.6	84.369	201.600	.000	2.414	2.224	.000	17.61	2.64	42.521	5.876	48.397
12-03	59.5	65.790	178.117	.000	1.521	1.403	.000	17.09	2.37	25.994	3.322	29.315
12-04	47.0	51.630	159.042	.000	1.174	1.120	.000	16.87	2.43	19.809	2.727	22.535
12-05	46.3	47.198	145.867	.000	1.120	.940	.000	16.85	2.43	18.872	2.287	21.159
12-06	46.0	43.538	134.920	.000	1.071	.829	.000	16.84	2.43	18.038	2.015	20.053
12-07	42.9	35.904	124.518	.000	1.027	.779	.000	16.82	2.42	17.273	1.886	19.159
12-08	41.0	30.986	115.889	.000	.982	.732	.000	16.80	2.42	16.501	1.769	18.270
12-09	39.9	28.216	106.764	.000	.887	.581	.000	16.81	2.54	14.916	1.473	16.390
12-10	39.0	26.122	98.955	.000	.835	.507	.000	16.81	2.58	14.028	1.310	15.338
12-11	38.0	23.720	91.923	.000	.791	.421	.000	16.76	2.61	13.265	1.100	14.365
12-12	37.0	22.162	83.726	.000	.760	.234	.000	16.74	2.79	12.717	.653	13.370
12-13	37.0	21.017	78.601	.000	.733	.219	.000	16.74	2.79	12.275	.613	12.888
S TOT	1.0	480.652	1519.921	.000	13.315	9.990	.000	16.99	2.51	226.209	25.030	251.239
AFTER	1.0	152.750	638.049	.000	4.302	1.487	.000	17.12	2.70	73.674	4.011	77.685
TOTAL	1.0	633.402	2157.971	.000	17.618	11.477	.000	17.02	2.53	299.883	29.041	328.924

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.341	.451	1.003	29.570	15.032	11.98	.000	15.032	15.032	14.366
12-03	1.426	.256	.600	14.632	12.401	9.64	.000	12.401	27.433	25.131
12-04	1.010	.209	.526	9.702	11.089	8.41	.000	11.089	38.522	33.879
12-05	.959	.176	.499	9.472	10.053	8.70	.000	10.053	48.575	41.088
12-06	.914	.155	.478	9.357	9.149	9.01	.000	9.149	57.724	47.053
12-07	.873	.145	.459	9.357	8.324	9.37	.000	8.324	66.048	51.987
12-08	.832	.136	.442	9.357	7.503	9.75	.000	7.503	73.551	56.029
12-09	.732	.113	.415	8.321	6.809	9.74	.000	6.809	80.360	59.365
12-10	.681	.100	.396	7.975	6.186	9.96	.000	6.186	86.546	62.120
12-11	.643	.084	.376	7.857	5.404	10.40	.000	5.404	91.951	64.308
12-12	.616	.050	.352	7.503	4.849	10.67	.000	4.849	96.799	66.093
12-13	.594	.047	.340	7.503	4.403	11.02	.000	4.403	101.203	67.566
S TOT	11.621	1.922	5.885	130.609	101.203	1.34	.000	101.203	101.203	67.566
AFTER	3.483	.304	2.131	35.009	36.758	1.34	.000	36.758	137.961	73.236
TOTAL	15.104	2.226	8.016	165.618	137.961	1.34	.000	137.961	137.961	73.236

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	111.0	30.0	LIFE, YRS.	46.67	8.00	80.332
GROSS ULT. MB & MMF	16953.000	44000.890	DISCOUNT %	10.00	10.00	73.236
GROSS CUM., MB & MMF	16319.600	41842.920	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	67.412
GROSS RES., MB & MMF	633.402	2157.971	DISCOUNTED PAYOUT, YRS.	.00	15.00	60.385
NET RES., MB & MMF	17.618	11.477	UNDISCOUNTED NET/INVEST.	.00	20.00	51.714
NET REVENUE, M$	299.883	29.041	DISCOUNTED NET/INVEST.	.00	25.00	45.456
INITIAL PRICE, $	17.458	2.297	RATE-OF-RETURN, PCT.	100.00	35.00	37.023
INITIAL N.I., PCT.	4.458	1.827	INITIAL W.I., PCT.	4.321	50.00	29.560
					70.00	23.895
					100.00	19.183

APPENDIX B11

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWR Inst Income Fund X-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 17 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 86.1 percent of the total net remaining liquid hydrocarbon reserves and 79.6 percent of the total net remaining gas reserves. The properties that we reviewed represent 87.0 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWR Inst Income Fund X-A

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		157,352		709		3,180		161,241
Gas—MMCF		160		3		13		176
Income Data
Future Gross Revenue	$	2,832,738	$	20,736	$	85,399	$	2,938,873
Deductions		1,129,056		2,653		15,720		1,147,429
Future Net Income (FNI)	$	1,703,682	$	18,083	$	69,679	$	1,791,444
Discounted FNI @ 10%	$	895,759	$	13,672	$	43,797	$	953,228

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		26,095		0		0		26,095
Gas—MMCF		45		0		0		45
Income Data
Future Gross Revenue	$	551,289	$	0	$	0	$	551,289
Deductions		300,785		0		0		300,785
Future Net Income (FNI)	$	250,504	$	0	$	0	$	250,504
Discounted FNI @ 10%	$	142,149	$	0	$	0	$	142,149
Total Net Reserves
Oil/Condensate—Barrels		183,447		709		3,180		187,336
Gas—MMCF		205		3		13		221
Income Data
Future Gross Revenue	$	3,384,027	$	20,736	$	85,399	$	3,490,162
Deductions		1,429,841		2,653		15,720		1,448,214
Future Net Income (FNI)	$	1,954,186	$	18,083	$	69,679	$	2,041,948
Discounted FNI @ 10%	$	1,037,908	$	13,672	$	43,797	$	1,095,377

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any: and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion?  . . . The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 13.9 percent of the total net remaining liquid hydrocarbon reserves and 20.4 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SWR INST INCOME FUND X-A PROPERTIES REV BY RYDER SCOTT PDP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:41 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	204.0	478.333	1306.493	.000	11.129	17.600	.000	16.90	2.20	188.125	38.684	226.809
12-03	204.0	449.476	1199.030	.000	10.553	16.260	.000	16.89	2.20	178.276	35.737	214.013
12-04	204.0	422.482	1104.265	.000	10.010	15.052	.000	16.88	2.20	168.997	33.072	202.069
12-05	204.0	397.212	1020.157	.000	9.497	13.952	.000	16.87	2.20	160.251	30.640	190.891
12-06	201.3	353.019	904.427	.000	8.692	12.390	.000	16.80	2.19	145.983	27.113	173.096
12-07	194.0	302.716	802.175	.000	7.733	10.991	.000	16.69	2.18	129.018	23.954	152.972
12-08	175.8	284.028	597.369	.000	7.354	9.494	.000	16.68	2.20	122.646	20.913	143.559
12-09	121.0	263.815	119.780	.000	6.982	6.681	.000	16.67	2.31	116.386	15.442	131.828
12-10	120.1	248.564	111.508	.000	6.643	6.212	.000	16.66	2.31	110.677	14.335	125.012
12-11	120.0	234.669	104.604	.000	6.329	5.789	.000	16.66	2.31	105.413	13.346	118.760
12-12	120.0	221.608	98.209	.000	6.032	5.398	.000	16.65	2.30	100.435	12.431	112.867
12-13	120.0	209.288	92.211	.000	5.751	5.033	.000	16.64	2.30	95.714	11.580	107.294
S TOT	1.0	3865.208	7460.228	.000	96.703	124.851	.000	16.77	2.22	1621.922	277.247	1899.169
AFTER	1.0	2109.466	835.797	.000	60.649	34.803	.000	16.58	2.24	1005.484	77.891	1083.375
TOTAL	1.0	5974.674	8296.025	.000	157.352	159.654	.000	16.70	2.22	2627.405	355.138	2982.543

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	8.821	3.010	5.870	51.123	157.986	4.89	.000	157.986	157.986	150.782
12-03	8.354	2.780	5.554	51.123	146.202	5.11	.000	146.202	304.188	277.633
12-04	7.914	2.572	5.258	51.123	135.202	5.34	.000	135.202	439.390	384.277
12-05	7.500	2.382	4.979	51.123	124.907	5.58	.000	124.907	564.298	473.844
12-06	6.833	2.111	4.518	49.260	110.375	5.83	.000	110.375	674.673	545.874
12-07	6.042	1.869	4.004	43.669	97.388	5.81	.000	97.388	772.061	603.587
12-08	5.737	1.628	3.792	42.274	90.127	5.98	.000	90.127	862.188	652.142
12-09	5.433	1.193	3.566	38.088	83.548	5.96	.000	83.548	945.736	693.059
12-10	5.164	1.107	3.387	37.901	77.452	6.19	.000	77.452	1023.189	727.544
12-11	4.916	1.031	3.224	37.884	71.706	6.45	.000	71.706	1094.895	756.567
12-12	4.681	.960	3.069	37.884	66.273	6.72	.000	66.273	1161.168	780.954
12-13	4.459	.894	2.922	37.884	61.135	7.01	.000	61.135	1222.303	801.405
S TOT	75.853	21.536	50.142	529.335	1222.303	9.37	.000	1222.303	1222.303	801.405
AFTER	46.474	5.942	30.389	519.190	481.380	9.37	.000	481.380	1703.682	895.759
TOTAL	122.327	27.478	80.531	1048.525	1703.682	9.37	.000	1703.682	1703.682	895.759

	OIL	GAS			P.W.  %	P.W., M$
GROSS WELLS	131.0	74.0	LIFE, YRS.	59.08	8.00	990.610
GROSS ULT., MB & MMF	55321.530	168107.200	DISCOUNT %	10.00	10.00	895.759
GROSS CUM., MB & MMF	49346.860	159811.200	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	818.030
GROSS RES., MB & MMF	5974.673	8296.024	DISCOUNTED PAYOUT, YRS.	.00	15.00	724.967
NET RES., MB & MMF	157.352	159.654	UNDISCOUNTED NET/INVEST.	.00	20.00	612.072
NET REVENUE, M$	2627.405	355.138	DISCOUNTED NET/INVEST.	.00	25.00	532.288
INITIAL PRICE, $	17.124	1.960	RATE-OF-RETURN, PCT.	100.00	35.00	427.180
INITIAL N.I., PCT.	2.335	1.351	INITIAL W.I., PCT.	1.727	50.00	336.225
					70.00	268.256
					100.00	212.348

SWR INST INCOME FUND X-A PROPERTIES REV BY RYDER SCOTT PNP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:42 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M$	NET GAS SALES   M$	TOTAL NET SALES M$
12-02	.1	.447	2.233	.000	.021	.105	.000	18.07	2.60	.381	.274	.655
12-03	1.0	4.311	21.553	.000	.204	1.018	.000	18.07	2.60	3.680	2.647	6.327
12-04	1.0	3.167	15.836	.000	.150	.748	.000	18.07	2.60	2.704	1.945	4.649
12-05	1.0	2.546	12.730	.000	.120	.601	.000	18.07	2.60	2.173	1.564	3.737
12-06	1.0	2.149	10.745	.000	.102	.508	.000	18.07	2.60	1.834	1.320	3.154
12-07	1.0	1.871	9.354	.000	.088	.442	.000	18.07	2.60	1.597	1.149	2.746
12-08	1.0	.510	2.548	.000	.024	.120	.000	18.07	2.60	.435	.313	.748
12-09
12-10
12-11
12-12
12-13
S  TOT	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST $/EBO	CAPITAL INVEST     M$	FUT NET CASHFLOW     M$	CUM CASHFLOW     M$	10.0% CUM DISC CF M$
12-02	.018	.021	.019	.031	.568	2.27	.000	.568	.568	.518
12-03	.169	.199	.179	.375	5.405	2.47	.000	5.405	5.973	5.220
12-04	.124	.146	.131	.375	3.872	2.83	.000	3.872	9.845	8.279
12-05	.100	.117	.106	.375	3.039	3.16	.000	3.039	12.884	10.460
12-06	.084	.099	.089	.375	2.507	3.48	.000	2.507	15.391	12.096
12-07	.073	.086	.078	.375	2.134	3.78	.000	2.134	17.524	13.361
12-08	.020	.023	.021	.125	.558	4.30	.000	.558	18.083	13.672
12-09
12-10
12-11
12-12
12-13
S  TOT	.589	.691	.622	2.031	18.083	4.30	.00	18.083	18.083	13.672
AFTER	.000	.000	.000	.000	.000	4.30	.000	.000	18.083	13.672
TOTAL	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	6.33	8.00	14.405
GROSS ULT., MB & MMF	15.000	98.806	DISCOUNT %	10.00	10.00	13.672
GROSS CUM., MB & MMF	.000	23.806	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	12.997
GROSS RES., MB & MMF	15.000	75.000	DISCOUNTED PAYOUT, YRS.	.00	15.00	12.083
NET RES., MB & MMF	.709	3.543	UNDISCOUNTED NET/INVEST.	.00	20.00	10.776
NET REVENUE, M$	12.804	9.212	DISCOUNTED NET/INVEST.	.00	25.00	9.688
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	7.995
INITIAL N.I., PCT.	4.724	4.724	INITIAL W.I., PCT.	6.250	50.00	6.248
					70.00	4.762
					100.00	3.443

SWR INST INCOME FUND X-A PROPERTIES REV BY RYDER SCOTT PUD RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:41 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END-  MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.6	8.863	35.452	.000	.425	1.699	.000	18.07	2.60	7.675	4.417	12.093
12-04	1.0	10.787	43.150	.000	.517	2.068	.000	18.07	2.60	9.342	5.377	14.718
12-05	1.0	8.028	32.111	.000	.385	1.539	.000	18.07	2.60	6.952	4.001	10.953
12-06	1.0	6.494	25.977	.000	.311	1.245	.000	18.07	2.60	5.624	3.237	8.861
12-07	1.0	5.503	22.010	.000	.264	1.055	.000	18.07	2.60	4.765	2.743	7.508
12-08	1.0	4.802	19.209	.000	.230	.921	.000	18.07	2.60	4.159	2.394	6.552
12-09	1.0	4.278	17.113	.000	.205	.820	.000	18.07	2.60	3.705	2.132	5.837
12-10	1.0	3.870	15.479	.000	.185	.742	.000	18.07	2.60	3.351	1.929	5.280
12-11	1.0	3.541	14.163	.000	.170	.679	.000	18.07	2.60	3.066	1.765	4.831
12-12	1.0	3.258	13.030	.000	.156	.624	.000	18.07	2.60	2.281	1.624	4.445
12-13	1.0	2.997	11.988	.000	.144	.575	.000	18.07	2.60	2.595	1.494	4.089
S  TOT	1.0	62.420	249.682	.000	2.991	11.966	.000	18.07	2.60	54.056	31.111	85.167
AFTER	1.0	3.925	15.699	.000	.188	.752	.000	18.07	2.60	3.399	1.956	5.355
TOTAL	1.0	66.345	265.381	.000	3.180	12.718	.000	18.07	2.60	57.455	33.067	90.522

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW   M$	CUM CASHFLOW   M$	10.0% CUM DISC CF     M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.353	.331	.342	.635	10.431	2.35	.000	10.431	10.431	8.878
12-04	.430	.403	.417	1.089	12.380	2.71	.000	12.380	22.811	18.667
12-05	.320	.300	.310	1.089	8.934	3.15	.000	8.934	31.745	25.083
12-06	.259	.243	.251	1.089	7.020	3.55	.000	7.020	38.765	29.664
12-07	.219	.206	.212	1.089	5.781	3.93	.000	5.781	44.546	33.093
12-08	.191	.180	.185	1.089	4.907	4.29	.000	4.907	49.453	35.738
12-09	.170	.160	.165	1.089	4.253	4.64	.000	4.253	53.706	37.822
12-10	.154	.145	.149	1.089	3.743	4.97	.000	3.743	57.449	39.489
12-11	.141	.132	.137	1.089	3.332	5.30	.000	3.332	60.781	40.838
12-12	.130	.122	.126	1.089	2.978	5.64	.000	2.978	63.759	41.934
12-13	.119	.112	.116	1.089	2.653	6.00	.000	2.653	66.412	42.822
S TOT	2.487	2.333	2.410	11.525	66.412	7.29	.000	66.412	66.412	42.822
AFTER	.156	.147	.152	1.633	3.267	7.29	.000	3.267	69.679	43.797
TOTAL	2.643	2.480	2.562	13.158	69.679	7.29	.000	69.679	69.679	43.797

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	13.50	8.00	47.579
GROSS ULT., MB & MMF	66.345	265.381	DISCOUNT %	10.00	10.00	43.797
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	40.485
GROSS RES., MB & MMF	66.345	265.381	DISCOUNTED PAYOUT, YRS.	.00	15.00	36.237
NET RES., MB & MMF	3.180	12.718	UNDISCOUNTED NET/INVEST.	.00	20.00	30.623
NET REVENUE, M$	57.455	33.067	DISCOUNTED NET/INVEST.	.00	25.00	26.327
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	20.250
INITIAL N.I., PCT.	4.792	4.792	INITIAL W.I., PCT.	6.050	50.00	14.661
					70.00	10.377
					100.00	6.900

SWR INST INCOME FUND X-A PROPERTIES REV BY RYDER SCOTT TOTAL PROVED RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:42 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M$	NET GAS SALES   M$	TOTAL NET SALES   M$
12-02	204.1	478.780	1308.726	.000	11.150	17.705	.000	16.91	2.20	188.507	38.958	227.465
12-03	205.6	462.649	1256.035	.000	11.181	18.977	.000	16.96	2.26	189.631	42.802	232.432
12-04	206.0	436.436	1163.251	.000	10.676	17.868	.000	16.96	2.26	181.043	40.393	221.436
12-05	206.0	407.786	1064.998	.000	10.002	16.092	.000	16.93	2.25	169.377	36.205	205.581
12-06	203.3	361.663	941.149	.000	9.104	14.143	.000	16.85	2.24	153.441	31.670	185.111
12-07	196.0	310.089	833.539	.000	8.085	12.488	.000	16.75	2.23	135.380	27.845	163.226
12-08	177.1	289.340	619.127	.000	7.608	10.535	.000	16.72	2.24	127.240	23.619	150.859
12-09	122.0	268.093	136.893	.000	7.187	7.501	.000	16.71	2.34	120.091	17.575	137.666
12-10	121.1	252.434	126.986	.000	6.828	6.954	.000	16.70	2.34	114.028	16.263	130.291
12-11	121.0	238.210	118.768	.000	6.499	6.468	.000	16.69	2.34	108.480	15.111	123.591
12-12	121.0	224.865	111.239	.000	6.188	6.022	.000	16.69	2.33	103.256	14.055	117.311
12-13	121.0	212.285	104.198	.000	5.894	5.607	.000	16.68	2.33	98.309	13.074	111.383
S TOT	1.0	3942.629	7784.909	.000	100.403	140.360	.000	16.82	2.26	1688.782	317.570	2006.352
AFTER	1.0	2113.390	851.496	.000	60.837	35.555	.000	16.58	2.25	1008.882	79.847	1088.729
TOTAL	1.0	6056.019	8636.405	.000	161.240	175.915	.000	16.73	2.26	2697.665	397.417	3095.081

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST   $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW   M$	CUM CASHFLOW   M$	10.0% CUM DISC CF   M$
12-02	8.839	3.030	5.888	51.154	158.553	4.89	.000	158.553	158.553	151.300
12-03	8.876	3.310	6.075	52.133	162.039	4.91	.000	162.039	320.592	291.731
12-04	8.468	3.121	5.806	52.587	151.454	5.13	.000	151.454	472.046	411.223
12-05	7.919	2.800	5.395	52.587	136.881	5.42	.000	136.881	608.927	509.388
12-06	7.176	2.453	4.858	50.723	119.901	5.69	.000	119.901	728.828	587.633
12-07	6.335	2.160	4.294	45.133	105.303	5.70	.000	105.303	834.132	650.040
12-08	5.949	1.831	3.999	43.488	95.593	5.90	.000	95.593	929.724	701.551
12-09	5.603	1.353	3.731	39.177	87.801	5.91	.000	87.801	1017.525	744.553
12-10	5.318	1.252	3.537	38.990	81.195	6.15	.000	81.195	1098.720	780.704
12-11	5.057	1.163	3.360	38.973	75.038	6.41	.000	75.038	1173.758	811.077
12-12	4.811	1.081	3.195	38.973	69.251	6.68	.000	69.251	1243.009	836.559
12-13	4.578	1.006	3.038	38.973	63.788	6.97	.000	63.788	1306.797	857.898
S TOT	78.928	24.560	53.175	542.891	1306.797	9.37	.000	1306.797	1306.797	857.898
AFTER	46.631	6.089	30.540	520.823	484.646	9.37	.000	484.646	1791.444	953.227
TOTAL	125.559	30.649	83.715	1063.715	1791.444	9.37	.000	1791.444	1791.444	953.227

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	133.0	74.0	LIFE, YRS.	59.08	8.00	1052.594
GROSS ULT., MB & MMF	55402.870	168471.400	DISCOUNT %	10.00	10.00	953.227
GROSS CUM., MB & MMF	49346.860	159835.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	871.512
GROSS RES., MB & MMF	6056.018	8636.403	DISCOUNTED PAYOUT, YRS.	.00	15.00	773.286
NET RES., MB & MMF	161.240	175.915	UNDISCOUNTED NET/INVEST.	.00	20.00	653.471
NET REVENUE, M$	2697.664	397.417	DISCOUNTED NET/INVEST.	.00	25.00	568.303
INITIAL PRICE, $	17.166	2.002	RATE-OF-RETURN, PCT.	100.00	35.00	455.425
INITIAL N.I., PCT.	2.443	1.578	INITIAL W.I., PCT.	1.974	50.00	357.134
					70.00	283.395
					100.00	222.691

SWR INST INCOME FUND X-A PROPERTIES NOT REV BY RYDER SCOTT PDP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 09:15:53 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	116.6	99.004	1365.940	.000	3.369	9.450	.000	18.05	2.25	60.804	21.226	82.031
12-03	91.5	77.682	979.014	.000	2.413	5.958	.000	17.86	2.34	43.105	13.967	57.072
12-04	66.3	61.058	667.434	.000	2.008	3.527	.000	17.84	2.69	35.817	9.492	45.310
12-05	62.3	55.450	593.920	.000	1.906	2.931	.000	17.82	2.68	33.966	7.852	41.818
12-06	62.0	51.182	551.037	.000	1.818	2.691	.000	17.81	2.69	32.367	7.234	39.601
12-07	61.9	47.424	512.488	.000	1.735	2.521	.000	17.79	2.69	30.877	6.783	37.660
12-08	60.6	43.115	473.442	.000	1.654	2.320	.000	17.77	2.72	29.393	6.311	35.704
12-09	58.9	39.464	434.520	.000	1.523	2.011	.000	17.81	2.82	27.124	5.666	32.790
12-10	58.0	36.696	404.006	.000	1.438	1.847	.000	17.81	2.84	25.622	5.250	30.871
12-11	57.0	33.622	375.982	.000	1.365	1.678	.000	17.79	2.86	24.272	4.804	29.076
12-12	56.0	31.399	348.365	.000	1.303	1.413	.000	17.77	2.93	23.164	4.137	27.301
12-13	54.9	29.235	324.107	.000	1.210	1.287	.000	17.72	2.92	21.436	3.758	25.194
S TOT	1.0	605.330	7030.255	.000	21.743	37.635	.000	17.84	2.56	387.948	96.479	484.427
AFTER	1.0	186.400	2875.578	.000	4.352	7.752	.000	17.59	2.87	76.581	22.268	98.849
TOTAL	1.0	791.731	9905.833	.000	26.095	45.387	.000	17.80	2.62	464.529	118.748	583.276

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST   $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW M$	CUM CASHFLOW   M$	10.0% CUM DISC CF   M$
12.02	3.209	1.637	1.801	44.624	30.760	10.37	.000	30.760	30.760	29.387
12.03	2.234	1.070	1.312	26.854	25.602	9.24	.000	25.602	56.362	51.615
12.04	1.761	.717	1.159	19.092	22.581	8.76	.000	22.581	78.943	69.435
12.05	1.667	.593	1.074	18.862	19.622	9.27	.000	19.622	98.565	83.507
12.06	1.586	.547	1.021	18.747	17.700	9.66	.000	17.700	116.265	95.048
12-07	1.511	.513	.974	18.747	15.915	10.09	.000	15.915	132.179	104.482
12-08	1.438	.477	.926	18.747	14.116	10.58	.000	14.116	146.295	112.089
12-09	1.306	.427	.870	17.711	12.476	10.93	.000	12.476	158.771	118.202
12-10	1.225	.396	.828	17.365	11.058	11.35	.000	11.058	169.829	123.127
12-11	1.160	.362	.785	17.247	9.522	11.89	.000	9.522	179.350	126.984
12-12	1.107	.312	.739	16.893	8.250	12.38	.000	8.250	187.601	130.021
12-13	1.025	.283	.681	16.111	7.094	12.71	.000	7.094	194.695	132.396
S TOT	19.229	7.333	12.168	251.003	194.695	1.43	.000	194.695	194.695	132.396
AFTER	3.750	1.676	2.606	35.009	55.809	1.43	.000	55.809	250.503	142.149
TOTAL	22.979	9.008	14.774	286.011	250.503	1.43	.000	250.503	250.503	142.149

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	134.0	59.0	LIFE, YRS.	38.92	8.00	154.994
GROSS ULT., MB & MMF	21306.430	135394.600	DISCOUNT %	10.00	10.00	142.149
GROSS CUM., MB & MMF	20514.700	125488.800	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	131.481
GROSS RES., MB & MMF	791.730	9905.834	DISCOUNTED PAYOUT, YRS.	.00	15.00	118.478
NET RES., MB & MMF	26.095	45.387	UNDISCOUNTED NET/INVEST.	.00	20.00	102.253
NET REVENUE, M$	464.529	118.748	DISCOUNTED NET/INVEST.	.00	25.00	90.415
INITIAL PRICE, $	17.731	2.216	RATE-OF-RETURN, PCT.	100.00	35.00	74.263
INITIAL N.I., PCT.	4.746	.834	INITIAL W.I., PCT.	2.735	50.00	59.734
					70.00	48.535
					100.00	39.098

SWR INST INCOME FUND X-A ALL PROPERTIES PDP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:39:13 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END-  MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	320.6	577.337	2672.433	.000	14.497	27.049	.000	17.17	2.21	248.930	59.910	308.840
12-03	295.5	527.157	2178.044	.000	12.966	22.218	.000	17.07	2.24	221.381	49.704	271.085
12-04	270.3	483.539	1771.699	.000	12.018	18.579	.000	17.04	2.29	204.814	42.564	247.378
12-05	266.3	452.662	1614.076	.000	11.404	16.883	.000	17.03	2.28	194.217	38.492	232.709
12-06	263.3	404.201	1455.464	.000	10.510	15.082	.000	16.97	2.28	178.350	34.347	212.697
12-07	255.9	350.140	1314.663	.000	9.468	13.512	.000	16.89	2.27	159.895	30.737	190.632
12-08	236.3	327.143	1070.811	.000	9.007	11.814	.000	16.88	2.30	152.039	27.223	179.263
12-09	179.9	303.279	554.301	.000	8.505	8.692	.000	16.87	2.43	143.510	21.108	164.618
12-10	178.1	285.260	515.513	.000	8.081	8.059	.000	16.87	2.43	136.298	19.584	155.883
12-11	177.0	268.290	480.586	.000	7.694	7.467	.000	16.86	2.43	129.685	18.150	147.835
12-12	176.0	253.007	446.574	.000	7.336	6.810	.000	16.85	2.43	123.599	16.568	140.167
12-13	174.9	238.522	416.318	.000	6.960	6.320	.000	16.83	2.43	117.150	15.338	132.488
S TOT	1.0	4470.540	14490.480	.000	118.446	162.486	.000	16.97	2.30	2009.869	373.726	2383.596
AFTER	1.0	2295.865	3711.376	.000	65.001	42.554	.000	16.65	2.35	1082.065	100.159	1182.224
TOTAL	1.0	6766.405	18201.860	.000	183.447	205.040	.000	16.85	2.31	3091.934	473.885	3365.819

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW   M$	CUM CASHFLOW   M$	10.0% CUM DISC CF     M$
12-02	12.030	4.646	7.671	95.747	188.745	6.32	.000	188.745	188.745	180.169
12-03	10.587	3.850	6.866	77.977	171.805	5.96	.000	171.805	360.550	329.248
12-04	9.675	3.289	6.416	70.215	157.784	5.93	.000	157.784	518.334	453.712
12-05	9.167	2.976	6.053	69.985	144.529	6.20	.000	144.529	662.863	557.352
12-06	8.419	2.658	5.539	68.007	128.075	6.50	.000	128.075	790.937	640.921
12-07	7.554	2.381	4.977	62.417	113.303	6.60	.000	113.303	904.241	708.068
12-08	7.175	2.105	4.718	61.021	104.243	6.83	.000	104.243	1008.484	764.231
12-09	6.738	1.621	4.436	55.799	96.024	6.89	.000	96.024	1104.508	811.261
12-10	6.389	1.503	4.215	55.266	88.510	7.15	.000	88.510	1193.018	850.670
12-11	6.076	1.393	4.008	55.131	81.227	7.45	.000	81.227	1274.245	883.551
12-12	5.788	1.272	3.807	54.777	74.523	7.75	.000	74.523	1348.768	910.975
12-13	5.484	1.177	3.603	53.995	68.229	8.02	.000	68.229	1416.997	933.801
S TOT	95.081	28.869	62.310	780.338	1416.997	7.24	.000	1416.997	1416.997	933.801
AFTER	50.224	7.617	32.995	554.198	537.188	7.24	.000	537.188	1954.185	1037.907
TOTAL	145.306	36.486	95.305	1334.536	1954.186	7.24	.000	1954.186	1954.185	1037.907

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	265.0	133.0	LIFE, YRS.	59.08	8.00	1145.603
GROSS ULT., MB & MMF	76627.960	303501.800	DISCOUNT %	10.00	10.00	1037.907
GROSS CUM., MB & MMF	69861.550	285300.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	949.511
GROSS RES., MB & MMF	6766.405	18201.850	DISCOUNTED PAYOUT, YRS.	.00	15.00	843.445
NET RES., MB & MMF	183.447	205.040	UNDISCOUNTED NET/INVEST.	.00	20.00	714.325
NET REVENUE, M$	3091.934	473.885	DISCOUNTED NET/INVEST.	.00	25.00	622.702
INITIAL PRICE, $	17.272	2.096	RATE-OF-RETURN, PCT.	100.00	35.00	501.442
INITIAL N.I., PCT.	2.923	1.077	INITIAL W.I., PCT.	2.089	50.00	395.959
					70.00	316.791
					100.00	251.446

SWR INST INCOME FUND X-A ALL PROPERTIES PNP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:39:13 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.1	.447	2.233	.000	.021	.105	.000	18.07	2.60	.381	.274	.655
12-03	1.0	4.311	21.553	.000	.204	1.018	.000	18.07	2.60	3.680	2.647	6.327
12-04	1.0	3.167	15.836	.000	.150	.748	.000	18.07	2.60	2.704	1.945	4.649
12-05	1.0	2.546	12.730	.000	.120	.601	.000	18.07	2.60	2.173	1.564	3.737
12-06	1.0	2.149	10.745	.000	.102	.508	.000	18.07	2.60	1.834	1.320	3.154
12-07	1.0	1.871	9.354	.000	.088	.442	.000	18.07	2.60	1.597	1.149	2.746
12-08	1.0	.510	2.548	.000	.024	.120	.000	18.07	2.60	.435	.313	.748
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	15.000	75.000	.000	.709	3.543	.000	18.07	2.60	12.804	9.212	22.016

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10. 0% CUM DISC CF M$
12-02	.018	.021	.019	.031	.568	2.27	.000	.568	.568	.518
12-03	.169	.199	.179	.375	5.405	2.47	.000	5.405	5.973	5.220
12-04	.124	.146	.131	.375	3.872	2.83	.000	3.872	9.845	8.279
12-05	.100	.117	.106	.375	3.039	3.16	.000	3.039	12.884	10.460
12-06	.084	.099	.089	.375	2.507	3.48	.000	2.507	15.391	12.096
12-07	.073	.086	.078	.375	2.134	3.78	.000	2.134	17.524	13.361
12-08	.020	.023	.021	.125	.558	4.30	.000	.558	18.083	13.672
12-09
12-10
12-11
12-12
12-13
S TOT	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672
AFTER	.000	.000	.000	.000	.000	4.30	.000	.000	18.083	13.672
TOTAL	.589	.691	.622	2.031	18.083	4.30	.000	18.083	18.083	13.672

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	6.33	8 00	14.405
GROSS ULT., MB & MMF	15.000	98.806	DISCOUNT %	10.00	10.00	13.672
GROSS CUM., MB & MMF	.000	23.806	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	12.997
GROSS RES., MB & MMF	15.000	75.000	DISCOUNTED PAYOUT, YRS.	.00	15.00	12.083
NET RES., MB & MMF	.709	3.543	UNDISCOUNTED NET/INVEST.	.00	20.00	10.776
NET REVENUE, M$	12.804	9.212	DISCOUNTED NET/INVEST.	.00	25.00	9.688
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	7.995
INITIAL N.I., PCT.	4.724	4.724	INITIAL W.I., PCT.	6.250	50.00	6.248
					70.00	4.762
					100.00	3.443

SWR INST INCOME FUND X-A ALL PROPERTIES PUD RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:39:13 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.6	8.863	35.452	.000	.425	1.699	.000	18.07	2.60	7.675	4.417	12.093
12-04	1.0	10.787	43.150	.000	.517	2.068	.000	18.07	2.60	9.342	5.377	14.718
12-05	1.0	8.028	32.111	.000	.385	1.539	.000	18.07	2.60	6.952	4.001	10.953
12-06	1.0	6.494	25.977	.000	.311	1.245	.000	18.07	2.60	5.624	3.237	8.861
12-07	1.0	5.503	22.010	.000	.264	1.055	.000	18.07	2.60	4.765	2.743	7.508
12-08	1.0	4.802	19.209	.000	.230	.921	.000	18.07	2.60	4.159	2.394	6.552
12-09	1.0	4.278	17.113	.000	.205	.820	.000	18.07	2.60	3.705	2.132	5.837
12-10	1.0	3.870	15.479	.000	.185	.742	.000	18.07	2.60	3.351	1.929	5.280
12-11	1.0	3.541	14.163	.000	.170	.679	.000	18.07	2.60	3.066	1.765	4.831
12-12	1.0	3.258	13.030	.000	.156	.624	.000	18.07	2.60	2.821	1.624	4.445
12-13	1.0	2.997	11.988	.000	.144	.575	.000	18.07	2.60	2.595	1.494	4.089
S TOT	1.0	62.420	249.682	.000	2.991	11.966	.000	18.07	2.60	54.056	31.111	85.167
AFTER	1.0	3.925	15.699	.000	.188	.752	.000	18.07	2.60	3.399	1.956	5.355
TOTAL	1.0	66.345	265.381	.000	3.180	12.718	.000	18.07	2.60	57.455	33.067	90.522

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.353	.331	.342	.635	10.431	2.35	.000	10.431	10.431	8.878
12-04	.430	.403	.417	1.089	12.380	2.71	.000	12.380	22.811	18.667
12-05	.320	.300	.310	1.089	8.934	3.15	.000	8.934	31.745	25.083
12-06	.259	.243	.251	1.089	7.020	3.55	.000	7.020	38.765	29.664
12-07	.219	.206	.212	1.089	5.781	3.93	.000	5.781	44.546	33.093
12-08	.191	.180	.185	1.089	4.907	4.29	.000	4.907	49.453	35.738
12-09	.170	.160	.165	1.089	4.253	4.64	.000	4.253	53.706	37.822
12-10	.154	.145	.149	1.089	3.743	4.97	.000	3.743	57.449	39.489
12-11	.141	.132	.137	1.089	3.332	5.30	.000	3.332	60.781	40.838
12-12	.130	.122	.126	1.089	2.978	5.64	.000	2.978	63.759	41.934
12-13	.119	.112	.116	1.089	2.653	6.00	.000	2.653	66.412	42.822
S TOT	2.487	2.333	2.410	11.525	66.412	7.29	.000	66.412	66.412	42.822
AFTER	.156	.147	.152	1.633	3.267	7.29	.000	3.267	69.679	43.797
TOTAL	2.643	2.480	2.562	13.158	69.679	7.29	.000	69.679	69.679	43.797

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	13.50	8.00	47.579
GROSS ULT., MB & MMF	66.345	265.381	DISCOUNT %	10.00	10.00	43.797
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	40.485
GROSS RES., MB & MMF	66.345	265.381	DISCOUNTED PAYOUT, YRS.	.00	15.00	36.237
NET RES., MB & MMF	3.180	12.718	UNDISCOUNTED NET/INVEST.	.00	20.00	30.623
NET REVENUE, M$	57.455	33.067	DISCOUNTED NET/INVEST.	.00	25.00	26.327
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	20.250
INITIAL N.I., PCT.	4.792	4.792	INITIAL W.I., PCT.	6.050	50.00	14.661
					70.00	10.377
					100.00	6.900

SWR INST INCOME FUND X-A ALL PROPERTIES TOTAL PROVED RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:39:13 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10A

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	320.7	577.784	2674.666	.000	14.519	27.155	.000	17.17	2.22	249.311	60.184	309.496
12-03	297.1	540.331	2235.049	.000	13.594	24.935	.000	17.12	2.28	232.736	56.769	289.504
12-04	272.3	497.494	1830.685	.000	12.684	21.395	.000	17.10	2.33	216.860	49.886	266.746
12-05	268.3	463.236	1658.917	.000	11.909	19.023	.000	17.08	2.32	203.343	44.057	247.399
12-06	265.3	412.844	1492.186	.000	10.922	16.834	.000	17.01	2.31	185.809	38.904	224.712
12-07	257.9	357.513	1346.027	.000	9.820	15.009	.000	16.93	2.31	166.258	34.628	200.886
12-08	237.7	332.455	1092.569	.000	9.262	12.855	.000	16.91	2.33	156.633	29.930	186.563
12-09	180.9	307.557	571.414	.000	8.710	9.512	.000	16.90	2.44	147.215	23.241	170.456
12-10	179.1	289.130	530.992	.000	8.267	8.801	.000	16.89	2.44	139.649	21.513	161.162
12-11	178.0	271.831	494.749	.000	7.863	8.146	.000	16.88	2.44	132.751	19.915	152.666
12-12	177.0	256.264	459.604	.000	7.492	7.435	.000	16.87	2.45	126.420	18.192	144.612
12-13	175.9	241.519	428.306	.000	7.104	6.895	.000	16.86	2.44	119.745	16.832	136.577
S TOT	1.0	4547.960	14815.160	.000	122.146	177.995	.000	17.00	2.33	2076.730	414.049	2490.779
AFTER	1.0	2299.790	3727.075	.000	65.189	43.307	.000	16.65	2.36	1085.464	102.115	1187.579
TOTAL	1.0	6847.749	18542.240	.000	187.335	221.302	.000	16.88	2.33	3162.193	516.165	3678.358

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LISTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	12.048	4.667	7.690	95.778	189.313	6.31	.000	189.313	189.313	180.687
12-03	11.110	4.380	7.387	78.987	187.641	5.74	.000	187.641	376.954	343.346
12-04	10.229	3.838	6.964	71.679	174.036	5.71	.000	174.036	550.989	480.658
12-05	9.586	3.393	6.468	71.449	156.502	6.03	.000	156.502	707.492	592.895
12-06	8.762	3.000	5.879	69.471	137.601	6.35	.000	137.601	845.093	682.681
12-07	7.846	2.673	5.267	63.881	121.218	6.47	.000	121.218	966.311	754.522
12-08	7.386	2.308	4.925	62.235	109.709	6.74	.000	109.709	1076.020	813.641
12-09	6.909	1.780	4.602	56.888	100.277	6.82	.000	100.277	1176.296	862.754
12-10	6.543	1.648	4.365	56.355	92.253	7.08	.000	92.253	1268.549	903.831
12-11	6.217	1.525	4.145	56.220	84.560	7.39	.000	84.560	1353.108	938.060
12-12	5.918	1.393	3.933	55.866	77.501	7.69	.000	77.501	1430.610	966.580
12-13	5.603	1.289	3.719	55.084	70.882	7.96	.000	70.882	1501.492	990.294
S TOT	98.157	31.893	65.342	793.894	1501.492	7.24	.000	1501.492	1501.492	990.294
AFTER	50.381	7.764	33.147	555.832	540.455	7.24	.000	540.455	2041.947	1095.376
TOTAL	148.538	39.657	98.489	1349.726	2041.947	7.24	.000	2041.947	2041.947	1095.376

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	267.0	133.0	LIFE, YRS.	59.08	8.00	1207.587
GROSS ULT., MB & MMF	76709.300	303866.000	DISCOUNT %	10.00	10.00	1095.376
GROSS CUM., MB & MMF	69861.550	285323.800	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1002.993
GROSS RES., MB & MMF	6847.750	18542.240	DISCOUNTED PAYOUT, YRS.	.00	15.00	891.764
NET RES., MB & MMF	187.335	221.302	UNDISCOUNTED NET/INVEST.	.00	20.00	755.724
NET REVENUE, M$	3162.193	516.165	DISCOUNTED NET/INVEST.	.00	25.00	658.718
INITIAL PRICE, $	17.299	2.112	RATE-OF-RETURN, PCT.	100.00	35.00	529.688
INITIAL N.I., PCT.	2.985	1.196	INITIAL W.I., PCT.	2.237	50.00	416.868
					70.00	331.930
					100.00	261.790

APPENDIX B12

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund X-B (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 16 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 99.5 percent of the total net remaining liquid hydrocarbon reserves and 79.2 percent of the total net remaining gas reserves. The properties that we reviewed represent 95.4 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund X-B

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		155,624		0		2,911		158,535
Gas—MMCF		257		0		9		266
Income Data
Future Gross Revenue	$	3,128,763	$	0	$	68,288	$	3,197,051
Deductions		1,765,862		0		15,115		1,780,977
Future Net Income (FNI)	$	1,362,901	$	0	$	53,173	$	1,416,074
Discounted FNI @ 10%	$	740,032	$	0	$	29,661	$	769,693

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		799		0		4		803
Gas—MMCF		69		0		1		70
Income Data
Future Gross Revenue	$	166,489	$	0	$	1,387	$	167,876
Deductions		107,253		0		191		107,444
Future Net Income (FNI)	$	59,236	$	0	$	1,196	$	60,432
Discounted FNI @ 10%	$	36,573	$	0	$	876	$	37,449
Total Net Reserves
Oil/Condensate—Barrels		156,423		0		2,915		159,338
Gas—MMCF		326		0		10		336
Income Data
Future Gross Revenue	$	3,295,252	$	0	$	69,675	$	3,364,927
Deductions		1,873,115		0		15,306		1,888,421
Future Net Income (FNI)	$	1,422,137	$	0	$	54,369	$	1,476,506
Discounted FNI @ 10%	$	776,605	$	0	$	30,537	$	807,142

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 0.5 percent of the total net remaining liquid hydrocarbon reserves and 20.8 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

/S/    L. B. BRANUM, P.E.

L. B. Branum, P.E.

Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	09:55:28
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	125.7	75.964	1798.036	.000	12.809	41.720	.000	18.35	1.94	234.997	80.854	315.851
12-03	114.2	71.106	1464.952	.000	12.202	34.820	.000	18.35	1.97	223.936	68.646	292.582
12-04	103.3	72.873	1177.029	.000	11.762	29.608	.000	18.35	2.01	215.790	59.618	275.408
12-05	102.3	65.386	1055.196	.000	11.005	26.622	.000	18.35	2.00	201.905	53.179	255.084
12-06	99.8	55.299	960.739	.000	9.864	24.633	.000	18.39	1.99	181.375	49.037	230.412
12-07	90.8	36.603	874.966	.000	7.739	22.634	.000	18.53	1.97	143.427	44.589	188.016
12-08	71.8	32.808	656.439	.000	7.373	19.601	.000	18.54	1.97	136.686	38.618	175.304
12-09	17.0	26.765	174.147	.000	7.003	13.993	.000	18.55	2.00	129.874	28.043	157.917
12-10	17.0	25.429	163.056	.000	6.697	13.271	.000	18.55	2.00	124.204	26.572	157.775
12-11	15.9	24.125	141.261	.000	6.406	12.259	.000	18.55	1.99	118.811	24.404	143.215
12-12	15.0	22.947	128.830	.000	6.128	10.714	.000	18.55	1.96	113.661	20.979	134.640
12-13	15.0	21.844	121.183	.000	5.862	10.714	.000	18.55	1.96	108.742	19.905	128.647
S TOT	1.1	531.150	8715.832	.000	104.848	260.050	.000	18.44	1.98	1933.407	514.444	2447.851
AFTER	1.1	168.742	989.209	.000	54.490	75.246	.000	18.55	2.06	1010.645	155.285	1165.930
TOTAL	1.1	699.892	9705.041	.000	159.337	335.295	.000	18.48	2.00	2944.051	669.729	3613.781

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	14.698	6.329	4.554	140.915	149.354	8.43	.000	149.354	149.354	142.589
12-03	14.033	5.362	4.239	134.598	134.350	8.79	.000	134.350	283.704	259.140
12-04	13.667	4.656	3.875	124.042	129.169	8.76	.000	129.169	412.872	361.074
12-05	12.819	4.158	3.553	120.856	113.699	9.16	.000	113.699	526.571	442.630
12-06	11.705	3.836	3.098	110.829	100.943	9.27	.000	100.943	627.514	508.452
12-07	9.806	3.492	2.207	81.368	91.143	8.42	.000	91.143	718.657	562.471
12-08	9.347	3.021	2.058	78.034	82.844	8.69	.000	82.844	801.501	607.108
12-09	8.882	2.179	1.873	69.327	75.656	8.81	.000	75.656	877.157	644.165
12-10	8.496	2.065	1.785	69.327	69.102	9.17	.000	69.102	946.259	674.936
12-11	8.129	1.899	1.679	68.643	62.865	9.51	.000	62.865	1009.124	700.385
12-12	7.779	1.638	1.541	66.635	57.047	9.81	.000	57.047	1066.170	721.379
12-13	7.443	1.555	1.470	66.635	51.543	10.20	.000	51.543	1117.714	738.628
S TOT	126.806	40.189	31.932	1131.210	1117.714	15.58	.000	1117.714	1117.714	738.625
AFTER	69.791	12.068	12.911	712.368	358.792	15.58	.000	358.792	1476.506	807.142
TOTAL	196.597	52.258	44.843	1843.578	1476.506	15.58	.000	1476.506	1476.506	807.142

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	270.0	106.0	LIFE, YRS.	59.08	8.00	886.897
GROSS ULT., MB & MMF	38071.690	370357.300	DISCOUNT %	10.00	10.00	807.142
GROSS CUM., MB & MMF	37371.800	360652.300	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	741.154
GROSS RES., MB & MMF	699.892	9705.043	DISCOUNTED PAYOUT, YRS.	.00	15.00	661.231
NET RES., MB & MMF	159.337	335.296	UNDISCOUNTED NET/INVEST.	.00	20.00	562.680
NET REVENUE, M$	2944.051	669.729	DISCOUNTED NET/INVEST.	.00	25.00	491.863
INITIAL PRICE, $	16.902	2.009	RATE-OF-RETURN, PCT.	100.00	35.00	397.081
INITIAL N.I., PCT.	16.083	-.470	INITIAL W.I., PCT.	19.232	50.00	313.857
					70.00	251.108
					100.00	199.238

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	09:55:27
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	125.7	75.964	1798.036	.000	12.809	41.720	.000	18.35	1.94	234.997	80.854	315.851
12-03	113.5	69.438	1386.187	.000	12.148	34.538	.000	18.35	1.97	222.957	67.964	290.922
12-04	101.3	62.103	1054.347	.000	11.303	28.084	.000	18.35	2.00	207.385	56.048	263.432
12-05	100.3	57.703	973.408	.000	10.676	25.539	.000	18.35	1.98	195.879	50.645	246.524
12-06	97.8	48.984	903.613	.000	9.591	23.751	.000	18.39	1.98	176.367	46.976	223.342
12-07	88.8	31.114	833.682	.000	7.499	21.874	.000	18.54	1.96	139.028	42.816	181.844
12-08	69.8	27.880	624.690	.000	7.156	18.922	.000	18.54	1.96	132.707	37.036	169.744
12-09	15.0	22.229	145.723	.000	6.803	13.369	.000	18.55	1.99	126.207	26.589	152.796
12-10	15.0	21.196	137.024	.000	6.510	12.689	.000	18.55	1.99	120.779	25.216	145.995
12-11	14.8	20.216	127.993	.000	6.230	11.730	.000	18.55	1.98	115.593	23.177	138.770
12-12	14.0	19.285	117.844	.000	5.963	10.220	.000	18.55	1.94	110.637	19.832	130.469
12-13	14.0	18.402	110.856	.000	5.707	9.709	.000	18.56	1.94	105.900	18.826	124.725
S TOT	1.1	474.515	8213.401	.000	102.396	252.143	.000	18.44	1.97	1888.436	495.978	2384.413
AFTER	1.1	158.465	958.379	.000	54.027	73.858	.000	18.55	2.06	1002.159	152.065	1154.223
TOTAL	1.1	632.980	9171.780	.000	156.423	326.001	.000	18.48	1.99	2890.595	648.042	3538.637

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	14.698	6.329	4.554	140.915	149.354	8.43	.000	149.354	149.354	142.589
12-03	13.965	5.309	4.218	134.497	132.932	8.82	.000	132.932	282.286	257.958
12-04	13.079	4.372	3.756	122.954	119.271	9.02	.000	119.271	401.557	352.057
12-05	12.398	3.956	3.468	119.768	106.934	9.35	.000	106.934	508.491	428.755
12-06	11.355	3.672	3.029	109.741	95.545	9.43	.000	95.545	604.036	491.055
12-07	9.498	3.351	2.148	80.280	86.567	8.55	.000	86.567	690.604	542.361
12-08	9.069	2.895	2.005	76.946	78.829	8.82	.000	78.829	769.433	584.835
12-09	8.626	2.063	1.825	68.239	72.044	8.94	.000	72.044	841.477	620.123
12-10	8.257	1.957	1.739	68.239	65.804	9.30	.000	65.804	907.281	649.424
12-11	7.904	1.801	1.638	67.571	59.857	9.64	.000	59.857	967.138	673.656
12-12	7.567	1.547	1.502	65.566	54.286	9.94	.000	54.286	1021.424	693.634
12-13	7.245	1.468	1.434	65.566	49.013	10.34	.000	49.013	1070.437	710.033
S TOT	123.660	38.719	31.316	1120.282	1070.437	15.58	.000	1070.437	1070.437	710.033
AFTER	69.197	11.811	12.803	708.715	351.699	15.58	.000	351.699	1422.135	776.605
TOTAL	192.857	50.530	44.118	1828.997	1422.135	15.58	.000	1422.135	1422.135	776.605

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	269.0	105.0	LIFE, YRS.	59.08	8.00	853.075
GROSS ULT., MB & MMF	38004.780	369792.100	DISCOUNT %	10.00	10.00	776.605
GROSS CUM., MB & MMF	37371.800	360620.400	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	713.432
GROSS RES., MB & MMF	632.980	9171.780	DISCOUNTED PAYOUT, YRS.	.00	15.00	637.030
NET RES., MB & MMF	156.423	326.001	UNDISCOUNTED NET/INVEST.	.00	20.00	542.969
NET REVENUE, M$	2890.595	648.042	DISCOUNTED NET/INVEST.	.00	25.00	475.454
INITIAL PRICE, $	16.773	1.968	RATE-OF-RETURN, PCT.	100.00	35.00	385.125
INITIAL N.I., PCT.	17.125	-.608	INITIAL W.I., PCT.	20.934	50.00	305.748
					70.00	245.755
					100.00	195.966

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	09:55:27
PUD RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.7	1.667	78.766	.000	.053	.282	.000	18.35	2.42	.979	.682	1.660
12-04	2.0	10.771	122.682	.000	.458	1.524	.000	18.34	2.34	8.406	3.570	11.976
12-05	2.0	7.682	81.787	.000	.329	1.083	.000	18.34	2.34	6.026	2.534	8.560
12-06	2.0	6.315	57.126	.000	.273	.882	.000	18.34	2.34	5.008	2.061	7.070
12-07	2.0	5.489	41.285	.000	.240	.761	.000	18.34	2.33	4.398	1.774	6.172
12-08	2.0	4.928	31.749	.000	.217	.679	.000	18.34	2.33	3.979	1.581	5.560
12-09	2.0	4.536	28.424	.000	.200	.624	.000	18.34	2.33	3.667	1.454	5.121
12-10	2.0	4.233	26.032	.000	.187	.582	.000	18.34	2.33	3.424	1.356	4.780
12-11	1.2	3.910	13.268	.000	.175	.529	.000	18.34	2.32	3.217	1.227	4.445
12-12	1.0	3.662	10.986	.000	.165	.495	.000	18.34	2.32	3.024	1.148	4.171
12-13	1.0	3.442	10.327	.000	.155	.465	.000	18.34	2.32	2.842	1.079	3.921
S TOT	1.0	56.636	502.431	.000	2.452	7.906	.000	18.34	2.34	44.971	18.466	63.437
AFTER	1.0	10.277	30.830	.000	.463	1.388	.000	18.34	2.32	8.486	3.220	11.706
TOTAL	1.0	66.913	533.262	.000	2.915	9.294	.000	18.34	2.33	53.457	21.687	75.144

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.068	.053	.022	.100	1.418	2.42	.000	1.418	1.418	1.182
12-04	.588	.284	.119	1.088	9.898	2.92	.000	9.898	11.315	9.017
12-05	.422	.201	.084	1.088	6.765	3.53	.000	6.765	18.080	13.875
12-06	.350	.164	.069	1.088	5.398	3.98	.000	5.398	23.478	17.397
12-07	.308	.141	.059	1.088	4.575	4.36	.000	4.575	28.053	20.110
12-08	.278	.126	.053	1.088	4.014	4.68	.000	4.014	32.068	22.273
12-09	.257	.116	.049	1.088	3.612	4.97	.000	3.612	35.680	24.042
12-10	.240	.108	.045	1.088	3.299	5.22	.000	3.299	38.978	25.511
12-11	.225	.098	.041	1.072	3.008	5.45	.000	3.008	41.986	26.729
12-12	.212	.092	.039	1.069	2.760	5.71	.000	2.760	44.746	27.745
12-13	.199	.086	.036	1.069	2.531	5.98	.000	2.531	47.277	28.591
S TOT	3.146	1.470	.616	10.928	47.277	7.17	.000	47.277	47.277	28.591
AFTER	.594	.258	.109	3.653	7.093	7.17	.000	7.093	54.370	30.537
TOTAL	3.740	1.728	.724	14.581	54.370	7.17	.000	54.370	54.370	30.537

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	1.0	LIFE, YRS.	15.42	8.00	33.822
GROSS ULT., MB & MMF	66.913	565.183	DISCOUNT %	10.00	10.00	30.537
GROSS CUM., MB & MMF	.000	31.921	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	27.722
GROSS RES., MB & MMF	66.913	533.262	DISCOUNTED PAYOUT, YRS.	.00	15.00	24.201
NET RES., MB & MMF	2.915	9.294	UNDISCOUNTED NET/INVEST.	.00	20.00	19.711
NET REVENUE, M$	53.457	21.687	DISCOUNTED NET/INVEST.	.00	25.00	16.410
INITIAL PRICE, $	18.374	2.490	RATE-OF-RETURN, PCT.	100.00	35.00	11.956
INITIAL N.I., PCT.	4.225	1.148	INITIAL W.I., PCT.	2.737	50.00	8.109
					70.00	5.352
					100.00	3.272

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	10:12:05
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	95.0	70.442	1094.177	.000	12.425	25.261	.000	18.33	1.86	227.790	46.980	274.770
12-03	95.1	66.990	1007.276	.000	11.862	23.798	.000	18.34	1.86	217.525	44.314	261.839
12-04	96.0	71.749	955.151	.000	11.684	23.548	.000	18.34	1.89	214.324	44.393	258.717
12-05	96.0	64.986	876.815	.000	11.004	21.825	.000	18.35	1.88	201.892	40.998	242.891
12-06	93.8	55.039	811.315	.000	9.863	20.437	.000	18.39	1.88	181.367	38.331	219.698
12-07	87.0	36.434	754.005	.000	7.738	19.215	.000	18.53	1.87	143.421	36.004	179.425
12-08	68.8	32.694	551.844	.000	7.373	16.553	.000	18.54	1.87	136.683	31.014	167.697
12-09	14.0	26.667	77.033	.000	7.003	11.123	.000	18.55	1.88	129.871	20.887	150.758
12-10	14.0	25.340	72.417	.000	6.697	10.569	.000	18.55	1.88	124.201	19.834	144.035
12-11	14.0	24.112	68.182	.000	6.406	10.047	.000	18.55	1.88	118.810	18.846	137.656
12-12	14.0	22.947	64.214	.000	6.128	9.551	.000	18.55	1.87	113.661	17.909	131.570
12-13	14.0	21.844	60.497	.000	5.862	9.082	.000	18.55	1.87	108.742	17.021	125.763
S TOT	1.1	519.246	6392.925	.000	104.046	201.007	.000	18.44	1.87	1918.287	376.531	2294.818
AFTER	1.1	168.742	397.275	.000	54.490	64.592	.000	18.55	1.97	1010.645	127.158	1137.803
TOTAL	1.1	687.988	6790.201	.000	158.535	265.599	.000	18.47	1.90	2928.932	503.689	3432.621

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASH FLOW M$	CUM CASH FLOW M$	10.0% CUM DISC CF M$
12-02	14.345	3.717	3.739	113.752	139.218	8.15	.000	139.218	139.218	132.891
12-03	13.728	3.505	3.545	113.841	127.219	8.50	.000	127.219	266.438	243.249
12-04	13.600	3.514	3.447	114.821	123.336	8.67	.000	123.336	389.773	340.578
12-05	12.819	3.244	3.235	114.821	108.772	9.16	.000	108.772	498.545	418.599
12-06	11.705	3.033	2.814	105.446	96.700	9.27	.000	96.700	595.245	481.654
12-07	9.806	2.848	1.972	77.319	87.480	8.40	.000	87.480	682.725	533.502
12-08	9.347	2.451	1.847	74.417	79.635	8.69	.000	79.635	762.360	576.410
12-09	8.882	1.642	1.675	65.710	72.849	8.80	.000	72.849	835.209	612.091
12-10	8.496	1.560	1.598	65.710	66.672	9.15	.000	66.672	901.881	641.778
12-11	8.129	1.482	1.525	65.710	60.810	9.51	.000	60.810	962.691	666.395
12-12	7.779	1.408	1.456	65.710	55.217	9.89	.000	55.217	1017.908	686.716
12-13	7.443	1.338	1.390	65.710	49.881	10.29	.000	49.881	1067.789	703.406
S TOT	126.079	29.742	28.241	1042.967	1067.789	15.58	.000	1067.789	1067.789	703.406
AFTER	69.791	9.959	12.131	697.638	348.285	15.58	.000	348.285	1416.074	769.693
TOTAL	195.869	39.701	40.371	1740.606	1416.074	15.58	.000	1416.074	1416.074	769.693

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	260.0	75.0	LIFE, YRS.	59.08	8.00	846.495
GROSS ULT., MB & MMF	23853.650	142574.600	DISCOUNT %	10.00	10.00	769.693
GROSS CUM., MB & MMF	23165.660	135784.400	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	706.198
GROSS RES., MB & MMF	687.988	6790.201	DISCOUNTED PAYOUT, YRS.	.00	15.00	629.358
NET RES., MB & MMF	158.535	265.599	UNDISCOUNTED NET/INVEST.	.00	20.00	534.716
NET REVENUE, M$	2928.931	503.689	DISCOUNTED NET/INVEST.	.00	25.00	466.792
INITIAL PRICE, $	16.770	1.890	RATE-OF-RETURN, PCT.	100.00	35.00	376.019
INITIAL N.I., PCT.	17.143	2.365	INITIAL W.I., PCT.	12.753	50.00	296.481
					70.00	236.649
					100.00	187.308

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	10:12:04
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	95.0	70.442	1094.177	.000	12.425	25.261	.000	18.33	1.86	227.790	46.980	274.770
12-03	95.0	65.824	1003.777	.000	11.810	23.640	.000	18.34	1.86	216.562	43.984	260.511
12-04	95.0	61.593	924.682	.000	11.227	22.176	.000	18.34	1.86	205.938	41.210	247.148
12-05	95.0	57.703	854.966	.000	10.676	20.841	.000	18.35	1.86	195.879	38.716	234.595
12-06	92.8	48.984	793.149	.000	9.591	19.619	.000	18.39	1.86	176.367	36.434	212.800
12-07	86.0	31.114	738.044	.000	7.499	18.496	.000	18.54	1.86	139.028	34.336	173.365
12-08	67.8	27.880	537.402	.000	7.156	15.902	.000	18.54	1.86	132.707	29.506	162.213
12-09	13.0	22.229	63.720	.000	6.803	10.524	.000	18.55	1.85	126.207	19.497	145.703
12-10	13.0	21.196	59.986	.000	6.510	10.009	.000	18.55	1.85	120.779	18.536	139.315
12-11	13.0	20.216	56.494	.000	6.230	9.520	.000	18.55	1.85	115.593	17.625	133.218
12-12	13.0	19.285	53.227	.000	5.963	9.057	.000	18.55	1.85	110.637	16.761	127.398
12-13	13.0	18.402	50.170	.000	5.707	8.617	.000	18.56	1.85	105.900	15.942	121.842
S TOT	1.1	464.869	6229.794	.000	101.597	193.663	.000	18.44	1.86	1873.387	359.491	2232.878
AFTER	1.1	158.465	366.445	.000	54.027	63.204	.000	18.55	1.96	1002.159	123.938	1126.097
TOTAL	1.1	623.334	6596.239	.000	155.624	256.866	.000	18.48	1.88	2875.546	483.429	3358.975

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	14.345	3.717	3.739	113.752	139.218	8.15	.000	139.218	139.218	132.891
12-03	13.661	3.476	3.532	113.752	126.089	8.53	.000	126.089	265.307	242.311
12-04	13.013	3.259	3.339	113.752	113.785	8.94	.000	113.785	379.092	332.080
12-05	12.398	3.062	3.158	113.752	102.225	9.36	.000	102.225	481.317	405.400
12-06	11.355	2.881	2.750	104.377	91.438	9.44	.000	91.438	572.755	465.021
12-07	9.498	2.715	1.915	76.250	82.986	8.54	.000	82.986	655.740	514.204
12-08	9.069	2.330	1.796	73.348	75.670	8.82	.000	75.670	731.411	554.975
12-09	8.626	1.531	1.628	64.641	69.278	8.93	.000	69.278	800.689	588.907
12-10	8.257	1.456	1.554	64.641	63.408	9.28	.000	63.408	864.097	617.142
12-11	7.904	1.384	1.484	64.641	57.805	9.65	.000	57.805	921.902	640.542
12-12	7.567	1.316	1.417	64.641	52.457	10.03	.000	52.457	974.358	659.848
12-13	7.245	1.252	1.353	64.641	47.351	10.43	.000	47.351	1021.709	675.691
S TOT	122.936	28.379	27.666	1032.188	1021.709	15.58	.000	1021.709	1021.709	675.691
AFTER	69.197	9.701	12.022	693.986	341.191	15.58	.000	341.191	1362.900	740.032
TOTAL	192.132	38.080	39.688	1726.174	1362.900	15.58	.000	1362.900	1362.900	740.032

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	259.0	75.0	LIFE, YRS.	59.08	8.00	813.601
GROSS ULT., MB & MMF	23788.990	142348.700	DISCOUNT %	10.00	10.00	740.032
GROSS CUM., MB & MMF	23165.660	135752.500	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	679.304
GROSS RES., MB & MMF	623.334	6596.240	DISCOUNTED PAYOUT, YRS.	.00	15.00	605.921
NET RES., MB & MMF	155.624	256.866	UNDISCOUNTED NET/INVEST.	.00	20.00	515.678
NET REVENUE, M$	2875.545	483.429	DISCOUNTED NET/INVEST.	.00	25.00	450.980
INITIAL PRICE, $	16.631	1.874	RATE-OF-RETURN, PCT.	100.00	35.00	364.546
INITIAL N.I., PCT.	18.262	2.287	INITIAL W.I., PCT.	13.294	50.00	288.737
					70.00	231.564
					100.00	184.219

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	10:12:04
PUD RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.1	1.166	3.498	.000	.053	.158	.000	18.34	2.32	.963	.365	1.328
12-04	1.0	10.156	30.469	.000	.457	1.372	.000	18.34	2.32	8.386	3.183	11.569
12-05	1.0	7.283	21.849	.000	.328	.984	.000	18.34	2.32	6.014	2.282	8.296
12-06	1.0	6.055	18.166	.000	.273	.818	.000	18.34	2.32	5.000	1.898	6.898
12-07	1.0	5.320	15.961	.000	.240	.719	.000	18.34	2.32	4.393	1.667	6.060
12-08	1.0	4.814	14.443	.000	.217	.650	.000	18.34	2.32	3.975	1.509	5.484
12-09	1.0	4.438	13.313	.000	.200	.599	.000	18.34	2.32	3.664	1.391	5.055
12-10	1.0	4.144	12.431	.000	.187	.560	.000	18.34	2.32	3.422	1.298	4.720
12-11	1.0	3.896	11.688	.000	.175	.526	.000	18.34	2.32	3.217	1.221	4.438
12-12	1.0	3.662	10.986	.000	.165	.495	.000	18.34	2.32	3.024	1.148	4.171
12-13	1.0	3.442	10.327	.000	.155	.465	.000	18.34	2.32	2.842	1.079	3.921
S TOT	1.0	54.377	163.131	.000	2.448	7.345	.000	18.34	2.32	44.900	17.040	61.940
AFTER	1.0	10.277	30.830	.000	.463	1.388	.000	18.34	2.32	8.486	3.220	11.706
TOTAL	1.0	64.654	193.961	.000	2.911	8.733	.000	18.34	2.32	53.386	20.260	73.646

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.067	.029	.012	.089	1.130	2.51	.000	1.130	1.130	.938
12-04	.587	.255	.107	1.069	9.551	2.94	.000	9.551	10.681	8.498
12-05	.421	.183	.077	1.069	6.546	3.56	.000	6.546	17.228	13.199
12-06	.350	.152	.064	1.069	5.263	4.00	.000	5.263	22.491	16.633
12-07	.308	.133	.056	1.069	4.494	4.36	.000	4.494	26.985	19.297
12-08	.278	.121	.051	1.069	3.965	4.67	.000	3.965	30.950	21.434
12-09	.256	.111	.047	1.069	3.571	4.95	.000	3.571	34.521	23.183
12-10	.240	.104	.044	1.069	3.264	5.20	.000	3.264	37.785	24.637
12-11	.225	.098	.041	1.069	3.005	5.45	.000	3.005	40.789	25.853
12-12	.212	.092	.039	1.069	2.760	5.71	.000	2.760	43.550	26.869
12-13	.199	.086	.036	1.069	2.531	5.98	.000	2.531	46.080	27.715
S TOT	3.143	1.363	.574	10.779	46.080	7.17	.000	46.080	46.080	27.715
AFTER	.594	.258	.109	3.653	7.093	7.17	.000	7.093	53.174	29.661
TOTAL	3.737	1.621	.683	14.432	53.174	7.17	.000	53.174	53.174	29.661

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	15.42	8.00	32.894
GROSS ULT., MB & MMF	64.654	225.882	DISCOUNT %	10.00	10.00	29.661
GROSS CUM., MB & MMF	.000	31.921	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	26.894
GROSS RES., MB & MMF	64.654	193.961	DISCOUNTED PAYOUT, YRS.	.00	15.00	23.437
NET RES., MB & MMF	2.911	8.733	UNDISCOUNTED NET/INVEST.	.00	20.00	19.038
NET REVENUE, M$	53.386	20.260	DISCOUNTED NET/INVEST.	.00	25.00	15.812
INITIAL PRICE, $	18.340	2.320	RATE-OF-RETURN, PCT.	100.00	35.00	11.473
INITIAL N.I., PCT.	4.502	4.502	INITIAL W.I., PCT.	5.469	50.00	7.744
					70.00	5.085
					100.00	3.089

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	10:19:20
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS OIL PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	30.7	5.522	703.859	.000	.384	16.459	.000	18.78	2.06	7.207	33.873	41.080
12-03	19.1	4.116	457.677	.000	.339	11.023	.000	18.88	2.21	6.411	24.332	30.743
12-04	7.3	1.124	221.878	.000	.077	6.060	.000	18.99	2.51	1.466	15.225	16.691
12-05	6.3	.399	178.381	.000	.001	4.796	.000	18.88	2.54	.012	12.181	12.193
12-06	6.0	.260	149.424	.000	.000	4.196	.000	18.88	2.55	.008	10.706	10.714
12-07	3.8	.169	120.961	.000	.000	3.419	.000	18.88	2.51	.005	8.586	8.591
12-08	3.0	.114	104.594	.000	.000	3.049	.000	18.88	2.49	.004	7.603	7.607
12-09	3.0	.099	97.114	.000	.000	2.870	.000	18.88	2.49	.003	7.156	7.159
12-10	3.0	.089	90.638	.000	.000	2.702	.000	18.88	2.49	.003	6.737	6.740
12-11	1.9	.014	73.079	.000	.000	2.212	.000	18.88	2.51	.000	5.559	5.559
12-12	1.0	.000	64.616	.000	.000	1.163	.000	.00	2.64	.000	3.070	3.070
12-13	1.0	.000	60.686	.000	.000	1.092	.000	.00	2.64	.000	2.884	2.884
S TOT	1.0	11.905	2322.908	.000	.802	59.042	.000	18.85	2.34	15.120	137.913	153.033
AFTER	1.0	.000	591.934	.000	.000	10.654	.000	.00	2.64	.000	28.127	28.127
TOTAL	1.0	11.905	2914.842	.000	.802	69.697	.000	18.85	2.38	15.120	166.040	181.159

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.353	2.613	.815	27.163	10.136	9.90	.000	10.136	10.136	9.698
12-03	.305	1.856	.695	20.757	7.130	10.85	.000	7.130	17.266	15.891
12-04	.067	1.142	.428	9.221	5.833	9.99	.000	5.833	23.099	20.495
12-05	.001	.914	.317	6.035	4.927	9.08	.000	4.927	28.026	24.031
12-06	.000	.803	.284	5.384	4.243	9.25	.000	4.243	32.269	26.798
12-07	.000	.644	.235	4.048	3.663	8.64	.000	3.663	35.932	28.970
12-08	.000	.570	.211	3.617	3.209	8.65	.000	3.209	39.140	30.699
12-09	.000	.537	.199	3.617	2.807	9.10	.000	2.807	41.947	32.074
12-10	.000	.505	.187	3.617	2.431	9.56	.000	2.431	44.378	33.157
12-11	.000	.417	.154	2.933	2.055	9.50	.000	2.055	46.433	33.990
12-12	.000	.230	.085	.925	1.829	6.40	.000	1.829	48.262	34.663
12-13	.000	.216	.080	.925	1.662	6.71	.000	1.662	49.924	35.219
S TOT	.728	10.447	3.691	88.243	49.924	15.46	.000	49.924	49.924	35.219
AFTER	.000	2.110	.781	14.729	10.508	15.46	.000	10.508	60.432	37.449
TOTAL	.728	12.556	4.472	102.972	60.432	15.46	.000	60.432	60.432	37.449

	OIL	GAS			P.W. %	P.W, M$
GROSS WELLS	10.0	31.0	LIFE, YRS.	27.92	8.00	40.402
GROSS ULT., MB & MMF	14218.040	227782.700	DISCOUNT %	10.00	10.00	37.449
GROSS CUM., MB & MMF	14206.140	224867.800	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	34.956
GROSS RES., MB & MMF	11.905	2914.842	DISCOUNTED PAYOUT, YRS.	.00	15.00	31.873
NET RES., MB & MMF	.802	69.697	UNDISCOUNTED NET/INVEST.	.00	20.00	27.964
NET REVENUE, M$	15.120	166.040	DISCOUNTED NET/INVEST.	.00	25.00	25.071
INITIAL PRICE, $	18.651	2.128	RATE-OF-RETURN, PCT.	100.00	35.00	21.062
INITIAL N.I., PCT.	2.034	-3.310	INITIAL W.I., PCT.	31.280	50.00	17.376
					70.00	14.459
					100.00	11.930

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	10:19:20
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD   MMCF	GROSS NGL PROD   MBBLS	NET OIL PROD   MBBLS	NET GAS PROD   MMCF	NET NGL PROD   MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES   M$
12-02	30.7	5.522	703.859	.000	.384	16.459	.000	18.78	2.06	7.207	33.873	41.080
12-03	18.5	3.614	382.409	.000	.339	10.898	.000	18.88	2.20	6.395	24.016	30.411
12-04	6.3	.510	129.665	.000	.076	5.908	.000	18.99	2.51	1.447	14.837	16.284
12-05	5.3	.000	118.442	.000	.000	4.697	.000	.00	2.54	.000	11.929	11.929
12-06	5.0	.000	110.464	.000	.000	4.131	.000	.00	2.55	.000	10.542	10.542
12-07	2.8	.000	95.637	.000	.000	3.377	.000	.00	2.51	.000	8.479	8.479
12-08	2.0	.000	87.288	.000	.000	3.020	.000	.00	2.49	.000	7.531	7.531
12-09	2.0	.000	82.003	.000	.000	2.845	.000	.00	2.49	.000	7.093	7.093
12-10	2.0	.000	77.038	.000	.000	2.680	.000	.00	2.49	.000	6.680	6.680
12-11	1.8	.000	71.499	.000	.000	2.210	.000	.00	2.51	.000	5.552	5.552
12-12	1.0	.000	64.616	.000	.000	1.163	.000	.00	2.64	.000	3.070	3.070
12-13	1.0	.000	60.686	.000	.000	1.092	.000	.00	2.64	.000	2.884	2.884
S TOT	1.0	9.646	1983.608	.000	.799	58.481	.000	18.85	2.33	15.049	136.486	151.535
AFTER	1.0	.000	591.934	.000	.000	10.654	.000	.00	2.64	.000	28.127	28.127
TOTAL	1.0	9.646	2575.542	.000	.799	69.135	.000	18.85	2.38	15.049	164.613	179.662

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.353	2.613	.815	27.163	10.136	9.90	.000	10.136	10.136	9.698
12-03	.304	1.833	.686	20.746	6.843	10.94	.000	6.843	16.979	15.647
12-04	.067	1.113	.417	9.202	5.486	10.18	.000	5.486	22.465	19.977
12-05	.000	.895	.310	6.016	4.708	9.22	.000	4.708	27.174	23.355
12-06	.000	.791	.279	5.364	4.108	9.34	.000	4.108	31.281	26.034
12-07	.000	.636	.232	4.029	3.582	8.70	.000	3.582	34.863	28.157
12-08	.000	.565	.209	3.598	3.159	8.69	.000	3.159	38.022	29.860
12-09	.000	.532	.197	3.598	2.766	9.12	.000	2.766	40.788	31.215
12-10	.000	.501	.185	3.598	2.396	9.59	.000	2.396	43.184	32.283
12-11	.000	.416	.154	2.930	2.052	9.50	.000	2.052	45.236	33.114
12-12	.000	.230	.085	.925	1.829	6.40	.000	1.829	47.066	33.787
12-13	.000	.216	.080	.925	1.662	6.71	.000	1.662	48.728	34.343
S TOT	.724	10.340	3.649	88.094	48.728	15.46	.000	48.728	48.728	34.343
AFTER	.000	2.110	.781	14.729	10.508	15.46	.000	10.508	59.235	36.573
TOTAL	.724	12.449	4.430	102.823	59.235	15.46	.000	59.235	59.235	36.573

	OIL	GAS			P.W. %	P.W. M$
GROSS WELLS	10.0	30.0	LIFE, YRS.	27.92	8.00	39.474
GROSS ULT., MB & MMF	14215.780	227443.400	DISCOUNT %	10.00	10.00	36.573
GROSS CUM., MB & MMF	14206.140	224867.800	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	34.128
GROSS RES., MB & MMF	9.646	2575.542	DISCOUNTED PAYOUT, YRS.	.00	15.00	31.109
NET RES., MB & MMF	.799	69.135	UNDISCOUNTED NET/INVEST.	.00	20.00	27.292
NET REVENUE, M$	15.049	164.613	DISCOUNTED NET/INVEST.	.00	25.00	24.473
INITIAL PRICE, $	18.632	2.071	RATE-OF-RETURN, PCT.	100.00	35.00	20.580
INITIAL N.I., PCT.	2.182	-3.791	INITIAL W.I., PCT.	36.290	50.00	17.010
					70.00	14.191
					100.00	11.747

SW OIL & GAS INCOME FUND X-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	10:19:20
PUD RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.6	.501	75.267	.000	.001	.125	.000	18.88	2.54	.016	.316	.332
12-04	1.0	.614	92.213	.000	.001	.153	.000	18.88	2.54	.019	.388	.407
12-05	1.0	.399	59.938	.000	.001	.099	.000	18.88	2.54	.012	.252	.265
12-06	1.0	.260	38.960	.000	.000	.064	.000	18.88	2.54	.008	.164	.172
12-07	1.0	.169	25.324	.000	.000	.042	.000	18.88	2.54	.005	.106	.112
12-08	1.0	.114	17.306	.000	.000	.029	.000	18.88	2.54	.004	.073	.076
12-09	1.0	.099	15.112	.000	.000	.025	.000	18.88	2.54	.003	.064	.067
12-10	1.0	.089	13.600	.000	.000	.023	.000	18.88	2.54	.003	.057	.060
12-11	1.0	.014	1.580	.000	.000	.003	.000	18.88	2.54	.000	.007	.007
12-12
12-13
S TOT	1.0	2.259	339.300	.000	.004	.562	.000	18.88	2.54	.071	1.427	1.497
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	2.259	339.300	.000	.004	.562	.000	18.88	2.54	.071	1.427	1.497

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.001	.024	.009	.011	.287	2.08	.000	.287	.287	.244
12-04	.001	.029	.011	.019	.346	2.28	.000	.346	.634	.519
12-05	.001	.019	.007	.019	.219	2.68	.000	.219	.852	.676
12-06	.000	.012	.005	.019	.135	3.28	.000	.135	.988	.764
12-07	.000	.008	.003	.019	.081	4.20	.000	.081	1.069	.813
12-08	.000	.005	.002	.019	.049	5.42	.000	.049	1.118	.839
12-09	.000	.005	.002	.019	.041	5.99	.000	.041	1.159	.859
12-10	.000	.004	.002	.019	.035	6.48	.000	.035	1.194	.875
12-11	.000	.000	.000	.003	.003	8.52	.000	.003	1.197	.876
12-12
12-13
S TOT	.003	.107	.042	.149	1.197	8.52	.000	1.197	1.197	.876
AFTER	.000	.000	.000	.000	.000	8.52	.000	.000	1.197	.876
TOTAL	.003	.107	.042	.149	1.197	8.52	.000	1.197	1.197	.876

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	.0	1.0	LIFE, YRS.	9.17	8.00	.928
GROSS ULT., MB & MMF	2.259	339.300	DISCOUNT %	10.00	10.00	.876
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	.828
GROSS RES., MB & MMF	2.259	339.300	DISCOUNTED PAYOUT, YRS.	.00	15.00	.764
NET RES., MB & MMF	.004	.562	UNDISCOUNTED NET/INVEST.	.00	20.00	.673
NET REVENUE, M$	.071	1.427	DISCOUNTED NET/INVEST.	.00	25.00	.598
INITIAL PRICE, $	18.880	2.540	RATE-OF-RETURN, PCT.	100.00	35.00	.482
INITIAL N.I., PCT.	.166	.166	INITIAL W.I., PCT.	.205	50.00	.365
					70.00	.268
					100.00	.183

APPENDIX B13

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWR Inst Income Fund X-B (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 22 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 91.4 percent of the total net remaining liquid hydrocarbon reserves and 85.4 percent of the total net remaining gas reserves. The properties that we reviewed represent 90.6 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWR Inst Income Fund X-B

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		175,174		128		2,911		178,213
Gas—MMCF		517		0		9		526
Income Data
Future Gross Revenue	$	3,802,244	$	2,824	$	68,288	$	3,873,356
Deductions		2,110,065		598		15,115		2,125,778
Future Net Income (FNI)	$	1,692,179	$	2,226	$	53,173	$	1,747,578
Discounted FNI @ 10%	$	949,967	$	1,770	$	29,661	$	981,398

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		16,775		0		4		16,779
Gas—MMCF		89		0		1		90
Income Data
Future Gross Revenue	$	513,198	$	0	$	1,387	$	514,585
Deductions		366,334		0		191		366,525
Future Net Income (FNI)	$	146,864	$	0	$	1,196	$	148,060
Discounted FNI @ 10%	$	100,423	$	0	$	876	$	101,299
Total Net Reserves
Oil/Condensate—Barrels		191,949		128		2,915		194,992
Gas—MMCF		606		0		10		616
Income Data
Future Gross Revenue	$	4,315,442	$	2,824	$	69,675	$	4,387,941
Deductions		2,476,399		598		15,306		2,492,303
Future Net Income (FNI)	$	1,839,043	$	2,226	$	54,369	$	1,895,638
Discounted FNI @ 10%	$	1,050,390	$	1,770	$	30,537	$	1,082,697

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? . . . The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Companies should report reserves of natural gas liquids which are net to their leasehold interest i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 8.6 percent of the total net remaining liquid hydrocarbon reserves and 14.6 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SWR INST INCOME FUND X-B PROPERTIES REV BY RYDER SCOTT TOTAL PROVED RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:44 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES   M$	TOTAL NET SALES M$
12-02	103.0	94.936	1451.096	.000	16.118	49.216	.000	18.18	1.65	293.099	80.962	374.062
12-03	104.4	96.103	1350.094	.000	15.328	45.841	.000	18.19	1.65	278.836	75.692	354.527
12-04	106.0	99.177	1271.066	.000	14.915	43.749	.000	18.20	1.67	271.466	73.156	344.622
12-05	105.4	87.216	1160.320	.000	13.996	40.286	.000	18.21	1.67	254.808	67.236	322.043
12-06	102.5	73.337	1066.707	.000	12.162	37.307	.000	18.25	1.67	221.994	62.268	284.262
12-07	95.0	51.781	984.940	.000	8.487	34.631	.000	18.45	1.67	156.580	57.846	214.426
12-08	76.8	46.917	763.546	.000	8.070	31.029	.000	18.46	1.67	148.932	51.681	200.613
12-09	20.5	38.199	262.282	.000	7.619	25.252	.000	18.46	1.63	140.644	41.263	181.907
12-10	20.0	35.441	239.666	.000	7.254	23.455	.000	18.46	1.63	133.907	38.344	172.251
12-11	20.0	33.485	221.515	.000	6.922	21.855	.000	18.46	1.64	127.800	35.808	163.608
12-12	19.3	30.324	204.400	.000	6.539	20.352	.000	18.48	1.64	120.830	33.428	154.258
12-13	16.0	22.321	187.134	.000	5.921	18.884	.000	18.54	1.65	109.799	31.122	140.921
S TOT	1.1	709.238	9162.764	.000	123.330	391.857	.000	18.31	1.66	2258.695	648.806	2907.501
AFTER	1.1	171.915	1342.616	.000	54.883	133.828	.000	18.54	1.70	1017.687	227.480	1245.167
TOTAL	1.1	881.153	10505.380	.000	178.213	525.684	.000	18.38	1.67	3276.383	876.286	4152.669

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX   M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW   M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	17.337	6.242	6.429	155.520	188.534	7.63	.000	188.534	188.534	179.987
12-03	16.538	5.838	6.054	155.734	170.364	8.02	.000	170.364	358.897	327.790
12-04	16.219	5.652	5.770	156.776	160.205	8.30	.000	160.205	519.102	454.222
12-05	15.244	5.194	5.374	156.721	139.510	8.81	.000	139.510	658.612	554.305
12-06	13.566	4.812	4.584	139.345	121.956	8.83	.000	121.956	780.568	633.839
12-07	10.404	4.471	3.017	87.332	109.202	7.38	.000	109.202	889.770	698.564
12-08	9.906	3.990	2.815	85.131	98.771	7.69	.000	98.771	988.541	751.786
12-09	9.378	3.170	2.548	77.289	89.522	7.81	.000	89.522	1078.063	795.637
12-10	8.943	2.948	2.389	76.862	81.109	8.16	.000	81.109	1159.172	831.756
12-11	8.543	2.754	2.253	76.862	73.196	8.56	.000	73.196	1232.368	861.389
12-12	8.108	2.572	2.092	75.762	65.724	8.91	.000	65.724	1298.092	885.579
12-13	7.492	2.396	1.811	70.262	58.959	9.04	.000	58.959	1357.051	905.307
S  TOT	141.677	50.039	45.138	1313.597	1357.051	15.58	.000	1357.051	1357.051	905.307
AFTER	70.115	17.483	15.116	751.927	390.527	15.58	.000	390.527	1747.577	981.397
TOTAL	211.792	67.522	60.254	2065.524	1747.578	15.58	.000	1747.578	1747.577	981.397

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	29.0	77.0	LIFE, YRS.	59.08	8.00	1074.425
GROSS ULT., MB & MMF	11417.570	152938.300	DISCOUNT %	10.00	10.00	981.397
GROSS CUM., MB & MMF	10536.410	142432.900	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	904.000
GROSS RES., MB & MMF	881.153	10505.380	DISCOUNTED PAYOUT, YRS.	.00	15.00	809.709
NET RES., MB & MMF	178.213	525.684	UNDISCOUNTED NET/INVEST.	.00	20.00	692.560
NET REVENUE, M$	3276.383	876.285	DISCOUNTED NET/INVEST.	.00	25.00	607.735
INITIAL PRICE, $	18.026	1.873	RATE-OF-RETURN, PCT.	100.00	35.00	493.282
INITIAL N.I., PCT.	13.516	3.354	INITIAL W.I., PCT.	9.199	50.00	391.823
					70.00	314.659
					100.00	250.397

SWR INST INCOME FUND X-B PROPERTIES REV BY RYDER SCOTT PDP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:43 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD   MMCF	GROSS NGL PROD   MBBLS	NET OIL PROD   MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M$	NET GAS SALES   M$	TOTAL NET SALES   M$
12-02	103.0	94.936	1451.096	.000	16.118	49.216	.000	18.18	1.65	293.099	80.962	374.062
12-03	103.0	87.093	1330.907	.000	15.230	45.592	.000	18.19	1.65	277.046	75.088	352.134
12-04	103.0	80.982	1224.520	.000	14.411	42.283	.000	18.20	1.65	262.232	69.729	331.962
12-05	103.0	75.597	1129.800	.000	13.643	39.251	.000	18.20	1.65	248.337	64.822	313.159
12-06	100.8	65.549	1045.074	.000	11.879	36.469	.000	18.25	1.65	216.811	60.318	277.129
12-07	94.0	46.461	968.979	.000	8.247	33.912	.000	18.45	1.66	152.187	56.179	208.366
12-08	75.8	42.103	749.103	.000	7.853	30.379	.000	18.46	1.65	144.957	50.172	195.129
12-09	19.5	33.762	248.970	.000	7.420	24.653	.000	18.46	1.62	136.980	39.873	176.853
12-10	19.0	31.297	227.235	.000	7.067	22.895	.000	18.46	1.62	130.485	37.045	167.531
12-11	19.0	29.589	209.828	.000	6.746	21.329	.000	18.47	1.62	124.583	34.587	159.170
12-12	18.3	26.662	193.413	.000	6.374	19.858	.000	18.48	1.63	117.806	32.280	150.087
12-13	15.0	18.878	176.807	.000	5.766	18.419	.000	18.55	1.63	106.956	30.044	137.000
S TOT	1.1	632.909	8955.731	.000	120.754	384.256	.000	18.31	1.64	2211.481	631.100	2842.582
AFTER	1.1	161.638	1311.785	.000	54.420	132.440	.000	18.54	1.69	1009.202	224.260	1233.461
TOTAL	1.1	794.548	10267.520	.000	175.174	516.695	.000	18.39	1.66	3220.683	855.360	4076.043

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW   M$	10.0% CUM DISC CF   M$
12-02	17.337	6.242	6.429	155.520	188.534	7.63	.000	188.534	188.534	179.987
12-03	16.432	5.791	6.012	155.520	168.379	8.05	.000	168.379	356.913	326.122
12-04	15.593	5.379	5.632	155.520	149.838	8.49	.000	149.838	506.751	444.347
12-05	14.802	5.002	5.280	155.520	132.554	8.95	.000	132.554	639.305	539.433
12-06	13.208	4.656	4.513	138.206	116.547	8.94	.000	116.547	755.852	615.437
12-07	10.097	4.338	2.961	86.263	104.708	7.46	.000	104.708	860.560	677.497
12-08	9.627	3.869	2.764	84.062	94.806	7.77	.000	94.806	955.366	728.582
12-09	9.121	3.059	2.502	76.220	85.951	7.89	.000	85.951	1041.317	770.684
12-10	8.703	2.844	2.345	75.793	77.845	8.24	.000	77.845	1119.162	805.350
12-11	8.318	2.656	2.212	75.793	70.191	8.64	.000	70.191	1189.353	833.767
12-12	7.897	2.480	2.053	74.693	62.963	9.00	.000	62.963	1252.317	856.941
12-13	7.293	2.310	1.775	69.193	56.429	9.12	.000	56.429	1308.746	875.822
S TOT	138.428	48.626	44.478	1302.304	1308.746	15.58	.000	1308.746	1308.746	875.822
AFTER	69.521	17.225	15.008	748.275	383.433	15.58	.000	383.433	1692.179	949.967
TOTAL	207.948	65.851	59.486	2050.579	1692.179	15.58	.000	1692.179	1692.179	949.967

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	26.0	77.0	LIFE, YRS.	59.08	8.00	1039.682
GROSS ULT., MB & MMF	11330.960	152668.500	DISCOUNT %	10.00	10.00	949.966
GROSS CUM., MB & MMF	10536.410	142401.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	875.411
GROSS RES., MB & MMF	794.548	10267.520	DISCOUNTED PAYOUT, YRS.	.00	15.00	784.678
NET RES., MB & MMF	175.174	516.696	UNDISCOUNTED NET/INVEST.	.00	20.00	672.079
NET REVENUE, M$	3220.683	855.360	DISCOUNTED NET/INVEST.	.00	25.00	590.609
INITIAL PRICE, $	17.975	1.847	RATE-OF-RETURN, PCT.	100.00	35.00	480.705
INITIAL N.I., PCT.	16.616	3.374	INITIAL W.I., PCT.	10.091	50.00	383.206
					70.00	308.907
					100.00	246.832

SWR INST INCOME FUND X-B	DATE TIME DBS FILE SETUP FILE SEQ NUMBER	: : : : :	02/18/02
PROPERTIES REV BY RYDER SCOTT			08:59:44
PNP RESERVES			SWR0102C
$19.84/BO AND $2.57/MCF NYMEX			BASE0102
			*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.3	7.844	15.689	.000	.046	.092	.000	18.07	2.60	.827	.238	1.065
12-04	2.0	8.038	16.077	.000	.047	.094	.000	18.07	2.60	.847	.244	1.091
12-05	1.4	4.336	8.671	.000	.025	.051	.000	18.07	2.60	.457	.132	.589
12-06	1.0	1.733	3.466	.000	.010	.020	.000	18.07	2.60	.183	.053	.235
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	21.952	43.903	.000	.128	.256	.000	18.07	2.60	2.314	.666	2.980
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	21.952	43.903	.000	.128	.256	.000	18.07	2.60	2.314	.666	2.980

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF   M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.038	.018	.030	.124	.854	3.45	.000	.854	.854	.731
12-04	.039	.018	.031	.187	.816	4.40	.000	.816	1.670	1.377
12-05	.021	.010	.017	.132	.409	5.33	.000	.409	2.079	1.673
12-06	.008	.004	.007	.070	.146	6.60	.000	.146	2.225	1.770
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	.106	.050	.085	.513	2.225	6.60	.000	2.225	2.225	1.770
AFTER	.000	.000	.000	.000	.000	6.60	.000	.000	2.225	1.770
TOTAL	.106	.050	.085	.513	2.225	6.60	.000	2.225	2.225	1.770

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	4.75	8.00	1.848
GROSS ULT., MB & MMF	21.952	43.903	DISCOUNT %	10.00	10.00	1.770
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1.696
GROSS RES., MB & MMF	21.952	43.903	DISCOUNTED PAYOUT, YRS.	.00	15.00	1.594
NET RES., MB & MMF	.128	.256	UNDISCOUNTED NET/INVEST.	.00	20.00	1.443
NET REVENUE, M$	2.314	.666	DISCOUNTED NET/INVEST.	.00	25.00	1.314
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	1.103
INITIAL N.I., PCT.	.583	.583	INITIAL W.I., PCT.	.778	50.00	.874
					70.00	.667
					100.00	.476

SWR INST INCOME FUND X-B PROPERTIES REV BY RYDER SCOTT PUD RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:59:44 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES   M$	TOTAL NET SALES   M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.1	1.166	3.498	.000	.053	.158	.000	18.34	2.32	.963	.365	1.328
12-04	1.0	10.156	30.469	.000	.457	1.372	.000	18.34	2.32	8.386	3.183	11.569
12-05	1.0	7.283	21.849	.000	.328	.984	.000	18.34	2.32	6.014	2.282	8.296
12-06	1.0	6.055	18.166	.000	.273	.818	.000	18.34	2.32	5.000	1.898	6.898
12-07	1.0	5.320	15.961	.000	.240	.719	.000	18.34	2.32	4.393	1.667	6.060
12-08	1.0	4.814	14.443	.000	.217	.650	.000	18.34	2.32	3.975	1.509	5.484
12-09	1.0	4.438	13.313	.000	.200	.599	.000	18.34	2.32	3.664	1.391	5.055
12-10	1.0	4.144	12.431	.000	.187	.560	.000	18.34	2.32	3.422	1.298	4.720
12-11	1.0	3.896	11.688	.000	.175	.526	.000	18.34	2.32	3.217	1.221	4.438
12-12	1.0	3.662	10.986	.000	.165	.495	.000	18.34	2.32	3.024	1.148	4.171
12-13	1.0	3.442	10.327	.000	.155	.465	.000	18.34	2.32	2.842	1.079	3.921
S TOT	1.0	54.377	163.131	.000	2.448	7.345	.000	18.34	2.32	44.900	17.040	61.940
AFTER	1.0	10.277	30.830	.000	.463	1.388	.000	18.34	2.32	8.486	3.220	11.706
TOTAL	1.0	64.654	193.961	.000	2.911	8.733	.000	18.34	2.32	53.386	20.260	73.646

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST   $/EBO	CAPITAL INVEST   M$	FUT NET CASHFLOW   M$	CUM CASHFLOW   M$	10.0% CUM DISC CF   M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.067	.029	.012	.089	1.130	2.51	.000	1.130	1.130	.938
12-04	.587	.255	.107	1.069	9.551	2.94	.000	9.551	10.681	8.498
12-05	.421	.183	.077	1.069	6.546	3.56	.000	6.546	17.228	13.199
12-06	.350	.152	.064	1.069	5.263	4.00	.000	5.263	22.491	16.633
12-07	.308	.133	.056	1.069	4.494	4.36	.000	4.494	26.985	19.297
12-08	.278	.121	.051	1.069	3.965	4.67	.000	3.965	30.950	21.434
12-09	.256	.111	.047	1.069	3.571	4.95	.000	3.571	34.521	23.183
12-10	.240	.104	.044	1.069	3.264	5.20	.000	3.264	37.785	24.637
12-11	.225	.098	.041	1.069	3.005	5.45	.000	3.005	40.789	25.853
12-12	.212	.092	.039	1.069	2.760	5.71	.000	2.760	43.550	26.869
12-13	.199	.086	.036	1.069	2.531	5.98	.000	2.531	46.080	27.715
S TOT	3.143	1.363	.574	10.779	46.080	7.17	.000	46.080	46.080	27.715
AFTER	.594	.258	.109	3.653	7.093	7.17	.000	7.093	53.174	29.661
TOTAL	3.737	1.621	.683	14.432	53.174	7.17	.000	53.174	53.174	29.661

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	15.42	8.00	32.894
GROSS ULT., MB & MMF	64.654	225.882	DISCOUNT %	10.00	10.00	29.661
GROSS CUM., MB & MMF	.000	31.921	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	26.894
GROSS RES., MB & MMF	64.654	193.961	DISCOUNTED PAYOUT, YRS.	.00	15.00	23.437
NET RES., MB & MMF	2.911	8.733	UNDISCOUNTED NET/INVEST.	.00	20.00	19.038
NET REVENUE, M$	53.386	20.260	DISCOUNTED NET/INVEST.	.00	25.00	15.812
INITIAL PRICE, $	18.340	2.320	RATE-OF-RETURN, PCT.	100.00	35.00	11.473
INITIAL N.I., PCT.	4.502	4.502	INITIAL W.I., PCT.	5.469	50.00	7.744
					70.00	5.085
					100.00	3.089

SWR INST INCOME FUND X-B PROPS NOT REV BY RYDER SCOTT TOTAL PROVED RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 09:15:55 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD   MMCF	GROSS NGL PROD   MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M$	NET GAS SALES   M$	TOTAL NET SALES   M$
12-02	38.7	15.132	991.184	.000	2.438	20.573	.000	18.94	2.21	46.178	45.523	91.701
12-03	27.1	12.760	714.270	.000	2.286	15.880	.000	18.95	2.32	43.336	36.915	80.251
12-04	12.5	7.327	432.810	.000	1.604	7.809	.000	18.98	2.67	30.444	20.846	51.290
12-05	11.3	5.860	364.646	.000	1.423	6.123	.000	18.98	2.75	27.008	16.820	43.828
12-06	11.0	5.212	315.275	.000	1.352	5.448	.000	18.98	2.77	25.660	15.091	40.751
12-07	5.4	3.680	149.075	.000	1.284	4.516	.000	18.98	2.77	24.367	12.506	36.873
12-08	4.0	3.241	107.221	.000	1.220	4.073	.000	18.98	2.77	23.153	11.282	34.435
12-09	4.0	3.071	99.609	.000	1.159	3.843	.000	18.98	2.77	22.004	10.649	32.653
12-10	4.0	2.914	93.008	.000	1.102	3.627	.000	18.98	2.77	20.912	10.055	30.967
12-11	2.9	2.698	75.330	.000	1.047	3.090	.000	18.98	2.82	19.872	8.710	28.581
12-12	2.0	2.551	66.753	.000	.995	1.997	.000	18.98	3.04	18.885	6.063	24.948
12-13	1.9	2.227	62.551	.000	.869	1.819	.000	18.98	3.02	16.487	5.494	21.981
S  TOT	1.0	66.674	3471.732	.000	16.779	78.799	.000	18.97	2.54	318.305	199.954	518.259
AFTER	1.0	.000	591.934	.000	.000	10.654	.000	.00	2.64	.000	28.127	28.127
TOTAL	1.0	66.674	4063.666	.000	16.779	89.453	.000	18.97	2.55	318.305	228.081	546.386

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE   M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.141	3.457	2.343	57.004	26.756	11.07	.000	26.756	26.756	25.568
12-03	2.001	2.782	2.149	52.021	21.298	11.95	.000	21.298	48.054	44.064
12-04	1.401	1.554	1.430	29.160	17.746	11.54	.000	17.746	65.800	58.069
12-05	1.242	1.253	1.233	24.815	15.285	11.68	.000	15.285	81.084	69.036
12-06	1.180	1.124	1.153	24.164	13.130	12.22	.000	13.130	94.215	77.600
12-07	1.121	.937	1.043	22.828	10.944	12.73	.000	10.944	105.159	84.091
12-08	1.065	.846	.976	22.397	9.151	13.32	.000	9.151	114.310	89.026
12-09	1.012	.799	.925	22.397	7.520	13.96	.000	7.520	121.830	92.713
12-10	.962	.754	.878	22.397	5.976	14.65	.000	5.976	127.806	95.377
12-11	.914	.653	.810	21.713	4.491	15.42	.000	4.491	132.297	97.198
12-12	.869	.455	.709	19.705	3.210	16.37	.000	3.210	135.507	98.382
12-13	.758	.412	.624	18.140	2.046	17.01	.000	2.046	137.553	99.069
S  TOT	14.667	15.025	14.273	336.742	137.553	15.46	.000	137.553	137.553	99.069
AFTER	.000	2.110	.781	14.729	10.508	15.46	.000	10.508	148.060	101.299
TOTAL	14.667	17.134	15.054	351.471	148.060	15.46	.000	148.060	148.060	101.299

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	60.0	31.0	LIFE, YRS.	27.92	8.00	107.948
GROSS ULT., MB & MMF	16899.760	231104.100	DISCOUNT %	10.00	10.00	101.299
GROSS CUM., MB & MMF	16833.080	227040.400	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	95.495
GROSS RES., MB & MMF	66.674	4063.666	DISCOUNTED PAYOUT, YRS.	.00	15.00	88.053
NET RES., MB & MMF	16.779	89.453	UNDISCOUNTED NET/INVEST.	.00	20.00	78.172
NET REVENUE, M$	318.305	228.081	DISCOUNTED NET/INVEST.	.00	25.00	70.524
INITIAL PRICE, $	17.614	2.140	RATE-OF-RETURN, PCT.	100.00	35.00	59.475
INITIAL N.I., PCT.	13.235	1.948	INITIAL W.I., PCT.	5.371	50.00	48.921
					70.00	40.397
					100.00	32.964

SWR INST INCOME FUND X-B	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	09:15:55
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	38.7	15.132	991.184	.000	2.438	20.573	.000	18.94	2.21	46.178	45.523	91.701
12-03	26.5	12.259	639.003	.000	2.286	15.756	.000	18.95	2.32	43.320	36.598	79.919
12-04	11.5	6.713	340.597	.000	1.603	7.656	.000	18.98	2.67	30.425	20.458	50.883
12-05	10.3	5.461	304.708	.000	1.422	6.024	.000	18.98	2.75	26.995	16.568	43.563
12-06	10.0	4.952	276.315	.000	1.351	5.384	.000	18.98	2.77	25.652	14.927	40.579
12-07	4.4	3.511	123.751	.000	1.284	4.474	.000	18.98	2.77	24.362	12.400	36.762
12-08	3.0	3.127	89.915	.000	1.220	4.045	.000	18.98	2.77	23.150	11.209	34.359
12-09	3.0	2.972	84.498	.000	1.159	3.818	.000	18.98	2.77	22.001	10.586	32.587
12-10	3.0	2.825	79.407	.000	1.102	3.604	.000	18.98	2.77	20.909	9.998	30.907
12-11	2.8	2.685	73.750	.000	1.047	3.087	.000	18.98	2.82	19.871	8.703	28.574
12-12	2.0	2.551	66.753	.000	.995	1.997	.000	18.98	3.04	18.885	6.063	24.948
12-13	1.9	2.227	62.551	.000	.869	1.819	.000	18.98	3.02	16.487	5.494	21.981
S TOT	1.0	64.416	3132.432	.000	16.775	78.237	.000	18.97	2.54	318.234	198.528	516.762
AFTER	1.0	.000	591.934	.000	.000	10.654	.000	.00	2.64	.000	28.127	28.127
TOTAL	1.0	64.416	3742.366	.000	16.775	88.891	.000	18.97	2.55	318.234	226.654	544.889

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.141	3.457	2.343	57.004	26.756	11.07	.000	26.756	26.756	25.568
12-03	2.000	2.758	2.140	52.010	21.011	11.99	.000	21.011	47.766	43.820
12-04	1.400	1.525	1.418	29.141	17.399	11.63	.000	17.399	65.166	57.551
12-05	1.242	1.234	1.226	24.796	15.066	11.75	.000	15.066	80.232	68.360
12-06	1.180	1.112	1.148	24.144	12.955	12.27	.000	12.995	93.227	76.836
12-07	1.121	.929	1.040	22.809	10.863	12.76	.000	10.863	104.090	83.279
12-08	1.065	.841	.974	22.378	9.102	13.34	.000	9.102	113.191	88.186
12-09	1.012	.794	.923	22.378	7.480	13.98	.000	7.480	120.671	91.853
12-10	.962	.750	.876	22.378	5.941	14.67	.000	5.941	126.612	94.502
12-11	.914	.653	.810	21.710	4.487	15.43	.000	4.487	131.100	96.322
12-12	.869	.455	.709	19.705	3.210	16.37	.000	3.210	134.310	97.506
12-13	.758	.412	.624	18.140	2.046	17.01	.000	2.046	136.356	98.193
S TOT	14.664	14.918	14.232	336.593	136.356	15.46	.000	136.356	136.356	98.193
AFTER	.000	2.110	.781	14.729	10.508	15.46	.000	10.508	146.863	100.423
TOTAL	14.664	17.027	15.012	351.322	146.863	15.46	.000	146.863	146.863	100.423

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	60.0	30.0	LIFE, YRS.	27.92	8.00	107.019
GROSS ULT., MB & MMF	16897.500	230764.800	DISCOUNT %	10.00	10.00	100.423
GROSS CUM., MB & MMF	16833.080	227040.400	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	94.667
GROSS RES., MB & MMF	64.416	3724.366	DISCOUNTED PAYOUT, YRS.	.00	15.00	87.290
NET RES., MB & MMF	16.775	88.891	UNDISCOUNTED NET/INVEST.	.00	20.00	77.499
NET REVENUE, M$	318.234	226.654	DISCOUNTED NET/INVEST.	.00	25.00	69.927
INITIAL PRICE, $	17.583	2.087	RATE-OF-RETURN, PCT.	100.00	35.00	58.993
INITIAL N.I., PCT.	13.557	2.185	INITIAL W.I., PCT.	6.043	50.00	48.556
					70.00	40.129
					100.00	32.781

SWR INST INCOME FUND X-B PROPS NOT REV BY RYDER SCOTT PUD RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 09:15:55 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.6	.501	75.267	.000	.001	.125	.000	18.88	2.54	.016	.316	.332
12-04	1.0	.614	92.213	.000	.001	.153	.000	18.88	2.54	.019	.388	.407
12-05	1.0	.399	59.938	.000	.001	.099	.000	18.88	2.54	.012	.252	.265
12-06	1.0	.260	38.960	.000	.000	.064	.000	18.88	2.54	.008	.164	.172
12-07	1.0	.169	25.324	.000	.000	.042	.000	18.88	2.54	.005	.106	.112
12-08	1.0	.114	17.306	.000	.000	.029	.000	18.88	2.54	.004	.073	.076
12-09	1.0	.099	15.112	.000	.000	.025	.000	18.88	2.54	.003	.064	.067
12-10	1.0	.089	13.600	.000	.000	.023	.000	18.88	2.54	.003	.057	.060
12-11	1.0	.014	1.580	.000	.000	.003	.000	18.88	2.54	.000	.007	.007
12-12
12-13
S TOT	1.0	2.259	339.300	.000	.004	.562	.000	18.88	2.54	.071	1.427	1.497
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	2.259	339.300	.000	.004	.562	.000	18.88	2.54	.071	1.427	1.497

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.001	.024	.009	.011	.287	2.08	.000	.287	.287	.244
12-04	.001	.029	.011	.019	.346	2.28	.000	.346	.634	.519
12-05	.001	.019	.007	.019	.219	2.68	.000	.219	.852	.676
12-06	.000	.012	.005	.019	.135	3.28	.000	.135	.988	.764
12-07	.000	.008	.003	.019	.081	4.20	.000	.081	1.069	.813
12-08	.000	.005	.002	.019	.049	5.42	.000	.049	1.118	.839
12-09	.000	.005	.002	.019	.041	5.99	.000	.041	1.159	.859
12-10	.000	.004	.002	.019	.035	6.48	.000	.035	1.194	.875
12-11	.000	.000	.000	.003	.003	8.62	.000	.003	1.197	.876
12-12
12-13
S TOT	.003	.107	.042	.149	1.197	8.62	.000	1.197	1.197	.876
AFTER	.000	.000	.000	.000	.000	8.62	.000	.000	1.197	.876
TOTAL	.003	.107	.042	.149	1.197	8.62	.000	1.197	1.197	.876

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	.0	1.0	LIFE, YRS.	9.17	8.00	.928
GROSS ULT., MB & MMF	2.259	339.300	DISCOUNT %	10.00	10.00	.876
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	.828
GROSS RES., MB & MMF	2.259	339.300	DISCOUNTED PAYOUT, YRS.	.00	15.00	.764
NET RES., MB & MMF	.004	.562	UNDISCOUNTED NET/INVEST.	.00	20.00	.673
NET REVENUE, M$	.071	1.427	DISCOUNTED NET/INVEST.	.00	25.00	.598
INITIAL PRICE, $	18.880	2.540	RATE-OF-RETURN, PCT.	100.00	35.00	.482
INITIAL N.I., PCT.	.166	.166	INITIAL W.I., PCT.	.205	50.00	.365
					70.00	.268
					100.00	.183

SWR INST INCOME FUND X-B ALL PROPERTIES TOTAL PROVED RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:39:17 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	141.7	110.068	2442.280	.000	18.556	69.789	.000	18.28	1.81	339.277	126.486	465.762
12-03	131.5	108.864	2064.364	.000	17.614	61.721	.000	18.29	1.82	322.172	112.607	434.778
12-04	118.5	106.504	1703.875	.000	16.519	51.557	.000	18.28	1.82	301.910	94.002	395.912
12-05	116.8	93.076	1524.966	.000	15.419	46.409	.000	18.28	1.81	281.815	84.056	365.871
12-06	113.5	78.549	1381.982	.000	13.514	42.756	.000	18.33	1.81	247.654	77.360	325.013
12-07	100.4	55.461	1134.015	.000	9.770	39.147	.000	18.52	1.80	180.947	70.352	251.300
12-08	80.8	50.159	870.767	.000	9.290	35.102	.000	18.52	1.79	172.086	62.962	235.048
12-09	24.5	41.270	361.892	.000	8.779	29.095	.000	18.53	1.78	162.648	51.913	214.561
12-10	24.0	38.354	332.674	.000	8.356	27.081	.000	18.53	1.79	154.819	48.399	203.218
12-11	22.9	36.183	296.845	.000	7.969	24.945	.000	18.53	1.78	147.672	44.517	192.189
12-12	21.3	32.876	271.153	.000	7.534	22.349	.000	18.54	1.77	139.715	39.490	179.206
12-13	17.9	24.548	249.685	.000	6.790	20.703	.000	18.60	1.77	126.286	36.617	162.902
S TOT	1.1	775.912	12634.500	.000	140.109	470.655	.000	18.39	1.80	2577.000	848.760	3425.760
AFTER	1.1	171.915	1934.550	.000	54.883	144.482	.000	18.54	1.77	1017.687	255.607	1273.294
TOTAL	1.1	947.827	14569.050	.000	194.991	615.137	.000	18.44	1.80	3594.688	1104.367	4699.054

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	19.478	9.699	8.773	212.524	215.289	8.30	.000	215.289	215.289	205.555
12-03	18.539	8.619	8.204	207.755	191.662	8.71	.000	191.662	406.951	371.855
12-04	17.619	7.205	7.200	185.936	177.951	8.68	.000	177.951	584.902	512.292
12-05	16.487	6.447	6.607	181.536	154.794	9.12	.000	154.794	739.696	623.341
12-06	14.746	5.936	5.736	163.509	135.086	9.20	.000	135.086	874.783	711.439
12-07	11.525	5.408	4.060	110.161	120.146	8.05	.000	120.146	994.928	782.656
12-08	10.971	4.836	3.791	107.528	107.922	8.40	.000	107.922	1102.851	840.811
12-09	10.390	3.969	3.474	99.686	97.042	8.62	.000	97.042	1199.893	888.349
12-10	9.905	3.702	3.267	99.259	87.085	9.02	.000	87.085	1286.978	927.133
12-11	9.457	3.407	3.063	98.575	77.686	9.44	.000	77.686	1364.664	958.587
12-12	8.977	3.027	2.800	95.468	68.934	9.79	.000	68.934	1433.598	983.961
12-13	8.250	2.808	2.436	88.403	61.005	9.95	.000	61.005	1494.603	1004.376
S TOT	156.344	65.063	59.411	1650.339	1494.603	15.58	.000	1494.603	1494.603	1004.376
AFTER	70.115	19.592	15.897	766.656	401.034	15.58	.000	401.034	1895.638	1082.696
TOTAL	226.459	84.656	75.308	2416.995	1895.638	15.58	.000	1895.638	1895.638	1082.696

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	89.0	108.0	LIFE, YRS.	59.08	8.00	1182.372
GROSS ULT., MB & MMF	28317.320	384042.500	DISCOUNT %	10.00	10.00	1082.696
GROSS CUM., MB & MMF	27369.500	369473.400	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	999.496
GROSS RES., MB & MMF	947.827	14569.050	DISCOUNTED PAYOUT, YRS.	.00	15.00	897.762
NET RES., MB & MMF	194.991	615.137	UNDISCOUNTED NET/INVEST.	.00	20.00	770.732
NET REVENUE, M$	3594.688	1104.367	DISCOUNTED NET/INVEST.	.00	25.00	678.259
INITIAL PRICE, $	17.928	1.989	RATE-OF-RETURN, PCT.	100.00	35.00	552.757
INITIAL N.I., PCT.	13.450	2.741	INITIAL W.I., PCT.	7.719	50.00	440.745
					70.00	355.056
					100.00	283.360

SWR INST INCOME FUND X-B ALL PROPERTIES PDP RESERVES $19.84/BO AND $2.57/MCF NYMEX DATE TIME DBS FILE SETUP FILE SEQ NUMBER : : : : : 02/18/02 08:39:17 SWR0102C BASE0102 *****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	141.7	110.068	2442.280	.000	18.556	69.789	.000	18.28	1.81	339.277	126.486	465.762
12-03	129.5	99.352	1969.910	.000	17.515	61.348	.000	18.29	1.82	320.366	111.687	432.053
12-04	114.5	87.695	1565.117	.000	16.014	49.939	.000	18.28	1.81	292.657	90.188	382.845
12-05	113.3	81.058	1434.507	.000	15.065	45.276	.000	18.28	1.80	275.332	81.390	356.722
12-06	110.8	70.501	1321.389	.000	13.231	41.853	.000	18.33	1.80	242.463	75.246	317.709
12-07	98.4	49.972	1092.730	.000	9.531	38.387	.000	18.52	1.79	176.549	68.579	245.128
12-08	78.8	45.230	839.019	.000	9.073	34.423	.000	18.53	1.78	168.107	61.381	229.488
12-09	22.5	36.734	333.467	.000	8.579	28.470	.000	18.53	1.77	158.981	50.458	209.439
12-10	22.0	34.122	306.642	.000	8.169	26.499	.000	18.53	1.78	151.394	47.043	198.438
12-11	21.8	32.273	283.577	.000	7.793	24.416	.000	18.54	1.77	144.455	43.290	187.744
12-12	20.3	29.213	260.167	.000	7.369	21.854	.000	18.55	1.75	136.692	38.343	175.034
12-13	16.9	21.105	239.357	.000	6.635	20.238	.000	18.61	1.76	123.443	35.538	158.981
S TOT	1.1	697.325	12088.160	.000	137.529	462.493	.000	18.39	1.79	2529.715	829.628	3359.343
AFTER	1.1	161.638	1903.719	.000	54.420	143.094	.000	18.54	1.76	1009.202	252.386	1261.588
TOTAL	1.1	858.963	13991.880	.000	191.949	605.586	.000	18.44	1.79	3538.917	1082.014	4620.931

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	19.478	9.699	8.773	212.524	215.289	8.30	.000	215.289	215.289	205.555
12-03	18.433	8.548	8.152	207.530	189.390	8.75	.000	189.390	404.679	369.941
12-04	16.992	6.903	7.050	184.661	167.237	8.86	.000	167.237	571.917	501.898
12-05	16.044	6.236	6.506	180.316	147.621	9.25	.000	147.621	719.537	607.793
12-06	14.388	5.768	5.661	162.350	129.542	9.31	.000	129.542	849.079	692.273
12-07	11.217	5.267	4.001	109.072	115.570	8.13	.000	115.570	964.650	760.776
12-08	10.692	4.710	3.738	106.440	103.908	8.48	.000	103.908	1068.558	816.768
12-09	10.133	3.853	3.425	98.598	93.430	8.71	.000	93.430	1161.988	862.537
12-10	9.665	3.594	3.221	98.171	83.787	9.11	.000	83.787	1245.774	899.852
12-11	9.232	3.309	3.022	97.503	74.679	9.53	.000	74.679	1320.453	930.089
12-12	8.765	2.935	2.762	94.399	66.174	9.39	.000	66.174	1386.627	954.447
12-13	8.052	2.722	2.399	87.334	58.475	10.04	.000	58.475	1445.101	974.015
S TOT	153.091	63.543	58.710	1638.897	1445.101	15.58	.000	1445.101	1445.101	974.015
AFTER	69.521	19.335	15.788	763.004	393.941	15.58	.000	393.941	1839.042	1050.390
TOTAL	222.612	82.878	74.498	2401.901	1839.042	15.58	.000	1839.042	1839.042	1050.390

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	86.0	107.0	LIFE, YRS.	59.08	8.00	1146.701
GROSS ULT., MB & MMF	28228.460	383433.300	DISCOUNT %	10.00	10.00	1050.390
GROSS CUM., MB & MMF	27369.500	369441.500	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	970.078
GROSS RES., MB & MMF	858.963	13991.880	DISCOUNTED PAYOUT, YRS.	.00	15.00	871.968
NET RES., MB & MMF	191.949	605.587	UNDISCOUNTED NET/INVEST.	.00	20.00	749.578
NET REVENUE, M$	3538.917	1082.014	DISCOUNTED NET/INVEST.	.00	25.00	660.536
INITIAL PRICE, $	17.866	1.947	RATE-OF-RETURN, PCT.	100.00	35.00	539.698
INITIAL N.I., PCT.	15.761	2.878	INITIAL W.I., PCT.	8.510	50.00	431.762
					70.00	349.036
					100.00	279.613

SWR INST INCOME FUND X-B	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:17
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.3	7.844	15.689	.000	.046	.092	.000	18.07	2.60	.827	.238	1.065
12-04	2.0	8.038	16.077	.000	.047	.094	.000	18.07	2.60	.847	.244	1.091
12-05	1.4	4.336	8.671	.000	.025	.051	.000	18.07	2.60	.457	.132	.589
12-06	1.0	1.733	3.466	.000	.010	.020	.000	18.07	2.60	.183	.053	.235
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	21.952	43.903	.000	.128	.256	.000	18.07	2.60	2.314	.666	2.980
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	21.952	43.903	.000	.128	.256	.000	18.07	2.60	2.314	.666	2.980

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.038	.018	.030	.124	.854	3.45	.000	.854	.854	.731
12-04	.039	.018	.031	.187	.816	4.40	.000	.816	1.670	1.377
12-05	.021	.010	.017	.132	.409	5.33	.000	.409	2.079	1.673
12-06	.008	.004	.007	.070	.146	6.60	.000	.146	2.225	1.770
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	.106	.050	.085	.513	2.225	6.60	.000	2.225	2.225	1.770
AFTER	.000	.000	.000	.000	.000	6.60	.000	.000	2.225	1.770
TOTAL	.106	.050	.085	.513	2.225	6.60	.000	2.225	2.225	1.770

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	4.75	8.00	1.848
GROSS ULT., MB & MMF	21.952	43.903	DISCOUNT %	10.00	10.00	1.770
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1.696
GROSS RES., MB & MMF	21.952	43.903	DISCOUNTED PAYOUT, YRS.	.00	15.00	1.594
NET RES., MB & MMF	.128	.256	UNDISCOUNTED NET/INVEST.	.00	20.00	1.443
NET REVENUE, M$	2.314	.666	DISCOUNTED NET/INVEST.	.00	25.00	1.314
INITIAL PRICE, $	18.070	2.600	RATE-OF-RETURN, PCT.	100.00	35.00	1.103
INITIAL N.I., PCT.	.583	.583	INITIAL W.I., PCT.	.778	50.00	.874
					70.00	.667
					100.00	.476

SWR INST INCOME FUND X-B	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:17
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10B

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.7	1.167	78.766	.000	.053	.282	.000	18.35	2.42	.979	.682	1.660
12-04	2.0	10.771	122.682	.000	.458	1.524	.000	18.34	2.34	8.406	3.570	11.976
12-05	2.0	7.682	81.787	.000	.329	1.083	.000	18.34	2.34	6.026	2.534	8.560
12-06	2.0	6.315	57.126	.000	.273	.882	.000	18.34	2.34	5.008	2.061	7.070
12-07	2.0	5.489	41.285	.000	.240	.761	.000	18.34	2.33	4.398	1.774	6.172
12-08	2.0	4.928	31.749	.000	.217	.679	.000	18.34	2.33	3.979	1.581	5.560
12-09	2.0	4.536	28.424	.000	.200	.624	.000	18.34	2.33	3.667	1.454	5.121
12-10	2.0	4.233	26.032	.000	.187	.582	.000	18.34	2.33	3.424	1.356	4.780
12-11	1.2	3.910	13.268	.000	.175	.529	.000	18.34	2.32	3.217	1.227	4.445
12-12	1.0	3.662	10.986	.000	.165	.495	.000	18.34	2.32	3.024	1.148	4.171
12-13	1.0	3.442	10.327	.000	.155	.465	.000	18.34	2.32	2.842	1.079	3.921
S TOT	1.0	56.636	502.431	.000	2.452	7.906	.000	18.34	2.34	44.971	18.466	63.437
AFTER	1.0	10.277	30.830	.000	.463	1.388	.000	18.34	2.32	8.486	3.220	11.706
TOTAL	1.0	66.913	533.262	.000	2.915	9.294	.000	18.34	2.33	53.457	21.687	75.144

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.068	.053	.022	.100	1.418	2.42	.000	1.418	1.418	1.182
12-04	.588	.284	.119	1.088	9.898	2.92	.000	9.898	11.315	9.017
12-05	.422	.201	.084	1.088	6.765	3.53	.000	6.765	18.080	13.875
12-06	.350	.164	.069	1.088	5.398	3.98	.000	5.398	23.478	17.397
12-07	.308	.141	.059	1.088	4.575	4.36	.000	4.575	28.053	20.110
12-08	.278	.126	.053	1.088	4.014	4.68	.000	4.014	32.068	22.273
12-09	.257	.116	.049	1.088	3.612	4.97	.000	3.612	35.680	24.042
12-10	.240	.108	.045	1.088	3.299	5.22	.000	3.299	38.978	25.511
12-11	.225	.098	.041	1.072	3.008	5.45	.000	3.008	41.986	26.729
12-12	.212	.092	.039	1.069	2.760	5.71	.000	2.760	44.746	27.745
12-13	.199	.086	.036	1.069	2.531	5.98	.000	2.531	47.277	28.591
S TOT	3.146	1.470	.616	10.928	47.277	7.17	.000	47.277	47.277	28.591
AFTER	.594	.258	.109	3.653	7.093	7.17	.000	7.093	54.370	30.537
TOTAL	3.740	1.728	.724	14.581	54.370	7.17	.000	54.370	54.370	30.537

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	1.0	LIFE, YRS.	15.42	8.00	33.822
GROSS ULT., MB & MMF	66.913	565.183	DISCOUNT %	10.00	10.00	30.537
GROSS CUM., MB & MMF	.000	31.921	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	27.722
GROSS RES., MB & MMF	66.913	533.262	DISCOUNTED PAYOUT, YRS.	.00	15.00	24.201
NET RES., MB & MMF	2.915	9.294	UNDISCOUNTED NET/INVEST.	.00	20.00	19.711
NET REVENUE, M$	53.457	21.687	DISCOUNTED NET/INVEST.	.00	25.00	16.410
INITIAL PRICE, $	18.374	2.490	RATE-OF-RETURN, PCT.	100.00	35.00	11.956
INITIAL N.I., PCT.	4.225	1.148	INITIAL W.I., PCT.	2.737	50.00	8.109
					70.00	5.352
					100.00	3.272

APPENDIX B14

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Oil & Gas Income Fund X-C (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 7 reserve determinations and are located in the states of Alabama, Louisiana, New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 78.3 percent of the total net remaining liquid hydrocarbon reserves and 93.4 percent of the total net remaining gas reserves. The properties that we reviewed represent 94.9 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Oil & Gas Income Fund X-C

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		21,587		0		0		21,587
Gas—MMCF		425		0		0		425
Income Data
Future Gross Revenue	$	1,156,697	$	0	$	0	$	1,156,697
Deductions		552,985		0		0		552,985
Future Net Income (FNI)	$	603,712	$	0	$	0	$	603,712
Discounted FNI @ 10%	$	376,061	$	0	$	0	$	376,061

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed			Undeveloped		Total Proved
		Producing	Non-Producing
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		5,977	0		0		5,977
Gas—MMCF		30	0		0		30
Income Data
Future Gross Revenue	$	103,722	$0	$	0	$	103,722
Deductions		75,676	0		0		75,676
Future Net Income (FNI)	$	28,046	$0	$	0	$	28,046
Discounted FNI @ 10%	$	20,087	$0	$	0	$	20,087
Total Net Reserves
Oil/Condensate—Barrels		27,564	0		0		27,564
Gas—MMCF		455	0		0		455
Income Data
Future Gross Revenue	$	1,260,419	$0	$	0	$	1,260,419
Deductions		628,661	0		0		628,661
Future Net Income (FNI)	$	631,758	$0	$	0	$	631,758
Discounted FNI @ 10%	$	396,148	$0	$	0	$	396,148

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 21.7 percent of the total net remaining liquid hydrocarbon reserves and 6.6 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

BY:          /S/    C. PATRICK MCINTURFF          

C. Patrick McInturff, P.E.

Petroleum Engineer

CPM/sw

Approved:

By:            /S/    L. B. BRANUM        

L. B. Branum, P.E.        

Vice President        

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW OIL & GAS INCOME FUND X-C	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	09:55:30
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES  AND  ECONOMICS

QUALIFIER:  RSC0102  OG10C

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	14.0	32.503	300.946	.000	3.703	48.984	.000	18.47	2.05	68.396	100.253	168.649
12-03	12.6	29.180	223.519	.000	3.402	42.293	.000	18.50	1.96	62.934	82.876	145.810
12-04	12.0	26.791	189.404	.000	3.163	37.801	.000	18.51	1.90	58.551	71.885	130.436
12-05	12.0	24.848	172.389	.000	2.959	34.434	.000	18.52	1.86	54.807	64.094	118.901
12-06	11.0	23.083	158.103	.000	2.777	31.610	.000	18.53	1.83	51.465	57.792	109.258
12-07	11.0	21.472	145.816	.000	2.613	29.186	.000	18.54	1.80	48.444	52.552	100.996
12-08	10.4	19.671	131.948	.000	2.332	25.791	.000	18.52	1.79	43.173	46.211	89.384
12-09	10.0	18.131	120.681	.000	2.121	23.206	.000	18.50	1.78	39.244	41.318	80.562
12-10	9.3	15.407	109.243	.000	1.411	20.384	.000	18.31	1.90	25.831	38.810	64.641
12-11	9.0	13.599	100.480	.000	1.037	18.459	.000	18.13	1.97	18.793	36.375	55.168
12-12	8.3	11.324	93.735	.000	.910	17.331	.000	18.20	1.96	16.552	33.947	50.499
12-13	4.9	4.112	83.606	.000	.526	15.738	.000	18.74	1.92	9.851	30.183	40.034
S TOT	1.0	240.123	1829.870	.000	26.952	345.218	.000	18.48	1.90	498.043	656.294	1154.337
AFTER	1.0	12.764	549.641	.000	.612	110.162	.000	18.51	1.67	11.319	183.942	195.262
TOTAL	1.0	252.887	2379.511	.000	27.564	455.380	.000	18.48	1.85	509.363	840.236	1349.599

-END -MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.211	7.886	4.086	50.515	102.951	5.54	.000	102.951	102.951	98.368
12-03	2.925	6.386	3.561	48.868	84.070	5.91	.000	84.070	187.021	171.369
12-04	2.714	5.506	3.182	48.044	70.989	6.28	.000	70.989	258.010	227.401
12-05	2.540	4.915	2.888	48.044	60.513	6.71	.000	60.513	318.524	270.820
12-06	2.386	4.436	2.645	55.137	44.654	8.03	.000	44.654	363.177	299.952
12-07	2.245	4.037	2.439	55.137	37.137	8.54	.000	37.137	400.314	321.979
12-08	2.002	3.556	2.137	50.983	30.706	8.85	.000	30.706	431.020	338.535
12-09	1.820	3.183	1.912	48.016	25.631	9.17	.000	25.631	456.652	351.099
12-10	1.202	2.990	1.480	37.692	21.277	9.02	.000	21.277	477.929	360.580
12-11	.878	2.803	1.231	32.530	17.727	9.10	.000	17.727	495.655	367.761
12-12	.774	2.616	1.118	31.430	14.560	9.46	.000	14.560	510.216	373.124
12-13	.465	2.330	.840	24.411	11.988	8.91	.000	11.988	522.204	377.138
S TOT	23.163	50.643	27.520	530.807	522.204	9.65	.000	522.204	522.204	377.138
AFTER	.676	14.698	1.870	68.463	109.555	9.65	.000	109.555	631.759	396.148
TOTAL	23.839	65.341	29.389	599.270	631.759	9.65	.000	631.759	631.759	396.148

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	414.0	8.0	LIFE, YRS.	40.25	8.00	425.395
GROSS ULT., MB & MMF	21215.370	18724.370	DISCOUNT %	10.00	10.00	396.148
GROSS CUM., MB & MMF	20962.480	16344.860	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	371.439
GROSS RES., MB & MMF	252.887	2379.511	DISCOUNTED PAYOUT, YRS.	.00	15.00	340.709
NET RES., MB & MMF	27.564	455.380	UNDISCOUNTED NET/INVEST.	.00	20.00	301.220
NET REVENUE, M$	509.363	840.236	DISCOUNTED NET/INVEST.	.00	25.00	271.414
INITIAL PRICE, $	16.165	2.396	RATE-OF-RETURN, PCT.	100.00	35.00	229.051
INITIAL N.I., PCT.	14.063	15.307	INITIAL W.I., PCT.	17.476	50.00	188.881
					70.00	156.331
					100.00	127.722

SW OIL & GAS INCOME FUND X-C	DATE	:	02/18/02
PROPS REVIEWED BY RYDER SCOTT	TIME	:	10:12:05
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10C

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	9.0	23.928	203.674	.000	3.084	44.744	.000	18.40	2.15	56.742	96.353	153.095
12-03	9.0	22.007	178.626	.000	2.832	39.436	.000	18.41	2.10	52.141	82.783	134.924
12-04	9.0	20.339	159.654	.000	2.622	35.361	.000	18.42	2.06	48.293	72.777	121.070
12-05	9.0	18.855	144.505	.000	2.440	32.071	.000	18.43	2.03	44.959	64.986	109.945
12-06	8.0	17.516	131.959	.000	2.279	29.322	.000	18.44	2.00	42.011	58.683	100.693
12-07	8.0	16.297	121.297	.000	2.134	26.970	.000	18.44	1.98	39.367	53.439	92.806
12-08	7.4	14.861	108.944	.000	1.872	23.644	.000	18.40	1.99	34.459	47.093	81.551
12-09	7.0	13.658	99.090	.000	1.680	21.126	.000	18.38	2.00	30.878	42.193	73.071
12-10	6.3	11.246	88.973	.000	.988	18.368	.000	18.02	2.16	17.798	39.678	57.476
12-11	6.0	9.726	81.442	.000	.631	16.506	.000	17.57	2.26	11.081	37.234	48.315
12-12	5.3	7.719	75.849	.000	.520	15.437	.000	17.60	2.25	9.147	34.797	43.944
12-13	1.9	.755	66.794	.000	.151	13.903	.000	18.14	2.23	2.741	31.024	33.764
S TOT	1.0	176.905	1460.807	.000	21.232	316.889	.000	18.35	2.09	389.615	661.040	1050.656
AFTER	1.0	1.641	502.197	.000	.355	108.648	.000	18.30	1.69	6.495	183.615	190.111
TOTAL	1.0	178.546	1963.004	.000	21.587	425.537	.000	18.35	1.98	396.111	844.656	1240.766

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.634	7.366	3.762	42.610	96.723	5.35	.000	96.723	96.723	92.400
12-03	2.421	6.340	3.286	42.610	80.268	5.81	.000	80.268	176.991	162.098
12-04	2.242	5.581	2.928	42.610	67.708	6.27	.000	67.708	244.699	215.541
12-05	2.088	4.990	2.645	42.610	57.613	6.72	.000	57.613	302.312	256.879
12-06	1.951	4.510	2.412	49.703	42.117	8.17	.000	42.117	344.429	284.357
12-07	1.828	4.110	2.216	49.703	34.948	8.73	.000	34.948	379.378	305.086
12-08	1.601	3.628	1.923	45.549	28.850	9.07	.000	28.850	408.227	320.642
12-09	1.436	3.255	1.707	42.582	24.092	9.42	.000	24.092	432.319	332.451
12-10	.833	3.061	1.283	32.258	20.041	9.25	.000	20.041	452.361	341.381
12-11	.523	2.873	1.043	27.096	16.781	9.33	.000	16.781	469.142	348.179
12-12	.434	2.685	.938	25.996	13.892	9.72	.000	13.892	483.033	353.295
12-13	.138	2.397	.667	18.977	11.584	8.99	.000	11.584	494.618	357.173
S TOT	18.129	50.796	24.811	462.302	494.618	9.65	.000	494.618	494.618	357.173
AFTER	.455	14.689	1.750	64.121	109.096	9.65	.000	109.096	603.714	376.061
TOTAL	18.584	65.485	26.561	526.424	603.714	9.65	.000	603.714	603.714	376.061

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	245.0	3.0	LIFE, YRS.	40.25	8.00	404.110
GROSS ULT., MB & MMF	14469.100	11375.700	DISCOUNT %	10.00	10.00	376.061
GROSS CUM., MB & MMF	14290.550	9412.694	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	352.413
GROSS RES., MB & MMF	178.546	1963.004	DISCOUNTED PAYOUT, YRS.	.00	15.00	323.064
NET RES., MB & MMF	21.587	425.537	UNDISCOUNTED NET/INVEST.	.00	20.00	285.437
NET REVENUE, M$	396.111	844.656	DISCOUNTED NET/INVEST.	.00	25.00	257.088
INITIAL PRICE, $	15.941	2.315	RATE-OF-RETURN, PCT.	100.00	35.00	216.846
INITIAL N.I., PCT.	5.160	21.906	INITIAL W.I., PCT.	11.158	50.00	178.710
					70.00	147.803
					100.00	120.630

SW OIL & GAS INCOME FUND X-C	DATE	:	02/18/02
PROPS NOT REVIEWED BY RYDER SCOTT	TIME	:	10:19:22
PDP RESERVES	DBS FILE	:	SWR0102
$19.87/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  OG10C

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD   MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	5.0	8.576	97.273	.000	.619	4.240	.000	18.82	.92	11.655	3.899	15.554
12-03	3.6	7.173	44.893	.000	.570	2.857	.000	18.93	.03	10.793	.092	10.885
12-04	3.0	6.453	29.750	.000	.541	2.440	.000	18.97	-.37	10.258	-.893	9.366
12-05	3.0	5.993	27.884	.000	.519	2.363	.000	18.97	-.38	9.848	-.892	8.956
12-06	3.0	5.568	26.143	.000	.498	2.288	.000	18.97	-.39	9.454	-.890	8.564
12-07	3.0	5.175	24.520	.000	.478	2.216	.000	18.97	-.40	9.077	-.887	8.190
12-08	3.0	4.811	23.004	.000	.459	2.147	.000	18.98	-.41	8.714	-.882	7.833
12-09	3.0	4.474	21.590	.000	.441	2.080	.000	18.98	-.42	8.367	-.876	7.491
12-10	3.0	4.162	20.270	.000	.423	2.016	.000	18.98	-.43	8.033	-.868	7.165
12-11	3.0	3.873	19.038	.000	.406	1.953	.000	18.98	-.44	7.713	-.860	6.853
12-12	3.0	3.605	17.887	.000	.390	1.893	.000	18.98	-.45	7.405	-.850	6.555
12-13	3.0	3.357	16.812	.000	.375	1.835	.000	18.98	-.46	7.110	-.840	6.270
S TOT	1.0	63.218	369.063	.000	5.720	28.329	.000	18.95	-.17	108.428	-4.747	103.681
AFTER	1.0	11.124	47.444	.000	.257	1.514	.000	18.79	.22	4.824	.327	5.151
TOTAL	1.0	74.342	416.507	.000	5.977	29.843	.000	18.95	-.15	113.252	-4.419	108.833

-END-MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.577	.521	.324	7.905	6.228	7.03	.000	6.228	6.228	5.968
12-03	.505	.046	.275	6.258	3.802	6.77	.000	3.802	10.030	9.271
12-04	.472	-.076	.254	5.434	3.281	6.42	.000	3.281	13.311	11.860
12-05	.453	-.075	.243	5.434	2.900	6.63	.000	2.900	16.212	13.941
12-06	.435	-.074	.233	5.434	2.536	6.85	.000	2.536	18.748	15.595
12-07	.417	-.073	.223	5.434	2.189	7.08	.000	2.189	20.937	16.893
12-08	.401	-.073	.214	5.434	1.857	7.31	.000	1.857	22.793	17.894
12-09	.385	-.072	.205	5.434	1.539	7.56	.000	1.539	24.332	18.648
12-10	.369	-.071	.196	5.434	1.236	7.81	.000	1.236	25.568	19.199
12-11	.355	-.070	.188	5.434	.946	8.07	.000	.946	26.514	19.582
12-12	.340	-.069	.180	5.434	.669	8.34	.000	.669	27.183	19.829
12-13	.327	-.068	.173	5.434	.404	8.62	.000	.404	27.587	19.965
S TOT	5.034	-.152	2.708	68.505	27.587	1.29	.000	27.587	27.587	19.965
AFTER	.221	.009	.120	4.342	.459	1.29	.000	.459	28.046	20.087
TOTAL	5.255	-.144	2.829	72.847	28.046	1.29	.000	28.046	28.046	20.087

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	169.0	5.0	LIFE, YRS.	17.67	8.00	21.286
GROSS ULT., MB & MMF	6746.269	7348.675	DISCOUNT %	10.00	10.00	20.087
GROSS CUM., MB & MMF	6671.927	6932.168	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	19.026
GROSS RES., MB & MMF	74.342	416.507	DISCOUNTED PAYOUT, YRS.	.00	15.00	17.645
NET RES., MB & MMF	5.977	29.843	UNDISCOUNTED NET/INVEST.	.00	20.00	15.784
NET REVENUE, M$	113.252	-4.419	DISCOUNTED NET/INVEST.	.00	25.00	14.326
INITIAL PRICE, $	16.502	2.529	RATE-OF-RETURN, PCT.	100.00	35.00	12.205
INITIAL N.I., PCT.	27.408	4.562	INITIAL W.I., PCT.	26.684	50.00	10.172
					70.00	8.528
					100.00	7.092

APPENDIX B15

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWR Inst Income Fund X-C (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 7 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 68.2 percent of the total net remaining liquid hydrocarbon reserves and 89.1 percent of the total net remaining gas reserves. The properties that we reviewed represent 90.2 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWR Inst Income Fund X-C

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		14,731		0		0		14,731
Gas—MMCF		350		0		0		350
Income Data
Future Gross Revenue	$	831,557	$	0	$	0	$	831,557
Deductions		347,170		0		0		347,170
Future Net Income (FNI)	$	484,387	$	0	$	0	$	484,387
Discounted FNI @ 10%	$	287,967	$	0	$	0	$	287,967

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		6,873		0		0		6,873
Gas—MMCF		43		0		0		43
Income Data
Future Gross Revenue	$	150,122	$	0	$	0	$	150,122
Deductions		105,418		0		0		105,418
Future Net Income (FNI)	$	44,704	$	0	$	0	$	44,704
Discounted FNI @ 10%	$	31,346	$	0	$	0	$	31,346
Total Net Reserves
Oil/Condensate—Barrels		21,604		0		0		21,604
Gas—MMCF		393		0		0		393
Income Data
Future Gross Revenue	$	981,679	$	0	$	0	$	981,679
Deductions		452,588		0		0		452,588
Future Net Income (FNI)	$	529,091	$	0	$	0	$	529,091
Discounted FNI @ 10%	$	319,313	$	0	$	0	$	319,313

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 31.8 percent of the total net remaining liquid hydrocarbon reserves and 10.9 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SWR INST INCOME FUND X-C	DATE	:	02/18/02
ALL PROPERTIES	TIME	:	08:39:20
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSCO102  IN10C

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	40.0	40.318	244.271	.000	3.229	39.291	.000	18.39	1.79	59.376	70.184	129.560
12-03	40.0	37.030	216.869	.000	3.010	35.771	.000	18.40	1.74	55.402	62.355	117.757
12-04	33.2	29.114	192.913	.000	2.699	32.860	.000	18.51	1.71	49.966	56.180	106.146
12-05	14.0	13.197	173.899	.000	2.198	30.370	.000	18.87	1.68	41.472	51.097	92.569
12-06	11.6	12.387	154.233	.000	2.079	26.751	.000	18.87	1.60	39.242	42.733	81.974
12-07	9.0	10.744	134.165	.000	1.967	23.369	.000	18.88	1.49	37.136	34.929	72.066
12-08	8.4	9.791	121.130	.000	1.736	20.519	.000	18.86	1.47	32.744	30.240	62.984
12-09	8.0	9.032	110.655	.000	1.570	18.387	.000	18.85	1.45	29.607	26.719	56.325
12-10	6.6	6.544	99.160	.000	.900	15.944	.000	18.76	1.59	16.875	25.357	42.231
12-11	6.0	5.262	90.873	.000	.562	14.346	.000	18.64	1.67	10.480	23.908	34.388
12-12	6.0	4.947	85.228	.000	.536	13.521	.000	18.65	1.65	9.996	22.362	32.358
12-13	5.3	3.962	76.537	.000	.505	12.546	.000	18.66	1.62	9.423	20.308	29.731
S TOT	1.0	182.329	1699.932	.000	20.991	283.676	.000	18.66	1.64	391.719	466.372	858.091
AFTER	1.0	2.554	505.424	.000	.613	109.797	.000	18.53	1.67	11.366	182.890	194.255
TOTAL	1.0	184.883	2205.356	.000	21.605	393.473	.000	18.66	1.65	403.084	649.262	1052.346

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD AL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.022	5.403	2.823	38.607	79.704	5.10	.000	79.704	79.704	76.114
12-03	2.816	4.808	2.547	38.607	68.980	5.44	.000	68.980	148.685	135.993
12-04	2.498	4.337	2.307	38.607	58.397	5.84	.000	58.397	207.082	182.127
12-05	1.960	3.948	2.073	38.607	45.982	6.42	.000	45.982	253.063	215.114
12-06	1.854	3.314	1.835	41.973	32.999	7.49	.000	32.999	286.062	236.639
12-07	1.754	2.722	1.615	37.926	28.049	7.51	.000	28.049	314.111	253.272
12-08	1.549	2.364	1.384	33.772	23.914	7.58	.000	23.914	338.025	266.162
12-09	1.403	2.095	1.220	30.805	20.804	7.66	.000	20.804	358.829	276.356
12-10	.814	1.987	.839	20.481	18.110	6.78	.000	18.110	376.938	284.423
12-11	.518	1.873	.637	15.319	16.041	6.21	.000	16.041	392.980	290.918
12-12	.494	1.753	.600	15.319	14.193	6.51	.000	14.193	407.173	296.142
12-13	.465	1.594	.545	14.668	12.459	6.65	.000	12.459	419.632	300.312
S TOT	19.147	36.199	18.424	364.689	419.632	9.65	.000	419.632	419.632	300.312
AFTER	.687	14.635	1.862	67.613	109.459	9.65	.000	109.459	529.091	319.313
TOTAL	19.834	50.834	20.286	432.302	529.091	9.65	.000	529.091	529.091	319.313

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	461.0	9.0	LIFE, YRS.	40.25	8.00	344.466
GROSS ULT., MB & MMF	27244.200	15643.900	DISCOUNT %	10.00	10.00	319.313
GROSS CUM., MB & MMF	27059.320	13438.550	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	298.300
GROSS RES., MB & MMF	184.883	2205.356	DISCOUNTED PAYOUT, YRS.	.00	15.00	272.475
NET RES., MB & MMF	21.605	393.473	UNDISCOUNTED NET/INVEST.	.00	20.00	239.785
NET REVENUE, M$	403.084	649.262	DISCOUNTED NET/INVEST.	.00	25.00	215.452
INITIAL PRICE, $	16.227	2.268	RATE-OF-RETURN, PCT.	100.00	35.00	181.292
INITIAL N.I., PCT.	12.690	15.579	INITIAL W.I., PCT.	15.274	50.00	149.218
					70.00	123.323
					100.00	100.544

SWR INST INCOME FUND X-C	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	08:59:45
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10C

EFFECTIVE DATE: 1/02

-END-  MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	30.0	30.259	198.643	.000	2.532	32.812	.000	18.31	1.84	46.348	60.415	106.763
12-03	30.0	27.534	173.951	.000	2.343	29.607	.000	18.32	1.80	42.928	53.227	96.155
12-04	23.8	20.433	155.311	.000	2.061	27.002	.000	18.45	1.77	38.037	47.675	85.711
12-05	5.0	5.191	140.469	.000	1.587	24.798	.000	18.93	1.74	30.058	43.169	73.228
12-06	4.0	4.819	128.209	.000	1.495	22.886	.000	18.94	1.72	28.311	39.392	67.702
12-07	4.0	4.499	117.811	.000	1.411	21.198	.000	18.94	1.71	26.732	36.150	62.882
12-08	3.4	3.898	105.705	.000	1.204	18.413	.000	18.92	1.71	22.778	31.431	54.210
12-09	3.0	3.471	96.081	.000	1.061	16.344	.000	18.91	1.71	20.061	27.880	47.942
12-10	2.3	1.779	86.177	.000	.413	13.965	.000	18.79	1.90	7.768	26.501	34.268
12-11	2.0	.930	78.844	.000	.097	12.426	.000	18.16	2.01	1.768	25.027	26.795
12-12	2.0	.866	73.824	.000	.091	11.658	.000	18.16	2.01	1.650	23.452	25.102
12-13	1.9	.755	66.794	.000	.080	10.740	.000	18.17	1.99	1.460	21.377	22.838
S TOT	1.0	104.435	1421.817	.000	14.376	241.850	.000	18.63	1.80	267.899	435.697	703.596
AFTER	1.0	1.641	502.197	.000	.355	108.648	.000	18.30	1.69	6.495	183.615	190.111
TOTAL	1.0	106.076	1924.015	.000	14.731	350.498	.000	18.63	1.77	274.394	619.313	893.707

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.384	4.670	2.284	25.595	71.829	4.37	.000	71.829	71.829	68.594
12-03	2.205	4.123	2.034	25.595	62.197	4.67	.000	62.197	134.026	122.584
12-04	1.915	3.699	1.822	25.595	52.680	5.03	.000	52.680	186.707	164.204
12-05	1.402	3.353	1.613	25.595	41.264	5.59	.000	41.264	227.970	193.805
12-06	1.321	3.063	1.485	32.688	29.146	7.26	.000	29.146	257.116	212.817
12-07	1.247	2.814	1.375	32.688	24.759	7.71	.000	24.759	281.874	227.499
12-08	1.064	2.454	1.154	28.534	21.004	7.77	.000	21.004	302.878	238.821
12-09	.938	2.181	1.000	25.567	18.255	7.84	.000	18.255	321.134	247.766
12-10	.372	2.073	.631	15.243	15.951	6.68	.000	15.951	337.084	254.871
12-11	.095	1.957	.437	10.081	14.225	5.80	.000	14.225	351.309	260.630
12-12	.089	1.834	.409	10.081	12.690	6.10	.000	12.690	363.999	265.301
12-13	.079	1.674	.363	9.430	11.292	6.17	.000	11.292	375.291	269.079
S TOT	13.111	33.895	14.606	266.693	375.291	9.65	.000	375.291	375.291	269.079
AFTER	.455	14.689	1.750	64.121	109.096	9.65	.000	109.096	484.387	287.967
TOTAL	13.566	48.584	16.356	330.814	484.387	9.65	.000	484.387	484.387	287.967

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	266.0	3.0	LIFE, YRS.	40.25	8.00	311.115
GROSS ULT., MB & MMF	16559.930	11196.780	DISCOUNT %	10.00	10.00	287.967
GROSS CUM., MB & MMF	16453.850	9272.761	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	268.727
GROSS RES., MB & MMF	106.076	1924.015	DISCOUNTED PAYOUT, YRS.	.00	15.00	245.202
NET RES., MB & MMF	14.731	350.498	UNDISCOUNTED NET/INVEST.	.00	20.00	215.601
NET REVENUE, M$	274.394	619.313	DISCOUNTED NET/INVEST.	.00	25.00	193.676
INITIAL PRICE, $	15.801	2.340	RATE-OF-RETURN, PCT.	100.00	35.00	163.004
INITIAL N.I., PCT.	4.361	16.245	INITIAL W.I., PCT.	7.373	50.00	134.252
					70.00	111.028
					100.00	90.570

SWR INST INCOME FUND X-C	DATE	:	02/18/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	09:15:58
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  IN10C

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	10.0	10.059	45.628	.000	.697	6.479	.000	18.69	1.51	13.028	9.769	22.797
12-03	10.0	9.496	42.919	.000	.667	6.164	.000	18.70	1.48	12.474	9.128	21.602
12-04	9.4	8.681	37.602	.000	.638	5.858	.000	18.70	1.45	11.930	8.505	20.435
12-05	9.0	8.005	33.430	.000	.610	5.572	.000	18.71	1.42	11.414	7.927	19.342
12-06	7.6	7.568	26.025	.000	.584	3.865	.000	18.71	.86	10.931	3.341	14.272
12-07	5.0	6.245	16.353	.000	.556	2.171	.000	18.72	-.56	10.405	-1.221	9.184
12-08	5.0	5.893	15.425	.000	.532	2.106	.000	18.73	-.57	9.965	-1.191	8.774
12-09	5.0	5.562	14.574	.000	.510	2.043	.000	18.73	-.57	9.545	-1.162	8.383
12-10	4.3	4.765	12.983	.000	.486	1.980	.000	18.74	-.58	9.107	-1.144	7.963
12-11	4.0	4.332	12.029	.000	.465	1.920	.000	18.74	-.58	8.712	-1.119	7.593
12-12	4.0	4.080	11.403	.000	.445	1.863	.000	18.74	-.59	8.346	-1.090	7.255
12-13	3.4	3.207	9.743	.000	.425	1.805	.000	18.75	-.59	7.962	-1.069	6.893
S TOT	1.6	77.894	278.114	.000	6.615	41.826	.000	18.72	.73	123.820	30.675	154.495
AFTER	1.6	.914	3.226	.000	.258	1.149	.000	18.85	-.63	4.870	-.725	4.145
TOTAL	1.6	78.808	281.341	.000	6.873	42.975	.000	18.72	.70	128.690	29.949	158.640

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.638	.733	.540	13.011	7.875	8.40	.000	7.875	7.875	7.520
12-03	.610	.685	.512	13.011	6.783	8.75	.000	6.783	14.658	13.409
12-04	.583	.638	.485	13.011	5.717	9.12	.000	5.717	20.375	17.922
12-05	.557	.595	.460	13.011	4.718	9.50	.000	4.718	25.093	21.308
12-06	.533	.251	.350	9.284	3.853	8.48	.000	3.853	28.946	23.822
12-07	.507	-.091	.240	5.238	3.290	6.42	.000	3.290	32.236	25.772
12-08	.485	-.089	.230	5.238	2.911	6.64	.000	2.911	35.147	27.341
12-09	.464	-.087	.220	5.238	2.548	6.86	.000	2.548	37.695	28.590
12-10	.443	-.086	.209	5.238	2.159	7.11	.000	2.159	39.854	29.552
12-11	.423	-.084	.199	5.238	1.816	7.36	.000	1.816	41.670	30.288
12-12	.405	-.082	.191	5.238	1.503	7.61	.000	1.503	43.174	30.841
12-13	.386	-.080	.182	5.238	1.168	7.89	.000	1.168	44.341	31.233
S TOT	6.036	2.304	3.817	97.996	44.341	8.41	.000	44.341	44.341	31.233
AFTER	.232	-.054	.113	3.492	.363	8.41	.000	.363	44.704	31.346
TOTAL	6.268	2.250	3.930	101.488	44.704	8.41	.000	44.704	44.704	31.346

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	195.0	6.0	LIFE, YRS.	12.67	8.00	33.351
GROSS ULT., MB & MMF	10684.270	4447.129	DISCOUNT %	10.00	10.00	31.346
GROSS CUM., MB & MMF	10605.460	4165.788	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	29.573
GROSS RES., MB & MMF	78.808	281.341	DISCOUNTED PAYOUT, YRS.	.00	15.00	27.273
NET RES., MB & MMF	6.873	42.975	UNDISCOUNTED NET/INVEST.	.00	20.00	24.184
NET REVENUE, M$	128.690	29.949	DISCOUNTED NET/INVEST.	.00	25.00	21.776
INITIAL PRICE, $	16.821	2.044	RATE-OF-RETURN, PCT.	100.00	35.00	18.289
INITIAL N.I., PCT.	24.310	13.511	INITIAL W.I., PCT.	27.230	50.00	14.966
					70.00	12.295
					100.00	9.974

APPENDIX B16

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SWRI Combo Income/Drilling Fund 1988 (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 2 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 100 percent of the total net remaining liquid hydrocarbon reserves and 100 percent of the total net remaining gas reserves. The properties that we reviewed represent 100 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in the properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SWRI Combo Income/Drilling Fund 1988

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		5,138		0		4,024		9,162
Gas—MMCF		14		0		7		21
Income Data
Future Gross Revenue	$	112,969	$	0	$	86,778	$	199,747
Deductions		107,588		0		21,591		129,179
Future Net Income (FNI)	$	5,381	$	0	$	65,187	$	70,568
Discounted FNI @ 10%	$	5,133	$	0	$	41,722	$	46,855

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		0		0		0		0
Gas—MMCF		0		0		0		0
Income Data
Future Gross Revenue	$	0	$	0	$	0	$	0
Deductions		0		0		0		0
Future Net Income (FNI)	$	0	$	0	$	0	$	0
Discounted FNI @ 10%	$	0	$	0	$	0	$	0
Total Net Reserves
Oil/Condensate—Barrels		5,138		0		4,024		9,162
Gas—MMCF		14		0		7		21
Income Data
Future Gross Revenue	$	112,969	$	0	$	86,778	$	199,747
Deductions		107,588		0		21,591		129,179
Future Net Income (FNI)		5,381	$	0	$	65,187	$	70,568
Discounted FNI @ 10%	$	5,133	$	0	$	41,722	$	46,855

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion?… The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimate of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed. It is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Reserve Estimates

The reserves for the properties that we reviewed were estimated by the performance method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimate for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimate reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimate of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SWRI COMBO INCOME/DRILLING FUND 1988	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:11
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  COM88

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD   MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	8.0	5.892	15.974	.000	3.478	9.430	.000	16.94	2.33	58.920	21.972	80.892
12-03	4.7	11.866	22.942	.000	2.328	5.594	.000	17.24	2.43	40.140	13.567	53.707
12-04	1.0	8.349	14.193	.000	.616	1.047	.000	17.99	2.80	11.084	2.933	14.016
12-05	1.0	5.884	10.003	.000	.434	.738	.000	17.99	2.80	7.811	2.067	9.878
12-06	1.0	4.638	7.885	.000	.342	.582	.000	17.99	2.80	6.157	1.629	7.786
12-07	1.0	3.870	6.579	.000	.286	.486	.000	17.99	2.80	5.138	1.359	6.497
12-08	1.0	3.344	5.684	.000	.247	.419	.000	17.99	2.80	4.439	1.174	5.613
12-09	1.0	2.958	5.028	.000	.218	.371	.000	17.99	2.80	3.927	1.039	4.966
12-10	1.0	2.657	4.517	.000	.196	.333	.000	17.99	2.80	3.527	.933	4.461
12-11	1.0	2.391	4.065	.000	.176	.300	.000	17.99	2.80	3.175	.840	4.015
12-12	1.0	2.152	3.659	.000	.159	.270	.000	17.99	2.80	2.857	.756	3.613
12-13	1.0	1.937	3.293	.000	.143	.243	.000	17.99	2.80	2.572	.680	3.252
S TOT	1.0	55.938	103.823	.000	8.624	19.813	.000	17.36	2.47	149.747	48.950	198.697
AFTER	1.0	7.295	12.402	.000	.538	.915	.000	17.99	2.80	9.685	2.563	12.248
TOTAL	1.0	63.233	116.225	.000	9.162	20.729	.000	17.40	2.49	159.432	51.513	210.944

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.710	1.648	2.296	69.466	4.772	15.07	.000	4.772	4.772	4.588
12-03	1.846	1.018	1.525	35.532	13.785	12.24	.000	13.785	18.557	16.410
12-04	.510	.220	.399	1.199	11.689	2.94	.000	11.689	30.246	25.658
12-05	.359	.155	.281	1.199	7.884	3.58	.000	7.884	38.130	31.322
12-06	.283	.122	.221	1.199	5.960	4.16	.000	5.960	44.090	35.213
12-07	.236	.102	.185	1.199	4.775	4.70	.000	4.775	48.865	38.045
12-08	.204	.088	.160	1.199	3.962	5.21	.000	3.962	52.827	40.181
12-09	.181	.078	.141	1.199	3.367	5.71	.000	3.367	56.194	41.831
12-10	.162	.070	.127	1.199	2.902	6.19	.000	2.902	59.096	43.124
12-11	.146	.063	.114	1.199	2.492	6.72	.000	2.492	61.588	44.133
12-12	.131	.057	.103	1.199	2.123	7.31	.000	2.123	63.711	44.915
12-13	.118	.051	.092	1.199	1.791	7.96	.000	1.791	65.502	45.515
S TOT	6.888	3.671	5.644	116.991	65.502	14.94	.000	65.502	65.502	45.515
AFTER	.446	.192	.348	6.196	5.065	14.94	.000	5.065	70.568	46.854
TOTAL	7.334	3.863	5.992	123.187	70.568	14.94	.000	70.568	70.568	46.854

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	9.0	.0	LIFE, YRS.	17.17	8.00	50.290
GROSS ULT., MB & MMF	810.638	1691.437	DISCOUNT %	10.00	10.00	46.854
GROSS CUM., MB & MMF	747.405	1575.212	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	43.846
GROSS RES., MB & MMF	63.233	116.225	DISCOUNTED PAYOUT, YRS.	.00	15.00	39.981
NET RES., MB & MMF	9.162	20.729	UNDISCOUNTED NET/INVEST.	.00	20.00	34.845
NET REVENUE, M$	159.432	51.513	DISCOUNTED NET/INVEST.	.00	25.00	30.873
INITIAL PRICE, $	17.719	2.631	RATE-OF-RETURN, PCT.	100.00	35.00	25.144
INITIAL N.I., PCT.	20.729	25.901	INITIAL W.I., PCT.	23.959	50.00	19.687
					70.00	15.304
					100.00	11.540

SWRI COMBO INCOME/DRILLING FUND 1988	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:10
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  COM88

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	8.0	5.892	15.974	.000	3.478	9.430	.000	16.94	2.33	58.920	21.972	80.892
12-03	8.0	2.812	7.551	.000	1.660	4.458	.000	16.94	2.33	28.121	10.387	38.507
12-04
12-05
12-06
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	8.0	8.704	23.525	.000	5.138	13.888	.000	16.94	2.33	87.041	32.359	119.400
AFTER	8.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	8.0	8.704	23.525	.000	5.138	13.888	.000	16.94	2.33	87.041	32.359	119.400

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.710	1.648	2.296	69.466	4.772	15.07	.000	4.772	4.772	4.588
12-03	1.294	.779	1.093	34.733	.609	15.77	.000	.609	5.381	5.133
12-04
12-05
12-06
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	4.004	2.427	3.389	104.199	5.381	15.77	.000	5.381	5.381	5.133
AFTER	.000	.000	.000	.000	.000	15.77	.000	.000	5.381	5.133
TOTAL	4.004	2.427	3.389	104.199	5.381	15.77	.000	5.381	5.381	5.133

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	8.0	.0	LIFE, YRS.	1.50	8.00	5.179
GROSS ULT., MB & MMF	756.109	1598.737	DISCOUNT %	10.00	10.00	5.133
GROSS CUM., MB & MMF	747.405	1575.212	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	5.088
GROSS RES., MB & MMF	8.704	23.525	DISCOUNTED PAYOUT, YRS.	.00	15.00	5.023
NET RES., MB & MMF	5.138	13.888	UNDISCOUNTED NET/INVEST.	.00	20.00	4.921
NET REVENUE, M$	87.041	32.359	DISCOUNTED NET/INVEST.	.00	25.00	4.826
INITIAL PRICE, $	16.940	2.330	RATE-OF-RETURN, PCT.	100.00	35.00	4.655
INITIAL N.I., PCT.	59.035	59.035	INITIAL W.I., PCT.	67.469	50.00	4.435
					70.00	4.195
					100.00	3.912

SWRI COMBO INCOME/DRILLING FUND 1988	DATE	:	02/18/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	07:51:10
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  COM88

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M$	NET GAS SALES   M$	TOTAL NET SALES   M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.7	9.054	15.391	.000	.668	1.136	.000	17.99	2.80	12.019	3.180	15.199
12-04	1.0	8.349	14.193	.000	.616	1.047	.000	17.99	2.80	11.084	2.933	14.016
12-05	1.0	5.884	10.003	.000	.434	.738	.000	17.99	2.80	7.811	2.067	9.878
12-06	1.0	4.638	7.885	.000	.342	.582	.000	17.99	2.80	6.157	1.629	7.786
12-07	1.0	3.870	6.579	.000	.286	.486	.000	17.99	2.80	5.138	1.359	6.497
12-08	1.0	3.344	5.684	.000	.247	.419	.000	17.99	2.80	4.439	1.174	5.613
12-09	1.0	2.958	5.028	.000	.218	.371	.000	17.99	2.80	3.927	1.039	4.966
12-10	1.0	2.657	4.517	.000	.196	.333	.000	17.99	2.80	3.527	.933	4.461
12-11	1.0	2.391	4.065	.000	.176	.300	.000	17.99	2.80	3.175	.840	4.015
12-12	1.0	2.152	3.659	.000	.159	.270	.000	17.99	2.80	2.857	.756	3.613
12-13	1.0	1.937	3.293	.000	.143	.243	.000	17.99	2.80	2.572	.680	3.252
S TOT	1.0	47.234	80.298	.000	3.486	5.926	.000	17.99	2.80	62.706	16.591	79.297
AFTER	1.0	7.295	12.402	.000	.538	.915	.000	17.99	2.80	9.685	2.563	12.248
TOTAL	1.0	54.529	92.700	.000	4.024	6.841	.000	17.99	2.80	72.391	19.154	91.545

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.553	.239	.432	.800	13.176	2.36	.000	13.176	13.176	11.277
12-04	.510	.220	.399	1.199	11.689	2.94	.000	11.689	24.865	20.526
12-05	.359	.155	.281	1.199	7.884	3.58	.000	7.884	32.749	26.190
12-06	.283	.122	.221	1.199	5.960	4.16	.000	5.960	38.709	30.080
12-07	.236	.102	.185	1.199	4.775	4.70	.000	4.775	43.484	32.912
12-08	.204	.088	.160	1.199	3.962	5.21	.000	3.962	47.446	35.048
12-09	.181	.078	.141	1.199	3.367	5.71	.000	3.367	50.812	36.698
12-10	.162	.070	.127	1.199	2.902	6.19	.000	2.902	53.715	37.991
12-11	.146	.063	.114	1.199	2.492	6.72	.000	2.492	56.207	39.001
12-12	.131	.057	.103	1.199	2.123	7.31	.000	2.123	58.330	39.782
12-13	.118	.051	.092	1.199	1.791	7.96	.000	1.791	60.121	40.382
S TOT	2.884	1.244	2.255	12.792	60.121	14.94	.000	60.121	60.121	40.382
AFTER	.446	.192	.348	6.196	5.065	14.94	.000	5.065	65.187	41.722
TOTAL	3.330	1.437	2.603	18.988	65.187	14.94	.000	65.187	65.187	41.722

	OIL	GAS			P.W. %	P.W, M$
GROSS WELLS	1.0	.0	LIFE, YRS.	17.17	8.00	45.111
GROSS ULT., MB & MMF	54.529	92.700	DISCOUNT %	10.00	10.00	41.722
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	38.758
GROSS RES., MB & MMF	54.529	92.700	DISCOUNTED PAYOUT, YRS.	.00	15.00	34.958
NET RES., MB & MMF	4.024	6.841	UNDISCOUNTED NET/INVEST.	.00	20.00	29.924
NET REVENUE, M$	72.391	19.154	DISCOUNTED NET/INVEST.	.00	25.00	26.046
INITIAL PRICE, $	17.990	2.800	RATE-OF-RETURN, PCT.	100.00	35.00	20.489
INITIAL N.I., PCT.	7.379	7.379	INITIAL W.I., PCT.	8.434	50.00	15.252
					70.00	11.109
					100.00	7.628

APPENDIX B17

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Development Drilling Fund 1990 (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 2 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 93.9 percent of the total net remaining liquid hydrocarbon reserves and 90.4 percent of the total net remaining gas reserves. The properties that we reviewed represent 98.0 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Development Drilling Fund 1990

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		42,477		0		0		42,477
Gas—MMCF		94		0		0		94
Income Data
Future Gross Revenue	$	904,963	$	0	$	0	$	904,963
Deductions		619,980		0		0		619,980
Future Net Income (FNI)	$	284,983	$	0	$	0	$	284,983
Discounted FNI @ 10%	$	184,688	$	0	$	0	$	184,688

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		2,783		0		0		2,783
Gas—MMCF		10		0		0		10
Income Data
Future Gross Revenue	$	71,512	$	0	$	0	$	71,512
Deductions		67,483		0		0		67,483
Future Net Income (FNI)	$	4,029	$	0	$	0	$	4,029
Discounted FNI @ 10%	$	3,755	$	0	$	0	$	3,755
Total Net Reserves
Oil/Condensate—Barrels		45,260		0		0		45,260
Gas—MMCF		104		0		0		104
Income Data
Future Gross Revenue	$	976,475	$	0	$	0	$	976,475
Deductions		687,463		0		0		687,463
Future Net Income (FNI)	$	289,012	$	0	$	0	$	289,012
Discounted FNI @ 10%	$	188,443	$	0	$	0	$	188,443

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 6.1 percent of the total net remaining liquid hydrocarbon reserves and 9.6 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW DEV DRILLING FUND 1990	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	17:46:39
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR90

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD   MMCF	GROSS NGL PROD   MBBLS	NET OIL PROD MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE   $/MCF	NET  LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	3.0	11.084	25.793	.000	5.209	12.680	.000	17.63	2.23	91.848	28.246	120.094
12-03	3.0	10.378	24.274	.000	4.892	11.965	.000	17.67	2.23	86.428	26.697	113.125
12-04	2.3	8.279	17.740	.000	3.758	8.335	.000	17.39	2.19	65.362	18.270	83.633
12-05	2.0	7.335	15.114	.000	3.277	6.935	.000	17.28	2.17	56.624	15.070	71.694
12-06	2.0	6.953	14.359	.000	3.110	6.599	.000	17.30	2.18	53.810	14.353	68.163
12-07	2.0	6.613	13.680	.000	2.962	6.294	.000	17.31	2.18	51.274	13.700	64.974
12-08	2.0	6.307	13.062	.000	2.827	6.014	.000	17.32	2.18	48.963	13.098	62.061
12-09	2.0	6.019	12.480	.000	2.700	5.750	.000	17.33	2.18	46.787	12.530	59.317
12-10	2.0	5.744	11.924	.000	2.578	5.498	.000	17.34	2.18	44.708	11.987	56.695
12-11	2.0	5.483	11.393	.000	2.463	5.257	.000	17.35	2.18	42.723	11.467	54.190
12-12	2.0	5.233	10.887	.000	2.352	5.027	.000	17.36	2.18	40.827	10.971	51.798
12-13	1.6	3.820	8.389	.000	1.779	4.005	.000	17.78	2.23	31.631	8.941	40.572
S TOT	1.0	83.248	179.096	.000	37.905	84.361	.000	17.44	2.20	660.985	185.329	846.314
AFTER	1.0	14.167	36.524	.000	7.355	18.962	.000	18.99	2.35	139.671	44.562	184.232
TOTAL	1.0	97.415	215.621	.000	45.260	103.323	.000	17.69	2.22	800.656	229.891	1030.547

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX   M$	LEASE OP EXPENSES   M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	4.225	2.118	3.413	67.172	43.166	10.51	.000	43.166	43.166	41.224
12-03	3.976	2.002	3.214	67.172	36.760	11.09	.000	36.760	79.926	73.140
12-04	3.007	1.370	2.378	45.393	31.485	10.13	.000	31.485	111.411	97.985
12-05	2.605	1.130	2.039	38.133	27.787	9.91	.000	27.787	139.198	117.917
12-06	2.475	1.076	1.938	38.133	24.540	10.36	.000	24.540	163.738	133.920
12-07	2.359	1.027	1.848	38.133	21.607	10.81	.000	21.607	185.345	146.730
12-08	2.252	.982	1.765	38.133	18.929	11.27	.000	18.929	204.274	156.932
12-09	2.152	.940	1.687	38.133	16.405	11.73	.000	16.405	220.679	164.971
12-10	2.057	.899	1.612	38.133	13.994	12.22	.000	13.994	234.673	171.206
12-11	1.965	.860	1.541	38.133	11.691	12.73	.000	11.691	246.363	175.943
12-12	1.878	.823	1.473	38.133	9.491	13.26	.000	9.491	255.854	179.439
12-13	1.455	.671	1.153	29.800	7.492	13.52	.000	7.492	263.347	181.948
S TOT	30.405	13.900	24.060	514.602	263.347	17.21	.000	263.347	263.347	181.948
AFTER	6.425	3.342	5.234	143.567	25.665	17.21	.000	25.665	289.012	188.443
TOTAL	36.830	17.242	29.294	658.169	289.012	17.21	.000	289.012	289.012	188.443

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	3.0	.0	LIFE, YRS.	19.92	8.00	202.583
GROSS ULT., MB & MMF	6126.109	654.042	DISCOUNT %	10.00	10.00	188.443
GROSS CUM., MB & MMF	6028.694	438.421	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	176.203
GROSS RES., MB & MMF	97.415	215.621	DISCOUNTED PAYOUT, YRS.	.00	15.00	160.686
NET RES., MB & MMF	45.260	103.323	UNDISCOUNTED NET/INVEST.	.00	20.00	140.461
NET REVENUE, MS	800.656	229.891	DISCOUNTED NET/INVEST.	.00	25.00	125.156
INITIAL PRICE, $	17.370	2.197	RATE-OF-RETURN, PCT.	100.00	35.00	103.646
INITIAL N.I., PCT.	46.917	49.086	INITIAL W.I., PCT.	56.764	50.00	83.796
					70.00	68.248
					100.00	55.018

SW DEV DRILLING FUND 1990	DATE	:	02/17/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	17:58:48
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR90

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES   M$
12-02	2.0	8.867	18.066	.000	3.932	8.229	.000	17.19	2.16	67.605	17.785	85.390
12-03	2.0	8.272	16.933	.000	3.679	7.737	.000	17.23	2.17	63.397	16.759	80.156
12-04	2.0	7.770	15.963	.000	3.464	7.311	.000	17.26	2.17	59.787	15.865	75.651
12-05	2.0	7.335	15.114	.000	3.277	6.935	.000	17.28	2.17	56.624	15.070	71.694
12-06	2.0	6.953	14.359	.000	3.110	6.599	.000	17.30	2.18	53.810	14.353	68.163
12-07	2.0	6.613	13.680	.000	2.962	6.294	.000	17.31	2.18	51.274	13.700	64.974
12-08	2.0	6.307	13.062	.000	2.827	6.014	.000	17.32	2.18	48.963	13.098	62.061
12-09	2.0	6.019	12.480	.000	2.700	5.750	.000	17.33	2.18	46.787	12.530	59.317
12-10	2.0	5.744	11.924	.000	2.578	5.498	.000	17.34	2.18	44.708	11.987	56.695
12-11	2.0	5.483	11.393	.000	2.463	5.257	.000	17.35	2.18	42.723	11.467	54.190
12-12	2.0	5.233	10.887	.000	2.352	5.027	.000	17.36	2.18	40.827	10.971	51.798
12-13	1.6	3.820	8.389	.000	1.779	4.005	.000	17.78	2.23	31.631	8.941	40.572
S TOT	1.0	78.417	162.250	.000	35.122	74.657	.000	17.31	2.18	608.135	162.526	770.661
AFTER	1.0	14.167	36.524	.000	7.355	18.962	.000	18.99	2.35	139.671	44.562	184.232
TOTAL	1.0	92.583	198.775	.000	42.477	93.619	.000	17.60	2.21	747.806	207.087	954.894

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX M$	AD VAL TAX   M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.110	1.334	2.428	38.133	40.385	8.49	.000	40.385	40.385	38.560
12-03	2.916	1.257	2.279	38.133	35.571	8.97	.000	35.571	75.956	69.434
12-04	2.750	1.190	2.151	38.133	31.427	9.44	.000	31.427	107.383	94.231
12-05	2.605	1.130	2.039	38.133	27.787	9.91	.000	27.787	135.170	114.163
12-06	2.475	1.076	1.938	38.133	24.540	10.36	.000	24.540	159.709	130.166
12-07	2.359	1.027	1.848	38.133	21.607	10.81	.000	21.607	181.316	142.975
12-08	2.252	.982	1.765	38.133	18.929	11.27	.000	18.929	200.245	153.178
12-09	2.152	.940	1.687	38.133	16.405	11.73	.000	16.405	216.650	161.217
12-10	2.057	.899	1.612	38.133	13.994	12.22	.000	13.994	230.644	167.452
12-11	1.965	.860	1.541	38.133	11.691	12.73	.000	11.691	242.335	172.188
12-12	1.878	.823	1.473	38.133	9.491	13.26	.000	9.491	251.825	175.684
12-13	1.455	.671	1.153	29.800	7.492	13.52	.000	7.492	259.318	178.194
S TOT	27.974	12.189	21.915	449.264	259.318	17.21	.000	259.318	259.318	178.194
AFTER	6.425	3.342	5.234	143.567	25.665	17.21	.000	25.665	284.983	184.688
TOTAL	34.399	15.532	27.149	592.831	284.983	17.21	.000	284.983	284.983	184.688

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	19.92	8.00	198.778
GROSS ULT., MB & MMF	6074.584	515.311	DISCOUNT %	10.00	10.00	184.688
GROSS CUM., MB & MMF	5982.000	316.536	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	172.497
GROSS RES., MB & MMF	92.583	198.775	DISCOUNTED PAYOUT, YRS.	.00	15.00	157.050
NET RES., MB & MMF	42.477	93.619	UNDISCOUNTED NET/INVEST.	.00	20.00	136.932
NET REVENUE, M$	747.806	207.087	DISCOUNTED NET/INVEST.	.00	25.00	121.727
INITIAL PRICE, $	16.970	2.132	RATE-OF-RETURN, PCT.	100.00	35.00	100.392
INITIAL N.I ., PCT.	44.275	45.473	INITIAL W.I., PCT.	53.902	50.00	80.760
					70.00	65.442
					100.00	52.471

SW DEV DRILLING FUND 1990	DATE	:	02/17/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	18:13:40
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR90

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES   M$	TOTAL NET SALES M$
12-02	1.0	2.216	7.728	.000	1.277	4.451	.000	18.99	2.35	24.243	10.460	34.703
12-03	1.0	2.105	7.341	.000	1.213	4.229	.000	18.99	2.35	23.031	9.937	32.968
12-04	1.0	.510	1.777	.000	.294	1.024	.000	18.99	2.35	5.576	2.406	7.981
12-05
12-06
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	4.832	16.846	.000	2.783	9.704	.000	18.99	2.35	52.850	22.803	75.653
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	4.832	16.846	.000	2.783	9.704	.000	18.99	2.35	52.850	22.803	75.653

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX   M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	1.115	.785	.984	29.039	2.781	15.82	.000	2.781	2.781	2.665
12-03	1.059	.745	.935	29.039	1.190	16.57	.000	1.190	3.970	3.707
12-04	.256	.180	.226	7.260	.058	17.07	.000	.058	4.029	3.755
12-05
12-06
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	2.431	1.710	2.145	65.338	4.029	17.07	.000	4.029	4.029	3.755
AFTER	.000	.000	.000	.000	.000	17.07	.000	.000	4.029	3.755
TOTAL	2.431	1.710	2.145	65.338	4.029	17.07	.000	4.029	4.029	3.755

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	2.25	8.00	3.805
GROSS ULT., MB & MMF	51.526	138.731	DISCOUNT %	10.00	10.00	3.755
GROSS CUM., MB & MMF	46.694	121.885	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	3.706
GROSS RES., MB & MMF	4.832	16.846	DISCOUNTED PAYOUT, YRS.	.00	15.00	3.636
NET RES., MB & MMF	2.783	9.704	UNDISCOUNTED NET/INVEST.	.00	20.00	3.528
NET REVENUE, M$	52.850	22.803	DISCOUNTED NET/INVEST.	.00	25.00	3.429
INITIAL PRICE, $	18.990	2.350	RATE-OF-RETURN, PCT.	100.00	35.00	3.254
INITIAL N.I ., PCT.	57.601	57.601	INITIAL W.I., PCT.	65.830	50.00	3.036
					70.00	2.806
					100.00	2.547

APPENDIX B18

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Development Drilling Fund 1991-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 4 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 100 percent of the total net remaining liquid hydrocarbon reserves and 100 percent of the total net remaining gas reserves. The properties that we reviewed represent 100 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Development Drilling Fund 1991-A

As of January 1, 2002

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		23,827		1,624		0		25,451
Gas—MMCF		28		2		0		30
Income Data
Future Gross Revenue	$	490,496	$	33,581	$	0	$	524,077
Deductions		361,887		3,647		0		365,534
Future Net Income (FNI)	$	128,609	$	29,934	$	0	$	158,543
Discounted FNI @ 10%	$	99,071	$	22,139	$	0	$	121,210

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		0		0		0		0
Gas—MMCF		0		0		0		0
Income Data
Future Gross Revenue	$	0	$	0	$	0	$	0
Deductions		0		0		0		0
Future Net Income (FNI)	$	0	$	0	$	0	$	0
Discounted FNI @ 10%	$	0	$	0	$	0	$	0
Total Net Reserves
Oil/Condensate—Barrels		23,827		1,624		0		24,451
Gas—MMCF		28		2		0		30
Income Data
Future Gross Revenue	$	490,496	$	33,581	$	0	$	524,077
Deductions		361,887		3,647		0		365,534
Future Net Income (FNI)	$	128,609	$	29,934	$	0	$	158.543
Discounted FNI @ 10%	$	99,071	$	22,139	$	0	$	121,210

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E.   Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW DEV DRILLING FUND 1991-A	DATE	:	02/17/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	17:58:49
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR91A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.5	28.370	55.536	.000	3.426	4.445	.000	18.95	2.24	64.919	9.947	74.866
12-03	3.8	61.295	104.624	.000	3.443	4.534	.000	18.98	2.22	65.341	10.079	75.420
12-04	4.0	58.628	100.075	.000	3.211	4.233	.000	18.98	2.23	60.945	9.421	70.366
12-05	3.7	50.024	82.254	.000	2.920	3.660	.000	18.98	2.25	55.435	8.248	63.684
12-06	3.0	35.346	51.624	.000	2.610	2.904	.000	18.99	2.32	49.570	6.730	56.300
12-07	3.0	25.224	36.526	.000	2.403	2.655	.000	18.98	2.33	45.625	6.174	51.799
12-08	3.0	18.202	26.072	.000	2.225	2.445	.000	18.98	2.33	42.226	5.701	47.926
12-09	3.0	13.313	18.814	.000	2.068	2.263	.000	18.98	2.34	39.241	5.289	44.530
12-10	3.0	9.896	13.758	.000	1.928	2.104	.000	18.98	2.34	36.578	4.924	41.503
12-11	2.3	5.046	6.882	.000	1.214	1.323	.000	18.97	2.34	23.040	3.100	26.139
12-12	1.0	.304	.456	.000	.003	.005	.000	19.22	2.03	.060	.009	.069
12-13
S TOT	1.0	305.648	496.621	.000	25.452	30.572	.000	18.98	2.28	482.980	69.622	552.602
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	305.648	496.621	.000	25.452	30.572	.000	18.98	2.28	482.980	69.622	552.602

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.137	.757	1.974	37.859	31.140	10.49	.000	31.140	31.140	29.700
12-03	3.251	.769	1.902	38.064	31.434	10.48	.000	31.434	62.574	56.959
12-04	3.023	.719	1.783	38.088	26.754	11.14	.000	26.754	89.327	78.082
12-05	2.711	.627	1.653	37.133	21.559	11.93	.000	21.559	110.886	93.561
12-06	2.371	.508	1.521	35.224	16.676	12.80	.000	16.676	127.562	104.448
12-07	2.161	.465	1.420	35.224	12.530	13.80	.000	12.530	140.092	111.887
12-08	1.985	.429	1.327	35.224	8.962	14.80	.000	8.962	149.054	116.726
12-09	1.834	.398	1.243	35.224	5.832	15.83	.000	5.832	154.886	119.592
12-10	1.703	.370	1.165	35.224	3.041	16.88	.000	3.041	157.927	120.954
12-11	1.070	.233	.736	23.492	.609	17.79	.000	.609	158.536	121.207
12-12	.004	.001	.001	.055	.008	15.65	.000	.008	158.544	121.210
12-13
S TOT	23.249	5.275	14.725	350.808	158.544	15.65	.000	158.544	158.544	121.210
AFTER	.000	.000	.000	.000	.000	15.65	.000	.000	158.544	121.210
TOTAL	23.249	5.275	14.725	350.808	158.544	15.65	.000	158.544	158.544	121.210

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	4.0	.0	LIFE, YRS.	10.58	8.00	127.257
GROSS ULT., MB & MMF	567.577	970.843	DISCOUNT %	10.00	10.00	121.210
GROSS CUM., MB & MMF	261.929	474.222	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	115.703
GROSS RES., MB & MMF	305.648	496.621	DISCOUNTED PAYOUT, YRS.	.00	15.00	108.317
NET RES., MB & MMF	25.452	30.572	UNDISCOUNTED NET/INVEST.	.00	20.00	97.926
NET REVENUE, M$	482.980	69.622	DISCOUNTED NET/INVEST.	.00	25.00	89.411
INITIAL PRICE, $	19.147	2.012	RATE-OF-RETURN, PCT.	100.00	35.00	76.369
INITIAL N.I., PCT.	5.369	4.199	INITIAL W.I., PCT.	6.562	50.00	63.114
					70.00	51.897
					100.00	41.833

SW DEV DRILLING FUND 1991-A	DATE	:	02/17/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	17:58:48
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR91A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.0	10.130	28.176	.000	3.332	4.305	.000	18.94	2.24	63.120	9.662	72.782
12-03	2.0	8.448	25.355	.000	3.088	4.001	.000	18.95	2.25	58.514	8.997	67.511
12-04	2.0	7.129	22.826	.000	2.870	3.721	.000	18.95	2.25	54.382	8.382	62.764
12-05	1.7	5.315	15.192	.000	2.640	3.241	.000	18.96	2.28	50.062	7.397	57.459
12-06	1.0	3.329	3.598	.000	2.414	2.609	.000	18.97	2.35	45.785	6.130	51.916
12-07	1.0	3.130	3.384	.000	2.269	2.453	.000	18.97	2.35	43.038	5.764	48.803
12-08	1.0	2.942	3.182	.000	2.133	2.307	.000	18.97	2.35	40.456	5.420	45.876
12-09	1.0	2.765	2.992	.000	2.005	2.169	.000	18.97	2.35	38.028	5.097	43.125
12-10	1.0	2.599	2.813	.000	1.884	2.039	.000	18.97	2.35	35.747	4.792	40.539
12-11	1.0	1.646	1.781	.000	1.193	1.291	.000	18.97	2.35	22.632	3.035	25.666
12-12
12-13
S TOT	1.0	47.433	109.299	.000	23.827	28.136	.000	18.96	2.30	451.764	64.677	516.440
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	47.433	109.299	.000	23.827	28.136	.000	18.96	2.30	451.764	64.677	516.440

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.011	.734	1.954	37.726	29.357	10.72	.000	29.357	29.357	28.040
12-03	2.773	.683	1.829	37.726	24.500	11.45	.000	24.500	53.857	49.316
12-04	2.563	.636	1.713	37.726	20.127	12.22	.000	20.127	73.984	65.207
12-05	2.335	.559	1.596	36.771	16.197	12.97	.000	16.197	90.181	76.835
12-06	2.106	.460	1.480	34.862	13.008	13.66	.000	13.008	103.189	85.324
12-07	1.980	.432	1.392	34.862	10.137	14.44	.000	10.137	113.326	91.341
12-08	1.861	.407	1.308	34.862	7.439	15.27	.000	7.439	120.765	95.357
12-09	1.749	.382	1.230	34.862	4.902	16.15	.000	4.902	125.667	97.766
12-10	1.644	.359	1.156	34.862	2.518	17.09	.000	2.518	128.185	98.895
12-11	1.041	.228	.732	23.241	.425	17.92	.000	.425	128.610	99.071
12-12
12-13
S TOT	21.064	4.880	14.390	347.497	128.610	17.92	.000	128.610	128.610	99.071
AFTER	.000	.000	.000	.000	.000	17.92	.000	.000	128.610	99.071
TOTAL	21.064	4.880	14.390	347.497	128.610	17.92	.000	128.610	128.610	99.071

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	9.67	8.00	103.848
GROSS ULT., MB & MMF	309.362	547.041	DISCOUNT %	10.00	10.00	99.071
GROSS CUM., MB & MMF	261.929	437.742	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	94.723
GROSS RES., MB & MMF	47.433	109.299	DISCOUNTED PAYOUT, YRS.	.00	15.00	88.895
NET RES., MB & MMF	23.827	28.136	UNDISCOUNTED NET/INVEST.	.00	20.00	80.702
NET REVENUE, M$	451.764	64.677	DISCOUNTED NET/INVEST.	.00	25.00	73.993
INITIAL PRICE, $	18.741	1.955	RATE-OF-RETURN, PCT.	100.00	35.00	63.722
INITIAL N.I., PCT.	31.305	15.058	INITIAL W.I., PCT.	35.441	50.00	53.277
					70.00	44.414
					100.00	36.413

SW DEV DRILLING FUND 1991-A	DATE	:	02/17/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	17:58:49
PNP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR91A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.5	18.240	27.360	.000	.094	.140	.000	19.22	2.03	1.799	.285	2.085
12-03	1.8	52.846	79.269	.000	.355	.533	.000	19.22	2.03	6.828	1.082	7.910
12-04	2.0	51.499	77.249	.000	.341	.512	.000	19.22	2.03	6.562	1.040	7.602
12-05	2.0	44.709	67.063	.000	.280	.419	.000	19.22	2.03	5.374	.851	6.225
12-06	2.0	32.017	48.026	.000	.197	.295	.000	19.22	2.03	3.785	.600	4.384
12-07	2.0	22.095	33.142	.000	.135	.202	.000	19.22	2.03	2.587	.410	2.996
12-08	2.0	15.260	22.890	.000	.092	.138	.000	19.22	2.03	1.770	.280	2.050
12-09	2.0	10.548	15.822	.000	.063	.095	.000	19.22	2.03	1.213	.192	1.405
12-10	2.0	7.296	10.945	.000	.043	.065	.000	19.22	2.03	.832	.132	.963
12-11	1.6	3.400	5.101	.000	.021	.032	.000	19.22	2.03	.408	.065	.473
12-12	1.0	.304	.456	.000	.003	.005	.000	19.22	2.03	.060	.009	.069
12-13
S TOT	1.0	258.215	387.322	.000	1.624	2.436	.000	19.22	2.03	31.217	4.946	36.162
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	258.215	387.322	.000	1.624	2.436	.000	19.22	2.03	31.217	4.946	36.162

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.126	.023	.019	.133	1.783	2.58	.000	1.783	1.783	1.660
12-03	.478	.087	.073	.338	6.934	2.20	.000	6.934	8.717	7.643
12-04	.459	.083	.071	.362	6.627	2.28	.000	6.627	15.343	12.875
12-05	.376	.068	.058	.362	5.361	2.47	.000	5.361	20.705	16.726
12-06	.265	.048	.041	.362	3.669	2.91	.000	3.669	24.373	19.123
12-07	.181	.033	.028	.362	2.393	3.59	.000	2.393	26.766	20.546
12-08	.124	.022	.019	.362	1.523	4.58	.000	1.523	28.289	21.369
12-09	.085	.015	.013	.362	.929	6.03	.000	.929	29.219	21.825
12-10	.058	.011	.009	.362	.524	8.13	.000	.524	29.742	22.060
12-11	.029	.005	.004	.251	.184	10.88	.000	.184	29.926	22.135
12-12	.004	.001	.001	.055	.008	15.65	.000	.008	29.935	22.139
12-13
S TOT	2.185	.396	.336	3.311	29.935	15.65	.000	29.935	29.935	22.139
AFTER	.000	.000	.000	.000	.000	15.65	.000	.000	29.935	22.139
TOTAL	2.185	.396	.336	3.311	29.935	15.65	.000	29.935	29.935	22.139

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	10.58	8.00	23.408
GROSS ULT., MB & MMF	258.215	423.802	DISCOUNT %	10.00	10.00	22.139
GROSS CUM., MB & MMF	.000	36.480	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	20.980
GROSS RES., MB & MMF	258.215	387.322	DISCOUNTED PAYOUT, YRS.	.00	15.00	19.422
NET RES., MB & MMF	1.624	2.436	UNDISCOUNTED NET/INVEST.	.00	20.00	17.224
NET REVENUE, M$	31.217	4.946	DISCOUNTED NET/INVEST.	.00	25.00	15.418
INITIAL PRICE, $	19.220	2.030	RATE-OF-RETURN, PCT.	100.00	35.00	12.647
INITIAL N.I., PCT.	.722	.722	INITIAL W.I., PCT.	.990	50.00	9.837
					70.00	7.483
					100.00	5.420

APPENDIX B19

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Development Drilling Fund 1992-A (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 5 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 97.7 percent of the total net remaining liquid hydrocarbon reserves and 89.8 percent of the total net remaining gas reserves. The properties that we reviewed represent 96.8 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002 they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Development Drilling Fund 1992-A

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		76,908		0		0		77,908
Gas—MMCF		219		0		0		219
Income Data
Future Gross Revenue	$	1,855,503	$	0	$	0	$	1,855,503
Deductions		1,147,696		0		0		1,147,696
Future Net Income (FNI)	$	707,807	$	0	$	0	$	707,807
Discounted FNI @ 10%	$	450,345	$	0	$	0	$	450,345

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		1,827		0		0		1,827
Gas—MMCF		25		0		0		25
Income Data
Future Gross Revenue	$	85,311	$	0	$	0	$	85,311
Deductions		67,005		0		0		67,005
Future Net Income (FNI)	$	18,306	$	0	$	0	$	18,306
Discounted FNI @10%	$	15,109	$	0	$	0	$	15,109
Total Net Reserves
Oil/Condensate—Barrels		78,735		0		0		78,735
Gas—MMCF		244		0		0		244
Income Data
Future Gross Revenue	$	1,940,814	$	0	$	0	$	1,940,814
Deductions		1,214,701		0		0		1,214,701
Future Net Income (FNI)	$	726,113	$	0	$	0	$	726,113
Discounted FNI @10%	$	465,454	$	0	$	0	$	465,454

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii)  Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)  Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 2.3 percent of the total net remaining liquid hydrocarbon reserves and 10.2 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,
RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW DEV DRILLING FUND 1992-A	DATE	:	02/17/02
ALL PROPERTIES	TIME	:	17:46:41
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR92A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	7.7	22.965	42.504	.000	8.708	21.764	.000	18.88	2.33	164.397	50.794	215.190
12-03	6.1	18.102	34.371	.000	8.014	20.443	.000	18.88	2.33	151.349	47.636	198.984
12-04	6.0	16.735	32.249	.000	7.517	19.453	.000	18.89	2.33	141.964	45.334	187.298
12-05	5.5	14.509	29.358	.000	7.006	18.474	.000	18.89	2.33	132.323	43.043	175.366
12-06	5.0	12.466	26.685	.000	6.528	17.549	.000	18.89	2.33	123.308	40.879	164.188
12-07	5.0	11.655	25.293	.000	6.130	16.726	.000	18.89	2.33	115.806	38.969	154.775
12-08	4.8	10.833	22.983	.000	5.711	15.225	.000	18.90	2.33	107.917	35.502	143.418
12-09	3.3	8.445	17.454	.000	4.012	11.256	.000	18.88	2.34	75.761	26.322	102.083
12-10	2.1	5.127	13.855	.000	3.083	10.139	.000	18.87	2.34	58.173	23.689	81.863
12-11	2.0	4.639	13.113	.000	2.889	9.751	.000	18.87	2.34	54.529	22.783	77.312
12-12	2.0	4.361	12.591	.000	2.716	9.386	.000	18.87	2.34	51.261	21.937	73.198
12-13	2.0	4.100	12.092	.000	2.553	9.036	.000	18.87	2.34	48.189	21.123	69.312
S TOT	1.0	133.936	282.548	.000	64.868	179.202	.000	18.88	2.33	1224.978	418.010	1642.988
AFTER	1.0	18.728	83.052	.000	13.867	65.479	.000	18.95	2.35	262.778	153.707	416.485
TOTAL	1.0	152.665	365.600	.000	78.735	244.682	.000	18.90	2.34	1487.756	571.717	2059.473

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	8.486	3.884	5.096	95.475	102.251	9.16	.000	102.251	102.251	97.621
12-03	7.756	3.638	4.771	92.118	90.701	9.48	.000	90.701	192.952	176.343
12-04	7.269	3.461	4.501	91.941	80.126	9.96	.000	80.126	273.078	239.569
12-05	6.754	3.284	4.237	90.881	70.210	10.43	.000	70.210	343.289	289.937
12-06	6.274	3.117	3.989	89.821	60.987	10.92	.000	60.987	404.276	329.715
12-07	5.890	2.970	3.765	89.821	52.329	11.49	.000	52.329	456.604	360.745
12-08	5.471	2.699	3.532	87.508	44.209	12.03	.000	44.209	500.813	384.581
12-09	3.901	1.984	2.528	56.170	37.500	10.97	.000	37.500	538.313	402.956
12-10	3.023	1.784	2.014	42.027	33.014	10.24	.000	33.014	571.327	417.660
12-11	2.831	1.716	1.907	41.850	29.008	10.70	.000	29.008	600.336	429.407
12-12	2.661	1.652	1.807	41.850	25.227	11.21	.000	25.227	625.563	438.694
12-13	2.502	1.590	1.713	41.850	21.657	11.74	.000	21.657	647.220	445.944
S TOT	62.817	31.780	39.860	861.311	647.220	16.60	.000	647.220	647.220	445.944
AFTER	12.526	11.537	11.399	302.129	78.894	16.60	.000	78.894	726.113	465.454
TOTAL	75.343	43.317	51.260	1163.440	726.113	16.60	.000	726.113	726.113	465.454

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	9.0	.0	LIFE, YRS.	21.08	8.00	501.494
GROSS ULT., MB & MMF	543.651	962.105	DISCOUNT %	10.00	10.00	465.454
GROSS CUM., MB & MMF	390.986	596.505	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	434.420
GROSS RES., MB & MMF	152.665	365.600	DISCOUNTED PAYOUT, YRS.	.00	15.00	395.289
NET RES., MB & MMF	78.735	244.682	UNDISCOUNTED NET/INVEST.	.00	20.00	344.613
NET REVENUE, M$	1487.756	571.717	DISCOUNTED NET/INVEST.	.00	25.00	306.486
INITIAL PRICE, $	18.719	2.446	RATE-OF-RETURN, PCT.	100.00	35.00	253.141
INITIAL N.I., PCT.	34.342	45.294	INITIAL W.I., PCT.	46.010	50.00	204.060
					70.00	165.641
					100.00	132.960

SW DEV DRILLING FUND 1992-A	DATE	:	02/17/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	17:58:49
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR92A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	T0TAL NET SALES M$
12-02	5.0	18.793	29.816	.000	8.232	16.934	.000	18.90	2.34	155.596	39.582	195.178
12-03	5.0	17.530	28.246	.000	7.728	16.211	.000	18.90	2.34	146.072	37.897	183.969
12-04	5.0	16.378	26.790	.000	7.260	15.523	.000	18.90	2.34	137.228	36.294	173.521
12-05	4.5	14.178	24.274	.000	6.767	14.813	.000	18.91	2.34	127.938	34.623	162.561
12-06	4.0	12.159	21.949	.000	6.307	14.139	.000	18.91	2.34	119.247	33.037	152.284
12-07	4.0	11.371	20.882	.000	5.926	13.549	.000	18.91	2.34	112.046	31.664	143.710
12-08	4.0	10.634	19.874	.000	5.568	12.987	.000	18.91	2.34	105.281	30.353	135.634
12-09	3.3	8.445	17.454	.000	4.012	11.256	.000	18.88	2.34	75.761	26.322	102.083
12-10	2.1	5.127	13.855	.000	3.083	10.139	.000	18.87	2.34	58.173	23.689	81.863
12-11	2.0	4.639	13.113	.000	2.889	9.751	.000	18.87	2.34	54.529	22.783	77.312
12-12	2.0	4.361	12.591	.000	2.716	9.386	.000	18.87	2.34	51.261	21.937	73.198
12-13	2.0	4.100	12.092	.000	2.553	9.036	.000	18.87	2.34	48.189	21.123	69.312
S TOT	1.0	127.715	240.936	.000	63.041	153.724	.000	18.90	2.34	1191.320	359.305	1550.625
AFTER	1.0	18.728	83.052	.000	13.867	65.479	.000	18.95	2.35	262.778	153.707	416.485
TOTAL	1.0	146.443	323.988	.000	76.908	219.204	.000	18.91	2.34	1454.099	513.011	1967.110

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	7.870	2.987	4.911	82.691	96.721	8.91	.000	96.721	96.721	92.335
12-03	7.386	2.859	4.633	82.691	86.400	9.36	.000	86.400	183.121	167.322
12-04	6.937	2.738	4.373	82.691	76.782	9.82	.000	76.782	259.904	227.906
12-05	6.447	2.611	4.119	81.630	67.754	10.26	.000	67.754	327.658	276.509
12-06	5.989	2.490	3.879	80.570	59.356	10.73	.000	59.356	387.013	315.219
12-07	5.627	2.386	3.663	80.570	51.464	11.27	.000	51.464	438.477	345.734
12-08	5.286	2.287	3.460	80.570	44.031	11.85	.000	44.031	482.508	369.471
12-09	3.901	1.984	2.528	56.170	37.500	10.97	.000	37.500	520.008	387.846
12-10	3.023	1.784	2.014	42.027	33.014	10.24	.000	33.014	553.022	402.551
12-11	2.831	1.716	1.907	41.850	29.008	10.70	.000	29.008	582.030	414.297
12-12	2.661	1.652	1.807	41.850	25.227	11.21	.000	25.227	607.257	423.585
12-13	2.502	1.590	1.713	41.850	21.657	11.74	.000	21.657	628.914	430.834
S TOT	60.461	27.083	39.007	795.160	628.914	16.60	.000	628.914	628.914	430.834
AFTER	12.526	11.537	11.399	302.129	78.894	16.60	.000	78.894	707.808	450.345
TOTAL	72.987	38.620	50.407	1097.289	707.808	16.60	.000	707.808	707.808	450.345

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	5.0	.0	LIFE, YRS.	21.08	8.00	485.841
GROSS ULT., MB & MMF	417.844	727.316	DISCOUNT %	10.00	10.00	450.345
GROSS CUM., MB & MMF	271.401	403.328	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	419.815
GROSS RES., MB & MMF	146.443	323.988	DISCOUNTED PAYOUT, YRS.	.00	15.00	381.377
NET RES., MB & MMF	76.908	219.204	UNDISCOUNTED NET/INVEST.	.00	20.00	331.709
NET REVENUE, M$	1454.099	513.011	DISCOUNTED NET/INVEST.	.00	25.00	294.439
INITIAL PRICE, $	18.763	2.397	RATE-OF-RETURN, PCT.	100.00	35.00	242.472
INITIAL N.I., PCT.	43.667	56.509	INITIAL W.I., PCT.	57.697	50.00	194.881
					70.00	157.805
					100.00	126.403

SW DEV DRILLING FUND 1992-A	DATE	:	02/17/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	18:13:42
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR92A

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.7	4.172	12.688	.000	.476	4.830	.000	18.48	2.32	8.800	11.211	20.012
12-03	1.1	.571	6.125	.000	.287	4.232	.000	18.41	2.30	5.277	9.738	15.015
12-04	1.0	.358	5.459	.000	.257	3.930	.000	18.40	2.30	4.737	9.040	13.777
12-05	1.0	.331	5.085	.000	.238	3.661	.000	18.40	2.30	4.386	8.420	12.806
12-06	1.0	.307	4.736	.000	.221	3.410	.000	18.40	2.30	4.061	7.843	11.904
12-07	1.0	.284	4.411	.000	.204	3.176	.000	18.40	2.30	3.760	7.305	11.065
12-08	1.0	.199	3.109	.000	.143	2.238	.000	18.40	2.30	2.636	5.148	7.784
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	6.222	41.612	.000	1.827	25.478	.000	18.42	2.30	33.657	58.706	92.363
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	6.222	41.612	.000	1.827	25.478	.000	18.42	2.30	33.657	58.706	92.363

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL  TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.616	.897	.185	12.784	5.530	11.30	.000	5.530	5.530	5.285
12-03	.369	.779	.139	9.427	4.301	10.80	.000	4.301	9.830	9.021
12-04	.332	.723	.127	9.251	3.344	11.43	.000	3.344	13.174	11.663
12-05	.307	.674	.118	9.251	2.456	12.20	.000	2.456	15.631	13.428
12-06	.284	.627	.110	9.251	1.632	13.02	.000	1.632	17.262	14.495
12-07	.263	.584	.102	9.251	.865	13.90	.000	.865	18.127	15.011
12-08	.185	.412	.072	6.938	.178	14.73	.000	.178	18.305	15.109
12-09
12-10
12-11
12-12
12-13
S TOT	2.356	4.696	.853	66.152	18.305	14.73	.000	18.305	18.305	15.109
AFTER	.000	.000	.000	.000	.000	14.73	.000	.000	18.305	15.109
TOTAL	2.356	4.696	.853	66.152	18.305	14.73	.000	18.305	18.305	15.109

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	4.0	.0	LIFE, YRS.	6.75	8.00	15.653
GROSS ULT., MB & MMF	125.807	234.789	DISCOUNT %	10.00	10.00	15.109
GROSS CUM., MB & MMF	119.585	193.177	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	14.605
GROSS RES., MB & MMF	6.222	41.612	DISCOUNTED PAYOUT, YRS.	.00	15.00	13.912
NET RES., MB & MMF	1.827	25.478	UNDISCOUNTED NET/INVEST.	.00	20.00	12.904
NET REVENUE, M$	33.657	58.706	DISCOUNTED NET/INVEST.	.00	25.00	12.046
INITIAL PRICE, $	18.597	2.525	RATE-OF-RETURN, PCT .	100.00	35.00	10.669
INITIAL N.I ., PCT.	8.791	27.453	INITIAL W.I., PCT.	17.649	50.00	9.180
					70.00	7.836
					100.00	6.557

APPENDIX B20

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Development Drilling Fund 1993 (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 7 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 100 percent of the total net remaining liquid hydrocarbon reserves and 100 percent of the total net remaining gas reserves. The properties that we reviewed represent 100 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Development Drilling Fund 1993

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		107,688		8,955		16,129		132,772
Gas—MMCF		244		6		26		276
Income Data
Future Gross Revenue	$	2,363,198	$	159,498	$	332,092	$	2,854,788
Deductions		1,268,769		29,095		82,307		1,380,171
Future Net Income (FNI)	$	1,094,429	$	130,403	$	249,785	$	1,474,617
Discounted FNI @ 10%	$	710,789	$	83,193	$	149,765	$	943,747

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed
	Producing		Non-Producing		Undeveloped		Total Proved
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		0		0		0		0
Gas—MMCF		0		0		0		0
Income Data
Future Gross Revenue	$	0	$	0	$	0	$	0
Deductions		0		0		0		0
Future Net Income (FNI)	$	0	$	0	$	0	$	0
Discounted FNI @ 10%	$	0	$	0	$	0	$	0
Total Net Reserves
Oil/Condensate—Barrels		107,688		8,955		16,129		132,772
Gas—MMCF		244		6		26		276
Income Data
Future Gross Revenue	$	2,363,198	$	159,498	$	332,092	$	2,854,788
Deductions		1,268,769		29,095		82,307		1,380,171
Future Net Income (FNI)	$	1,094,429	$	130,403	$	249,785	$	1,474,617
Discounted FNI @ 10%	$	710,789	$	83,193	$	149,765	$	943,747

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? . . . The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our

estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours, RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW DEV DRILLING FUND 1993	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:17
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****
RESERVES AND ECONOMICS QUALIFIER:  RSC0102  DR93

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	4.3	21.332	52.857	.000	12.888	23.829	.000	17.67	2.45	227.670	58.478	286.148
12-03	5.0	30.218	63.200	.000	13.498	23.849	.000	17.63	2.49	237.991	59.484	297.475
12-04	5.6	37.175	72.016	.000	13.790	23.702	.000	17.61	2.53	242.809	59.904	302.713
12-05	6.0	34.803	68.545	.000	12.689	22.187	.000	17.62	2.53	223.558	56.079	279.637
12-06	6.0	29.681	59.466	.000	11.417	20.252	.000	17.64	2.51	201.356	50.915	252.271
12-07	6.0	26.308	53.423	.000	10.405	18.692	.000	17.65	2.51	183.666	46.839	230.505
12-08	6.0	23.809	48.959	.000	9.542	17.353	.000	17.66	2.50	168.539	43.388	211.927
12-09	5.5	21.181	40.358	.000	8.711	15.679	.000	17.68	2.51	154.016	39.339	193.355
12-10	4.3	17.576	31.095	.000	6.888	13.074	.000	17.80	2.50	122.600	32.704	155.303
12-11	4.0	15.409	27.879	.000	5.832	11.677	.000	17.88	2.49	104.269	29.038	133.307
12-12	4.0	13.194	25.020	.000	5.192	10.783	.000	17.91	2.48	93.016	26.708	119.724
12-13	3.5	9.467	21.314	.000	3.587	9.407	.000	18.20	2.45	65.296	23.021	88.317
S TOT	1.0	280.153	564.131	.000	114.440	210.485	.000	17.69	2.50	2024.786	525.897	2550.683
AFTER	1.0	45.381	123.491	.000	18.333	64.777	.000	18.73	2.40	343.455	155.491	498.946
TOTAL	1.0	325.533	687.622	.000	132.773	275.262	.000	17.84	2.48	2368.241	681.388	3049.629

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	14.094	4.497	4.809	90.465	172.282	6.75	.000	172.282	172.282	164.147
12-03	14.927	4.589	4.786	93.495	179.678	6.74	.000	179.678	351.960	319.850
12-04	15.369	4.632	4.714	96.334	181.665	6.82	.000	181.665	533.624	462.971
12-05	14.119	4.336	4.386	97.290	159.507	7.33	.000	159.507	693.131	577.446
12-06	12.656	3.931	4.025	97.290	134.368	7.97	.000	134.368	827.499	665.095
12-07	11.504	3.614	3.723	97.290	114.375	8.59	.000	114.375	941.873	732.919
12-08	10.527	3.345	3.456	97.290	97.309	9.22	.000	97.309	1039.183	785.379
12-09	9.586	3.029	3.195	95.532	82.013	9.83	.000	82.013	1121.196	825.578
12-10	7.459	2.505	2.758	73.862	68.719	9.55	.000	68.719	1189.915	856.195
12-11	6.243	2.218	2.475	63.906	58.465	9.62	.000	58.465	1248.380	879.875
12-12	5.519	2.038	2.275	62.906	46.986	10.41	.000	46.986	1295.366	897.205
12-13	3.638	1.749	1.914	45.972	35.044	10.33	.000	35.044	1330.410	908.936
S TOT	125.642	40.484	42.516	1011.632	1330.410	16.74	.000	1330.410	1330.410	908.936
AFTER	16.981	11.733	12.929	313.095	144.208	16.74	.000	144.208	1474.618	943.747
TOTAL	142.623	52.217	55.445	1324.726	1474.618	16.74	.000	1474.618	1474.618	943.747

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	6.0	.0	LIFE, YRS.	22.67	8.00	1017.957
GROSS ULT., MB & MMF	527.946	1079.324	DISCOUNT %	10.00	10.00	943.747
GROSS CUM., MB & MMF	202.413	391.702	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	879.565
GROSS RES., MB & MMF	325.533	687.622	DISCOUNTED PAYOUT, YRS.	.00	15.00	798.241
NET RES., MB & MMF	132.773	275.262	UNDISCOUNTED NET/INVEST.	.00	20.00	692.225
NET REVENUE, M$	2368.241	681.388	DISCOUNTED NET/INVEST.	.00	25.00	611.942
INITIAL PRICE, $	17.389	2.756	RATE-OF-RETURN, PCT.	100.00	35.00	499.000
INITIAL N.I., PCT.	30.582	27.058	INITIAL W.I., PCT.	35.190	50.00	394.845
					70.00	313.722
					100.00	245.610

SW DEV DRILLING FUND 1993	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:17
PDP RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****
RESERVES AND ECONOMICS QUALIFIER:  RSC0102  DR93

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	4.0	15.993	43.244	.000	12.303	22.902	.000	17.68	2.43	217.567	55.650	273.218
12-03	4.0	14.730	39.902	.000	11.343	21.318	.000	17.70	2.43	200.735	51.766	252.501
12-04	4.0	13.585	36.980	.000	10.462	19.863	.000	17.71	2.43	185.271	48.195	233.466
12-05	4.0	12.544	34.389	.000	9.652	18.522	.000	17.72	2.42	171.053	44.902	215.955
12-06	4.0	11.593	32.069	.000	8.908	17.283	.000	17.73	2.42	157.974	41.860	199.833
12-07	4.0	10.723	29.974	.000	8.223	16.137	.000	17.75	2.42	145.936	39.045	184.981
12-08	4.0	9.925	28.071	.000	7.593	15.074	.000	17.76	2.42	134.853	36.437	171.290
12-09	3.5	8.686	21.521	.000	6.958	13.624	.000	17.78	2.43	123.698	33.072	156.770
12-10	2.3	6.331	14.107	.000	5.310	11.221	.000	17.95	2.41	95.314	27.053	122.367
12-11	2.0	5.288	12.559	.000	4.412	10.007	.000	18.07	2.39	79.712	23.943	103.655
12-12	2.0	4.912	11.782	.000	4.095	9.389	.000	18.08	2.39	74.044	22.455	96.499
12-13	1.5	3.582	10.473	.000	2.943	8.361	.000	18.40	2.37	54.161	19.832	73.993
S TOT	1.0	117.891	315.072	.000	92.203	183.702	.000	17.79	2.42	1640.318	444.210	2084.528
AFTER	1.0	19.356	75.143	.000	15.485	60.115	.000	19.00	2.35	294.207	141.269	235.476
TOTAL	1.0	137.247	390.215	.000	107.688	243.816	.000	17.96	2.40	1934.525	585.479	2520.004

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	13.387	4.271	4.689	89.700	161.170	6.95	.000	161.170	161.170	153.877
12-03	12.320	3.971	4.369	89.700	142.142	7.41	.000	142.142	303.312	277.254
12-04	11.341	3.695	4.071	89.700	124.658	7.90	.000	124.658	427.970	375.624
12-05	10.443	3.441	3.795	89.700	108.575	8.43	.000	108.575	536.545	453.518
12-06	9.620	3.207	3.538	89.700	93.768	9.00	.000	93.768	630.313	514.678
12-07	8.863	2.990	3.300	89.700	80.127	9.61	.000	80.127	710.441	562.195
12-08	8.169	2.789	3.079	89.700	67.553	10.27	.000	67.553	777.994	598.617
12-09	7.464	2.528	2.855	87.942	55.981	10.92	.000	55.981	833.975	626.061
12-10	5.549	2.053	2.452	66.272	46.041	10.63	.000	46.041	880.016	646.575
12-11	4.524	1.811	2.200	56.316	38.805	10.67	.000	38.805	918.821	662.294
12-12	4.191	1.698	2.060	56.316	32.235	11.35	.000	32.235	951.055	674.167
12-13	2.858	1.494	1.781	41.382	26.478	10.96	.000	26.478	977.533	683.030
S TOT	98.729	33.949	38.189	936.128	977.533	16.74	.000	977.533	977.533	683.030
AFTER	13.534	10.595	12.340	282.112	116.895	16.74	.000	116.895	1094.429	710.789
TOTAL	112.262	44.544	50.529	1218.240	1094.429	16.74	.000	1094.429	1094.429	710.789

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	4.0	.0	LIFE, YRS.	22.67	8.00	763.924
GROSSULT., MB & MMF	339.660	747.873	DISCOUNT %	10.00	10.00	710.789
GROSS CUM., MB & MMF	202.413	357.658	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	664.939
GROSS RES., MB &MMF	137.247	390.215	DISCOUNTED PAYOUT, YRS.	.00	15.00	606.954
NET RES., MB &MMF	107.688	243.816	UNDISCOUNTED NET/INVEST.	.00	20.00	531.474
NET REVENUE, M$	1934.525	585.479	DISCOUNTED NET/INVEST.	.00	25.00	474.304
INITIAL PRICE, $	17.653	2.302	RATE-OF-RETURN, PCT.	100.00	35.00	393.634
INITIAL N.I., PCT.	76.868	52.689	INITIAL W.I., PCT.	85.512	50.00	318.611
					70.00	259.348
					100.00	208.610

SW DEV DRILLING FUND 1993	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:17
PNP RESERVES	DBS FILE	:	SWR01020
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR93

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.0	4.200	2.940	.000	.919	.567	.000	17.29	3.05	15.894	1.730	17.624
12-04	.0	6.816	4.771	.000	1.492	.920	.000	17.29	3.05	25.798	2.807	28.605
12-05	.0	5.487	3.841	.000	1.201	.741	.000	17.29	3.05	20.767	2.260	23.026
12-06	.0	4.837	3.386	.000	1.059	.653	.000	17.29	3.05	18.307	1.992	20.299
12-07	.0	4.353	3.047	.000	.953	.588	.000	17.29	3.05	16.476	1.793	18.269
12-08	.0	3.918	2.743	.000	.858	.529	.000	17.29	3.05	14.829	1.614	16.442
12-09	.0	3.526	2.468	.000	.772	.476	.000	17.29	3.05	13.346	1.452	14.798
12-10	.0	3.174	2.222	.000	.695	.429	.000	17.29	3.05	12.011	1.307	13.318
12-11	.0	2.856	1.999	.000	.625	.386	.000	17.29	3.05	10.810	1.176	11.986
12-12	.0	1.744	1.221	.000	.382	.235	.000	17.29	3.05	6.599	.718	7.317
12-13
S TOT	.0	40.912	28.638	.000	8.955	5.524	.000	17.29	3.05	154.837	16.848	171.685
AFTER	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	.0	40.912	28.638	.000	8.955	5.524	.000	17.29	3.05	154.837	16.848	171.685

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	1.113	.138	.164	1.500	14.709	2.88	.000	14.709	14.709	12.459
12-04	1.806	.225	.266	3.000	23.309	3.22	.000	23.309	38.017	30.874
12-05	1.454	.181	.214	3.000	18.178	3.66	.000	18.178	56.196	43.921
12-06	1.281	.159	.189	3.000	15.670	3.96	.000	15.670	71.865	54.140
12-07	1.153	.143	.170	3.000	13.803	4.25	.000	13.803	85.668	62.323
12-08	1.038	.129	.153	3.000	12.122	4.57	.000	12.122	97.790	68.856
12-09	.934	.116	.137	3.000	10.610	4.92	.000	10.610	108.401	74.055
12-10	.841	.105	.124	3.000	9.249	5.31	.000	9.249	117.650	78.175
12-11	.757	.094	.111	3.000	8.024	5.75	.000	8.024	125.674	81.425
12-12	.462	.057	.068	2.000	4.730	6.15	.000	4.730	130.404	83.193
12-13
S TOT	10.839	1.348	1.595	27.500	130.404	6.15	.000	130.404	130.404	83.193
AFTER	.000	.000	.000	.000	.000	6.15	.000	.000	130.404	83.193
TOTAL	10.839	1.348	1.595	27.500	130.404	6.15	.000	130.404	130.404	83.193

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	.0	.0	LIFE, YRS.	10.67	8.00	90.322
GROSS ULT., MB & MMF	40.912	28.638	DISCOUNT %	10.00	10.00	83.193
GROSS CUM., MB & MMF	.000	.000	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	76.883
GROSS RES., MB & MMF	40.912	28.638	DISCOUNTED PAYOUT, YRS.	.00	15.00	68.705
NET RES., MB & MMF	8.955	5.524	UNDISCOUNTED NET/INVEST.	.00	20.00	57.762
NET REVENUE, M$	154.837	16.848	DISCOUNTED NET/INVEST.	.00	25.00	49.306
INITIAL PRICE, $	17.290	3.050	RATE-OF-RETURN, PCT.	100.00	35.00	37.292
INITIAL N.I., PCT.	21.889	19.289	INITIAL W.I., PCT.	25.000	50.00	26.313
					70.00	18.075
					100.00	11.609

SW DEV DRILLING FUND 1993	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:17
PUD RESERVES	DBS FILE	:	SWR0102
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR93

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.3	5.339	9.613	.000	.584	.927	.000	17.29	3.05	10.103	2.828	12.930
12-03	1.0	11.289	20.358	.000	1.235	1.963	.000	17.29	3.05	21.362	5.988	27.350
12-04	1.6	16.773	30.265	.000	1.836	2.919	.000	17.29	3.05	31.740	8.903	40.643
12-05	2.0	16.772	30.315	.000	1.836	2.924	.000	17.29	3.05	31.738	8.917	40.656
12-06	2.0	13.251	24.011	.000	1.450	2.316	.000	17.29	3.05	25.075	7.063	32.138
12-07	2.0	11.232	20.402	.000	1.229	1.968	.000	17.29	3.05	21.254	6.001	27.255
12-08	2.0	9.965	18.145	.000	1.091	1.750	.000	17.29	3.05	18.858	5.337	24.195
12-09	2.0	8.969	16.369	.000	.982	1.579	.000	17.29	3.05	16.972	4.815	21.787
12-10	2.0	8.072	14.766	.000	.883	1.424	.000	17.29	3.05	15.275	4.344	19.618
12-11	2.0	7.265	13.321	.000	.795	1.285	.000	17.29	3.05	13.747	3.918	17.666
12-12	2.0	6.538	12.017	.000	.716	1.159	.000	17.29	3.05	12.372	3.535	15.907
12-13	2.0	5.884	10.840	.000	.644	1.045	.000	17.29	3.05	11.135	3.189	14.324
S TOT	1.0	121.350	220.421	.000	13.281	21.259	.000	17.29	3.05	229.631	64.839	294.470
AFTER	1.0	26.025	48.348	.000	2.848	4.663	.000	17.29	3.05	49.248	14.222	63.469
TOTAL	1.0	147.375	268.769	.000	16.129	25.922	.000	17.29	3.05	278.879	79.061	357.939

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.707	.226	.120	.765	11.112	2.46	.000	11.112	11.112	10.271
12-03	1.495	.479	.254	2.295	22.827	2.89	.000	22.827	33.939	30.137
12-04	2.222	.712	.377	3.634	33.698	2.99	.000	33.698	67.637	56.474
12-05	2.222	.713	.377	4.590	32.754	3.40	.000	32.754	100.391	80.007
12-06	1.755	.565	.298	4.590	24.930	3.93	.000	24.930	125.320	96.277
12-07	1.488	.480	.253	4.590	20.445	4.37	.000	20.445	145.765	108.402
12-08	1.320	.427	.224	4.590	17.633	4.75	.000	17.633	163.398	117.906
12-09	1.188	.385	.202	4.590	15.421	5.11	.000	15.421	178.820	125.462
12-10	1.069	.347	.182	4.590	13.430	5.52	.000	13.430	192.249	131.444
12-11	.962	.313	.164	4.590	11.636	5.97	.000	11.636	203.885	136.156
12-12	.866	.283	.148	4.590	10.021	6.48	.000	10.021	213.906	139.846
12-13	.779	.255	.133	4.590	8.567	7.04	.000	8.567	222.473	142.713
S TOT	16.074	5.187	2.732	48.004	222.473	17.11	.000	222.473	222.473	142.713
AFTER	3.447	1.138	.589	30.983	27.313	17.11	.000	27.313	249.786	149.765
TOTAL	19.522	6.325	3.321	78.986	249.786	17.11	.000	249.786	249.786	149.765

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	20.42	8.00	163.710
GROSS ULT., MB & MMF	147.375	302.813	DISCOUNT %	10.00	10.00	149.765
GROSS CUM., MB & MMF	.000	34.044	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	137.743
GROSS RES., MB & MMF	147.375	268.769	DISCOUNTED PAYOUT, YRS.	.00	15.00	122.582
NET RES., MB & MMF	16.129	25.922	UNDISCOUNTED NET/INVEST.	.00	20.00	102.990
NET REVENUE, M$	278.879	79.061	DISCOUNTED NET/INVEST.	.00	25.00	88.332
INITIAL PRICE, $	17.290	3.050	RATE-OF-RETURN, PCT.	100.00	35.00	68.074
INITIAL N.I., PCT .	10.945	9.645	INITIAL W.I., PCT.	12.500	50.00	49.921
					70.00	36.299
					100.00	25.390

APPENDIX B21

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the SW Development Drilling Fund 1994 (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The property that we reviewed is located in the state of Texas.

The net reserves attributable to the property that we reviewed account for 81.7 percent of the total net remaining liquid hydrocarbon reserves and 94.2 percent of the total net remaining gas reserves. The property that we reviewed represents 89.8 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in the property that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

SW Development Drilling Fund 1994

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Reviewed by Ryder Scott
Oil/Condensate—Barrels		45,816		0		0		45,816
Gas—MMCF		114		0		0		114
Income Data
Future Gross Revenue	$	1,078,033	$	0	$	0	$	1,078,033
Deductions		579,672		0		0		579,672
Future Net Income (FNI)	$	498,361	$	0	$	0	$	498,361
Discounted FNI @ 10%	$	312,513	$	0	$	0	$	312,513

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		10,239		0		0		10,239
Gas—MMCF		7		0		0		7
Income Data
Future Gross Revenue	$	190,822	$	0	$	0	$	190,822
Deductions		149,038		0		0		149,038
Future Net Income (FNI)	$	41,784	$	0	$	0	$	41,784
Discounted FNI @ 10%	$	35,312	$	0	$	0	$	35,312
Total Net Reserves
Oil/Condensate—Barrels		56,055		0		0		56,055
Gas—MMCF		121		0		0		121
Income Data
Future Gross Revenue	$	1,268,855	$	0	$	0	$	1,268,855
Deductions		728,710		0		0		728,710
Future Net Income (FNI)	$	540,145	$	0	$	0	$	540,145
Discounted FNI @ 10%	$	347,825	$	0	$	0	$	347,825

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)  Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A)  that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B)  the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii)  Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)  Estimates of proved reserves do not include the following:

(A)  oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B)  crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C)  crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D)  crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed property was prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for this property. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the property which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the property that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 18.3 percent of the total net remaining liquid hydrocarbon reserves and 5.8 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the property that we reviewed and for the other properties.

Reserve Estimates

The reserves for the property that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

General

In general, the reserve estimates for the property that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject property and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the property which was reviewed.

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours, RYDER SCOTT COMPANY, L.P.
By:	/s/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw Approved:
By:	/s/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SW DEV DRILLING FUND 1994	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:18:48
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR94

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.0	8.866	15.321	.000	6.137	11.372	.000	18.83	2.33	115.574	26.471	142.045
12-03	2.0	8.233	14.351	.000	5.705	10.661	.000	18.83	2.33	107.450	24.819	132.269
12-04	2.0	7.671	13.444	.000	5.323	9.995	.000	18.84	2.33	100.271	23.272	123.543
12-05	2.0	7.150	12.595	.000	4.969	9.370	.000	18.84	2.33	93.601	21.822	115.423
12-06	2.0	6.665	11.800	.000	4.638	8.786	.000	18.84	2.33	87.383	20.464	107.847
12-07	1.8	5.616	10.641	.000	3.986	7.998	.000	18.87	2.33	75.206	18.669	93.875
12-08	1.0	3.525	8.782	.000	2.735	6.815	.000	18.99	2.35	51.940	16.015	67.955
12-09	1.0	3.313	8.255	.000	2.571	6.406	.000	18.99	2.35	48.824	15.054	63.878
12-10	1.0	3.114	7.760	.000	2.417	6.022	.000	18.99	2.35	45.894	14.151	60.045
12-11	1.0	2.928	7.294	.000	2.272	5.660	.000	18.99	2.35	43.141	13.302	56.443
12-12	1.0	2.752	6.857	.000	2.135	5.321	.000	18.99	2.35	40.552	12.504	53.056
12-13	1.0	2.587	6.445	.000	2.007	5.002	.000	18.99	2.35	38.119	11.754	49.873
S TOT	1.0	62.419	123.544	.000	44.895	93.407	.000	18.89	2.34	847.955	218.296	1066.252
AFTER	1.0	14.381	35.832	.000	11.160	27.806	.000	18.99	2.35	211.921	65.343	277.264
TOTAL	1.0	76.800	159.376	.000	56.055	121.213	.000	18.91	2.34	1059.877	283.640	1343.516

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	6.272	2.002	3.213	54.269	76.290	8.19	.000	76.290	76.290	72.839
12-03	5.822	1.876	3.000	54.269	67.301	8.68	.000	67.301	143.591	131.254
12-04	5.422	1.759	2.812	54.269	59.280	9.19	.000	59.280	202.871	178.032
12-05	5.051	1.649	2.637	54.269	51.816	9.74	.000	51.816	254.687	215.205
12-06	4.706	1.546	2.473	54.269	44.852	10.32	.000	44.852	299.540	244.460
12-07	3.938	1.408	2.255	47.872	38.402	10.43	.000	38.402	337.942	267.231
12-08	2.389	1.201	1.931	28.681	33.753	8.84	.000	33.753	371.694	285.420
12-09	2.246	1.129	1.815	28.681	30.007	9.31	.000	30.007	401.701	300.122
12-10	2.111	1.061	1.706	28.681	26.486	9.81	.000	26.486	428.187	311.919
12-11	1.984	.998	1.604	28.681	23.176	10.35	.000	23.176	451.363	321.304
12-12	1.865	.938	1.508	28.681	20.064	10.92	.000	20.064	471.427	328.691
12-13	1.753	.882	1.417	28.681	17.140	11.52	.000	17.140	488.566	334.428
S TOT	43.562	16.450	26.371	491.303	488.566	17.53	.000	488.566	488.566	334.428
AFTER	9.748	4.901	7.878	203.158	51.579	17.53	.000	51.579	540.145	347.825
TOTAL	53.310	21.351	34.249	694.461	540.145	17.53	.000	540.145	540.145	347.825

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	19.08	8.00	374.713
GROSS ULT., MB &MMF	161.909	328.572	DISCOUNT %	10.00	10.00	347.825
GROSS CUM., MB &MMF	85.109	169.196	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	324.611
GROSS RES., MB & MMF	76.800	159.376	DISCOUNTED PAYOUT, YRS.	.00	15.00	295.276
NET RES., MB & MMF	56.055	121.213	UNDISCOUNTED NET/INVEST.	.00	20.00	257.217
NET REVENUE, M$	1059.877	283.640	DISCOUNTED NET/INVEST.	.00	25.00	228.569
INITIAL PRICE, $	18.801	2.321	RATE-OF-RETURN, PCT.	100.00	35.00	188.542
INITIAL N.I., PCT.	69.202	74.201	INITIAL W.I., PCT.	88.014	50.00	151.839
					70.00	123.219
					100.00	98.938

SW DEV DRILLING FUND 1994	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:17
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR94

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.0	5.141	12.730	.000	3.990	9.879	.000	18.99	2.35	75.761	23.215	98.976
12-03	1.0	4.804	11.966	.000	3.728	9.286	.000	18.99	2.35	70.796	21.822	92.618
12-04	1.0	4.514	11.248	.000	3.503	8.729	.000	18.99	2.35	66.526	20.513	87.039
12-05	1.0	4.244	10.573	.000	3.293	8.205	.000	18.99	2.35	62.535	19.282	81.816
12-06	1.0	3.989	9.939	.000	3.095	7.713	.000	18.99	2.35	58.783	18.125	76.907
12-07	1.0	3.750	9.343	.000	2.910	7.250	.000	18.99	2.35	55.256	17.037	72.293
12-08	1.0	3.525	8.782	.000	2.735	6.815	.000	18.99	2.35	51.940	16.015	67.955
12-09	1.0	3.313	8.255	.000	2.571	6.406	.000	18.99	2.35	48.824	15.054	63.878
12-10	1.0	3.114	7.760	.000	2.417	6.022	.000	18.99	2.35	45.894	14.151	60.045
12-11	1.0	2.928	7.294	.000	2.272	5.660	.000	18.99	2.35	43.141	13.302	56.443
12-12	1.0	2.752	6.857	.000	2.135	5.321	.000	18.99	2.35	40.552	12.504	53.056
12-13	1.0	2.587	6.445	.000	2.007	5.002	.000	18.99	2.35	38.119	11.754	49.873
S TOT	1.0	44.660	111.193	.000	34.656	86.286	.000	18.99	2.35	658.127	202.773	860.899
AFTER	1.0	14.381	35.832	.000	11.160	27.806	.000	18.99	2.35	211.921	65.343	277.264
TOTAL	1.0	59.041	147.025	.000	45.816	114.092	.000	18.99	2.35	870.048	268.116	1138.164

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.485	1.741	2.812	28.681	62.256	6.52	.000	62.256	62.256	59.429
12-03	3.257	1.637	2.632	28.681	56.412	6.86	.000	56.412	118.668	108.381
12-04	3.060	1.538	2.473	28.681	51.286	7.21	.000	51.286	169.954	148.839
12-05	2.877	1.446	2.325	28.681	46.488	7.58	.000	46.488	216.441	182.180
12-06	2.704	1.359	2.185	28.681	41.978	7.97	.000	41.978	258.419	209.549
12-07	2.542	1.278	2.054	28.681	37.738	8.39	.000	37.738	296.157	231.919
12-08	2.389	1.201	1.931	28.681	33.753	8.84	.000	33.753	329.910	250.108
12-09	2.246	1.129	1.815	28.681	30.007	9.31	.000	30.007	359.917	264.809
12-10	2.111	1.061	1.706	28.681	26.486	9.81	.000	26.486	386.402	276.606
12-11	1.984	.998	1.604	28.681	23.176	10.35	.000	23.176	409.578	285.992
12-12	1.865	.938	1.508	28.681	20.064	10.92	.000	20.064	429.642	293.379
12-13	1.753	.882	1.417	28.681	17.140	11.52	.000	17.140	446.782	299.116
S TOT	30.274	15.208	24.463	344.173	446.782	17.53	.000	446.782	446.782	299.116
AFTER	9.748	4.901	7.878	203.158	51.579	17.53	.000	51.579	498.361	312.513
TOTAL	40.022	20.109	32.341	547.331	498.361	17.53	.000	498.361	498.361	312.513

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	19.08	8.00	338.282
GROSS ULT., MB & MMF	106.909	268.480	DISCOUNT %	10.00	10.00	312.513
GROSS CUM., MB & MMF	47.868	139.455	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	290.345
GROS RES., MB & MMF	59.041	147.025	DISCOUNTED PAYOUT, YRS.	.00	15.00	262.459
NET RES., MB & MMF	45.816	114.092	UNDISCOUNTED NET/INVEST.	.00	20.00	226.535
NET REVENUE, M$	870.048	268.116	DISCOUNTED NET/INVEST.	.00	25.00	199.731
INITIAL PRICE, $	18.990	2.350	RATE-OF-RETURN, PCT.	100.00	35.00	162.717
INITIAL N.I., PCT	77.600	77.600	INITIAL W.I., PCT.	97.001	50.00	129.357
					70.00	103.832
					100.00	82.576

SW DEV DRILLING FUND 1994	DATE	:	02/15/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	21:52:03
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  DR94

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	1.0	3.725	2.590	.000	2.147	1.493	.000	18.54	2.18	39.814	3.256	43.069
12-03	1.0	3.429	2.385	.000	1.977	1.375	.000	18.54	2.18	36.654	2.997	39.651
12-04	1.0	3.157	2.196	.000	1.820	1.266	.000	18.54	2.18	33.744	2.760	36.504
12-05	1.0	2.906	2.021	.000	1.676	1.165	.000	18.54	2.18	31.066	2.540	33.607
12-06	1.0	2.676	1.861	.000	1.543	1.073	.000	18.54	2.18	28.600	2.339	30.939
12-07	1.0	1.866	1.298	.000	1.076	.748	.000	18.54	2.18	19.951	1.631	21.582
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	17.759	12.351	.000	10.239	7.121	.000	18.54	2.18	189.829	15.524	205.352
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	17.759	12.351	.000	10.239	7.121	.000	18.54	2.18	189.829	15.524	205.352

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	2.787	.260	.400	25.588	14.034	12.12	.000	14.034	14.034	13.411
12-03	2.566	.240	.368	25.588	10.889	13.04	.000	10.889	24.923	22.873
12-04	2.362	.221	.339	25.588	7.994	14.04	.000	7.994	32.917	29.192
12-05	2.175	.203	.312	25.588	5.329	15.12	.000	5.329	38.246	33.025
12-06	2.002	.187	.288	25.588	2.875	16.30	.000	2.875	41.121	34.910
12-07	1.397	.131	.201	19.191	.664	17.42	.000	.664	41.785	35.312
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	13.288	1.242	1.908	147.130	41.785	17.42	.000	41.785	41.785	35.312
AFTER	.000	.000	.000	.000	.000	17.42	.000	.000	41.785	35.312
TOTAL	13.288	1.242	1.908	147.130	41.785	17.42	.000	41.785	41.785	35.312

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	5.75	8.00	36.431
GROSS ULT., MB & MMF	55.000	42.092	DISCOUNT %	10.00	10.00	35.312
GROSS CUM., MB & MMF	37.241	29.741	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	34.266
GROS RES., MB & MMF	17.759	12.351	DISCOUNTED PAYOUT, YRS.	.00	15.00	32.817
NET RES., MB & MMF	10.239	7.121	UNDISCOUNTED NET/INVEST.	.00	20.00	30.682
NET REVENUE, M$	189.829	15.524	DISCOUNTED NET/INVEST.	.00	25.00	28.839
INITIAL PRICE, $	18.540	2.180	RATE-OF-RETURN, PCT.	100.00	35.00	25.825
INITIAL N.I., PCT	57.655	57.655	INITIAL W.I., PCT.	72.750	50.00	22.482
					70.00	19.387
					100.00	16.362

APPENDIX B22

March 6, 2002

Southwest Royalties, Inc.

407 N. Eig Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the Southwest Partners, LP (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 4 reserve determinations and are located in the states of New Mexico and Texas.

The net reserves attributable to the properties that we reviewed account for 85.3 percent of the total net remaining liquid hydrocarbon reserves and 91.7 percent of the total net remaining gas reserves. The properties that we reviewed represent 94.5 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

Southwest Partners, LP

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		2,084		0		103,273		105,357
Gas—MMCF		458		0		179		637
Income Data
Future Gross Revenue	$	764,661	$	0	$	2,247,498	$	3,012,159
Deductions		221,435		0		910,717		1,132,152
Future Net Income (FNI)	$	543,226	$	0	$	1,336,781	$	1,880,007
Discounted FNI @ 10%	$	321,295	$	0	$	757,840	$	1,079,135

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		7,610		10,516		0		18,126
Gas—MMCF		18		40		0		58
Income Data
Future Gross Revenue	$	172,666	$	278,755	$	0	$	451,421
Deductions		155,287		200,876		0		356,163
Future Net Income (FNI)	$	17,379	$	77,879	$	0	$	95,258
Discounted FNI @ 10%	$	15,751	$	46,926	$	0	$	62,677
Total Net Reserves
Oil/Condensate—Barrels		9,694		10,516		103,273		123,483
Gas—MMCF		476		40		179		695
Income Data
Future Gross Revenue	$	937,327	$	278,755	$	2,247,498	$	3,463,580
Deductions		376,722		200,876		910,717		1,488,315
Future Net Income (FNI)	$	560,605	$	77,879	$	1,336,781	$	1,975,265
Discounted FNI @ 10%	$	337,046	$	46,926	$	757,840	$	1,141,812

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

recovery when a field is in the late stages of depletion?... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 14.7 percent of the total net remaining liquid hydrocarbon reserves and 8.3 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
By:	/S/    C. PATRICK MCINTURFF
	C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

By:	/S/    L. B. BRANUM
	L. B. Branum, P.E. Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:19:55
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END-   MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	4.0	6.489	337.719	.000	2.992	49.067	.000	18.35	1.82	54.911	89.070	143.981
12-03	5.6	28.834	354.309	.000	22.458	80.206	.000	19.15	2.08	430.139	167.070	597.208
12-04	7.0	27.751	336.673	.000	21.887	82.897	.000	19.11	2.14	418.221	177.141	595.363
12-05	5.4	18.502	292.820	.000	14.434	63.570	.000	19.16	2.07	276.584	131.456	408.040
12-06	5.0	14.071	261.455	.000	10.881	52.805	.000	19.19	2.02	208.792	106.928	315.721
12-07	5.0	11.545	236.188	.000	8.873	45.679	.000	19.20	2.00	170.324	91.281	261.605
12-08	5.0	9.778	214.323	.000	7.480	40.166	.000	19.20	1.98	143.633	79.448	223.080
12-09	4.0	7.730	192.075	.000	5.851	33.375	.000	19.24	1.92	112.561	64.191	176.752
12-10	4.0	6.968	175.852	.000	5.270	30.433	.000	19.24	1.92	101.397	58.459	159.856
12-11	4.0	6.353	161.133	.000	4.807	27.854	.000	19.24	1.92	92.478	53.490	145.968
12-12	4.0	5.845	147.739	.000	4.427	25.568	.000	19.24	1.92	85.167	49.122	134.289
12-13	4.0	5.416	135.530	.000	4.109	23.525	.000	19.24	1.92	79.051	45.245	124.296
S TOT	1.0	149.283	2845.816	.000	113.468	555.148	.000	19.15	2.00	2173.259	1112.901	3286.160
AFTER	1.0	14.895	966.439	.000	10.015	139.971	.000	19.20	1.82	192.340	255.291	447.631
TOTAL	1.0	164.178	3812.255	.000	123.483	695.118	.000	19.16	1.97	2365.599	1368.192	3733.791

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.654	6.757	2.849	55.872	74.848	6.19	.000	74.848	74.848	71.514
12-03	30.015	13.028	6.866	81.978	465.321	3.68	550.000	-84.679	-9.831	-10.857
12-04	29.207	13.862	6.723	107.832	437.739	4.41	.000	437.739	427.908	335.352
12-05	19.302	10.233	4.882	69.344	304.279	4.15	.000	304.279	732.188	553.940
12-06	14.563	8.294	3.933	59.820	229.111	4.40	.000	229.111	961.298	703.505
12-07	11.875	7.064	3.347	59.820	179.499	4.98	.000	179.499	1140.797	810.005
12-08	10.011	6.137	2.913	59.820	144.200	5.57	.000	144.200	1284.997	887.771
12-09	7.840	4.935	2.412	40.524	121.041	4.88	.000	121.041	1406.037	947.082
12-10	7.062	4.493	2.191	40.524	105.586	5.25	.000	105.586	1511.623	994.113
12-11	6.441	4.111	2.003	40.524	92.889	5.62	.000	92.889	1604.512	1031.724
12-12	5.932	3.775	1.840	40.524	82.217	5.99	.000	82.217	1686.729	1061.987
12-13	5.507	3.478	1.698	40.524	73.089	6.38	.000	73.089	1759.819	1086.444
S TOT	151.410	86.167	41.658	697.106	2309.819	12.83	550.000	1759.819	1759.819	1086.444
AFTER	13.286	19.348	8.271	191.279	215.448	12.83	.000	215.448	1975.266	1141.812
TOTAL	164.696	105.515	49.929	888.385	2525.266	12.83	550.000	1975.266	1975.266	1141.812

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	5.0	3.0	LIFE, YRS.	27.33	8.00	1258.352
GROSS ULT., MB & MMF	567.529	11822.850	DISCOUNT %	10.00	10.00	1141.812
GROSS CUM., MB & MMF	403.351	8010.590	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	1041.221
GROSS RES., MB &MMF	164.178	3812.255	DISCOUNTED PAYOUT, YRS.	.00	15.00	914.221
NET RES., MB & MMF	123.483	695.119	UNDISCOUNTED NET/INVEST.	4.59	20.00	749.964
NET REVENUE, M$	2365.599	1368.192	DISCOUNTED NET/INVEST.	3.37	25.00	627.183
INITIAL PRICE, $	19.056	1.887	RATE-OF-RETURN, PCT.	100.00	35.00	458.425
INITIAL N.I., PCT.	75.591	28.634	INITIAL W.I., PCT.	70.806	50.00	309.900
					70.00	202.714
					100.00	122.898

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:19:35
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	4.0	6.489	337.719	.000	2.992	49.067	.000	18.35	1.82	54.911	89.070	143.981
12-03	4.0	4.601	309.701	.000	2.608	45.095	.000	18.39	1.82	47.959	81.958	129.917
12-04	4.0	3.961	284.022	.000	2.400	41.455	.000	18.40	1.82	44.149	75.444	119.593
12-05	2.4	1.573	255.468	.000	.567	34.170	.000	18.31	1.74	10.384	59.323	69.707
12-06	2.0	.936	232.996	.000	.122	30.405	.000	17.92	1.71	2.190	52.031	54.221
12-07	2.0	.847	213.561	.000	.111	27.869	.000	17.92	1.71	1.981	47.698	49.679
12-08	2.0	.769	195.747	.000	.100	25.544	.000	17.92	1.71	1.799	43.725	45.523
12-09	2.0	.699	179.419	.000	.091	23.413	.000	17.92	1.71	1.634	40.083	41.717
12-10	2.0	.635	164.453	.000	.083	21.460	.000	17.92	1.71	1.485	36.745	38.229
12-11	2.0	.577	150.735	.000	.075	19.670	.000	17.92	1.71	1.349	33.684	35.033
12-12	2.0	.524	138.162	.000	.068	18.030	.000	17.92	1.71	1.226	30.879	32.104
12-13	2.0	.476	126.637	.000	.062	16.526	.000	17.92	1.71	1.113	28.307	29.420
S TOT	1.0	22.087	2588.617	.000	9.280	352.704	.000	18.34	1.75	170.179	618.946	789.125
AFTER	1.0	3.173	945.340	.000	.414	123.364	.000	17.92	1.74	7.420	215.102	222.522
TOTAL	1.0	25.260	3533.958	.000	9.694	476.068	.000	18.32	1.75	177.599	834.047	1011.647

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.654	6.757	2.849	55.872	74.848	6.19	.000	74.848	74.848	71.514
12-03	3.263	6.219	2.529	55.872	62.034	6.71	.000	62.034	136.883	125.375
12-04	3.022	5.726	2.309	55.872	52.665	7.19	.000	52.665	189.547	166.943
12-05	.668	4.462	1.743	17.384	45.450	3.87	.000	45.450	234.997	199.543
12-06	.101	3.902	1.507	7.860	40.851	2.58	.000	40.851	275.849	226.179
12-07	.091	3.577	1.380	7.860	36.770	2.71	.000	36.770	312.619	247.974
12-08	.083	3.279	1.265	7.860	33.036	2.87	.000	33.036	345.655	265.776
12-09	.075	3.006	1.159	7.860	29.617	3.03	.000	29.617	375.272	280.285
12-10	.068	2.756	1.062	7.860	26.483	3.21	.000	26.483	401.755	292.080
12-11	.062	2.526	.973	7.860	23.611	3.41	.000	23.611	425.366	301.639
12-12	.056	2.316	.892	7.860	20.980	3.62	.000	20.980	446.346	309.362
12-13	.051	2.123	.817	7.860	18.569	3.85	.000	18.569	464.914	315.576
S TOT	11.194	46.650	18.485	247.880	464.914	12.83	.000	464.914	464.914	315.576
AFTER	.341	16.133	6.181	104.175	95.691	12.83	.000	95.691	560.606	337.046
TOTAL	11.536	62.783	24.667	352.055	560.606	12.83	.000	560.606	560.606	337.046

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	2.0	3.0	LIFE, YRS.	27.33	8.00	366.101
GROSS ULT., MB & MMF	428.611	11510.090	DISCOUNT %	10.00	10.00	337.046
GROSS CUM., MB & MMF	403.351	7976.137	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	312.507
GROSS RES., MB & MMF	25.260	3533.958	DISCOUNTED PAYOUT, YRS.	.00	15.00	282.190
NET RES., MB & MMF	9.694	476.068	UNDISCOUNTED NET/INVEST.	.00	20.00	243.941
NET REVENUE, M$	177.599	834.047	DISCOUNTED NET/INVEST.	.00	25.00	215.883
INITIAL PRICE, $	18.117	1.735	RATE-OF-RETURN, PCT.	100.00	35.00	177.578
INITIAL N.I., PCT.	39.699	14.943	INITIAL W.I., PCT.	27.166	50.00	143.183
					70.00	116.687
					100.00	94.311

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:19:41
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END-   MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.1	.449	1.797	.000	.368	1.415	.000	18.92	2.52	6.963	3.565	10.528
12-04	1.0	4.468	17.871	.000	3.660	14.066	.000	18.92	2.52	69.239	35.447	104.686
12-05	1.0	3.127	12.510	.000	2.562	9.846	.000	18.92	2.52	48.467	24.813	73.280
12-06	1.0	2.189	8.757	.000	1.793	6.893	.000	18.92	2.52	33.927	17.369	51.296
12-07	1.0	1.532	6.130	.000	1.255	4.825	.000	18.92	2.52	23.749	12.158	35.907
12-08	1.0	1.073	4.291	.000	.879	3.377	.000	18.92	2.52	16.624	8.511	25.135
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	12.839	51.355	.000	10.516	40.422	.000	18.92	2.52	198.969	101.863	300.832
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	12.839	51.355	.000	10.516	40.422	.000	18.92	2.52	198.969	101.863	300.832

-END-   MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.487	.285	.098	1.608	8.049	4.10	100.000	-91.951	-91.951	-76.625
12-04	4.847	2.836	.970	19.296	76.737	4.66	.000	76.737	-15.213	-15.921
12-05	3.393	1.985	.679	19.296	47.927	6.03	.000	47.927	32.714	18.560
12-06	2.375	1.390	.475	19.296	27.760	8.00	.000	27.760	60.475	36.731
12-07	1.662	.973	.333	19.296	13.643	10.81	.000	13.643	74.118	44.866
12-08	1.164	.681	.233	19.296	3.762	14.83	.000	3.762	77.880	46.926
12-09
12-10
12-11
12-12
12-13
S TOT	13.928	8.149	2.788	98.088	177.880	14.83	100.000	77.880	77.880	46.926
AFTER	.000	.000	.000	.000	.000	14.83	.000	.000	77.880	46.926
TOTAL	13.928	8.149	2.788	98.088	177.880	14.83	100.000	77.880	77.880	46.926

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	7.00	8.00	51.889
GROSS ULT., MB & MMF	12.839	68.484	DISCOUNT %	10.00	10.00	46.926
GROSS CUM., MB & MMF	.000	17.129	UNDISCOUNTED PAYOUT, YRS.	3.32	12.00	42.441
GROSS RES., MB &MMF	12.839	51.355	DISCOUNTED PAYOUT, YRS.	3.46	15.00	36.498
NET RES., MB & MMF	10.516	40.422	UNDISCOUNTED NET/INVEST.	1.78	20.00	28.327
NET REVENUE, M$	198.969	101.863	DISCOUNTED NET/INVEST.	1.56	25.00	21.869
INITIAL PRICE, $	18.920	2.520	RATE-OF-RETURN, PCT.	65.30	35.00	12.605
INITIAL N.I., PCT.	81.911	78.711	INITIAL W.I., PCT.	100.000	50.00	4.402
					70.00	-1.025
					100.00	-4.118

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:19:48
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE   $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES   M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.5	23.784	42.811	.000	19.482	33.697	.000	19.26	2.42	375.217	81.547	456.764
12-04	2.0	19.323	34.781	.000	15.827	27.376	.000	19.26	2.42	304.834	66.250	371.084
12-05	2.0	13.801	24.843	.000	11.305	19.554	.000	19.26	2.42	217.733	47.320	265.053
12-06	2.0	10.945	19.702	.000	8.965	15.507	.000	19.26	2.42	172.675	37.528	210.203
12-07	2.0	9.165	16.498	.000	7.507	12.986	.000	19.26	2.42	144.594	31.425	176.019
12-08	2.0	7.937	14.286	.000	6.501	11.245	.000	19.26	2.42	125.210	27.212	152.422
12-09	2.0	7.031	12.656	.000	5.759	9.962	.000	19.26	2.42	110.927	24.108	135.035
12-10	2.0	6.333	11.400	.000	5.188	8.973	.000	19.26	2.42	99.913	21.714	121.627
12-11	2.0	5.776	10.398	.000	4.732	8.184	.000	19.26	2.42	91.130	19.805	110.935
12-12	2.0	5.321	9.577	.000	4.358	7.539	.000	19.26	2.42	83.942	18.243	102.185
12-13	2.0	4.940	8.892	.000	4.047	6.999	.000	19.26	2.42	77.938	16.938	94.876
S TOT	2.0	114.358	205.844	.000	93.671	162.022	.000	19.26	2.42	1804.111	392.092	2196.203
AFTER	2.0	11.722	21.099	.000	9.601	16.607	.000	19.26	2.42	184.920	40.189	225.109
TOTAL	2.0	126.079	226.943	.000	103.273	178.629	.000	19.26	2.42	1989.031	432.281	2421.312

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	26.265	6.524	4.240	24.498	395.237	2.45	450.000	-54.763	-54.763	-59.607
12-04	21.338	5.300	3.444	32.664	308.337	3.08	.000	308.337	253.574	184.331
12-05	15.241	3.786	2.460	32.664	210.902	3.72	.000	210.902	464.476	335.837
12-06	12.087	3.002	1.951	32.664	160.499	4.30	.000	160.499	624.975	440.595
12-07	10.122	2.514	1.634	32.664	129.086	4.85	.000	129.086	754.060	517.165
12-08	8.765	2.177	1.415	32.664	107.402	5.38	.000	107.402	861.462	575.069
12-09	7.765	1.929	1.253	32.664	91.424	5.88	.000	91.424	952.886	619.871
12-10	6.994	1.737	1.129	32.664	79.103	6.36	.000	79.103	1031.989	655.107
12-11	6.379	1.584	1.030	32.664	69.278	6.83	.000	69.278	1101.267	683.159
12-12	5.876	1.459	.948	32.664	61.237	7.29	.000	61.237	1162.504	705.699
12-13	5.456	1.355	.881	32.664	54.521	7.74	.000	54.521	1217.024	723.942
S TOT	126.288	31.367	20.385	351.138	1667.024	8.97	450.000	1217.024	1217.024	723.942
AFTER	12.944	3.215	2.089	87.104	119.756	8.97	.000	119.756	1336.781	757.840
TOTAL	139.232	34.582	22.475	438.242	1786.781	8.97	450.000	1336.781	1336.781	757.840

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	14.67	8.00	840.362
GROSS ULT., MB & MMF	126.079	244.267	DISCOUNT %	10.00	10.00	757.840
GROSS CUM., MB & MMF	.000	17.324	UNDISCOUNTED PAYOUT, YRS.	2.18	12.00	686.273
GROSS RES., MB & MMF	126.079	226.943	DISCOUNTED PAYOUT, YRS.	2.24	15.00	595.533
NET RES., MB & MMF	103.273	178.629	UNDISCOUNTED NET/INVEST.	3.97	20.00	477.696
NET REVENUE, M$	1989.031	432.281	DISCOUNTED NET/INVEST.	2.90	25.00	389.431
INITIAL PRICE, $	19.260	2.420	RATE-OF-RETURN, PCT.	100.00	35.00	268.242
INITIAL N.I., PCT.	81.911	78.711	INITIAL W.I., PCT.	100.000	50.00	162.315
					70.00	87.052
					100.00	32.705

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME:	:	21:37:21
TOTAL PROVED RESERVES	DBS FILE:	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE:	:	BASE0102
	SEQ NUMBER:	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END-   MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.0	3.375	330.110	.000	.440	43.078	.000	17.92	1.71	7.892	73.678	81.570
12-03	3.5	25.469	345.385	.000	19.702	73.182	.000	19.25	2.04	379.157	149.008	528.245
12-04	4.0	20.549	312.115	.000	15.987	63.567	.000	19.25	2.02	307.701	128.166	435.867
12-05	4.0	14.848	279.043	.000	11.442	52.726	.000	19.24	1.97	220.181	104.079	324.260
12-06	4.0	11.882	252.698	.000	9.088	45.913	.000	19.24	1.95	174.865	89.559	264.425
12-07	4.0	10.013	230.058	.000	7.618	40.854	.000	19.24	1.94	146.575	79.123	225.698
12-08	4.0	8.706	210.033	.000	6.601	36.789	.000	19.24	1.93	127.008	70.937	197.945
12-09	4.0	7.730	192.075	.000	5.851	33.375	.000	19.24	1.92	112.561	64.191	176.752
12-10	4.0	6.968	175.852	.000	5.270	30.433	.000	19.24	1.92	101.397	58.459	159.856
12-11	4.0	6.353	161.133	.000	4.807	27.854	.000	19.24	1.92	92.478	53.490	145.968
12-12	4.0	5.845	147.739	.000	4.427	25.568	.000	19.24	1.92	85.167	49.122	134.289
12-13	4.0	5.416	135.530	.000	4.109	23.525	.000	19.24	1.92	79.051	45.245	124.296
S TOT	1.0	127.154	2771.770	.000	95.341	496.866	.000	19.24	1.94	1834.034	965.137	2799.171
AFTER	1.0	14.895	966.439	.000	10.015	139.971	.000	19.20	1.82	192.340	255.291	447.631
TOTAL	1.0	142.048	3738.209	.000	105.357	636.836	.000	19.23	1.92	2026.375	1220.428	3246.802

-END-   MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.363	5.526	2.270	7.860	65.551	2.10	.000	65.551	65.551	62.617
12-03	26.446	11.589	6.227	32.358	451.624	2.40	450.000	1.624	67.175	51.951
12-04	21.470	9.944	5.245	40.524	358.684	2.90	.000	358.684	425.859	335.610
12-05	15.354	8.043	4.105	40.524	256.234	3.36	.000	256.234	682.094	519.629
12-06	12.188	6.905	3.458	40.524	201.350	3.77	.000	201.350	883.444	651.022
12-07	10.213	6.091	3.014	40.524	165.856	4.15	.000	165.856	1049.299	749.388
12-08	8.847	5.456	2.680	40.524	140.438	4.52	.000	140.438	1189.737	825.093
12-09	7.840	4.935	2.412	40.524	121.041	4.88	.000	121.041	1310.778	884.404
12-10	7.062	4.493	2.191	40.524	105.586	5.25	.000	105.586	1416.364	931.435
12-11	6.441	4.111	2.003	40.524	92.889	5.62	.000	92.889	1509.253	969.047
12-12	5.932	3.775	1.840	40.524	82.217	5.99	.000	82.217	1591.470	999.310
12-13	5.507	3.478	1.698	40.524	73.089	6.38	.000	73.089	1664.559	1023.766
S TOT	127.664	74.346	37.144	445.458	2114.559	12.83	450.000	1664.559	1664.559	1023.766
AFTER	13.286	19.348	8.271	191.279	215.448	12.83	.000	215.448	1880.007	1079.135
TOTAL	140.950	93.694	45.415	636.738	2330.007	12.83	450.000	1880.007	1880.007	1079.135

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	2.0	2.0	LIFE, YRS.	27.33	8.00	1190.416
GROSS ULT., MB & MMF	389.065	10219.620	DISCOUNT %	10.00	10.00	1079.135
GROSS CUM., MB & MMF	247.017	6481.406	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	983.309
GROSS RES., MB & MMF	142.048	3738.209	DISCOUNTED PAYOUT, YRS.	.00	15.00	862.651
NET RES., MB & MMF	105.357	636.836	UNDISCOUNTED NET/INVEST.	5.18	20.00	707.175
NET REVENUE, M$	2026.374	1220.428	DISCOUNTED NET/INVEST.	3.70	25.00	591.400
INITIAL PRICE, $	19.114	1.838	RATE-OF-RETURN, PCT.	100.00	35.00	432.855
INITIAL N.I., PCT.	74.430	24.834	INITIAL W.I., PCT.	66.566	50.00	293.672
					70.00	193.066
					100.00	117.581

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:21
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES     M$	NET GAS SALES   M$	TOTAL NET SALES     M$
12-02	2.0	3.375	330.110	.000	.440	43.078	.000	17.92	1.71	7.892	73.678	81.570
12-03	2.0	1.685	302.574	.000	.220	39.485	.000	17.92	1.71	3.940	67.541	71.481
12-04	2.0	1.226	277.334	.000	.160	36.191	.000	17.92	1.71	2.867	61.916	64.783
12-05	2.0	1.047	254.200	.000	.137	33.172	.000	17.92	1.71	2.448	56.759	59.207
12-06	2.0	.936	232.996	.000	.122	30.405	.000	17.92	1.71	2.190	52.031	54.221
12-07	2.0	.847	213.561	.000	.111	27.869	.000	17.92	1.71	1.981	47.698	49.679
12-08	2.0	.769	195.747	.000	.100	25.544	.000	17.92	1.71	1.799	43.725	45.523
12-09	2.0	.699	179.419	.000	.091	23.413	.000	17.92	1.71	1.634	40.083	41.717
12-10	2.0	.635	164.453	.000	.083	21.460	.000	17.92	1.71	1.485	36.745	38.229
12-11	2.0	.577	150.735	.000	.075	19.670	.000	17.92	1.71	1.349	33.684	35.033
12-12	2.0	.524	138.162	.000	.068	18.030	.000	17.92	1.71	1.226	30.879	32.104
12-13	2.0	.476	126.637	.000	.062	16.526	.000	17.92	1.71	1.113	28.307	29.420
S TOT	1.0	12.796	2565.927	.000	1.670	334.844	.000	17.92	1.71	29.923	573.045	602.968
AFTER	1.0	3.173	945.340	.000	.414	123.364	.000	17.92	1.74	7.420	215.102	222.522
TOTAL	1.0	15.969	3511.267	.000	2.084	458.208	.000	17.92	1.72	37.343	788.147	825.490

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES     M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST     M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.363	5.526	2.270	7.860	65.551	2.10	.000	65.551	65.551	62.617
12-03	.181	5.066	1.987	7.860	56.387	2.22	.000	56.387	121.938	111.558
12-04	.132	4.644	1.800	7.860	50.347	2.33	.000	50.347	172.285	151.279
12-05	.113	4.257	1.645	7.860	45.332	2.45	.000	45.332	217.618	183.792
12-06	.101	3.902	1.507	7.860	40.851	2.58	.000	40.851	258.469	210.427
12-07	.091	3.577	1.380	7.860	36.770	2.71	.000	36.770	295.239	232.223
12-08	.083	3.279	1.265	7.860	33.036	2.87	.000	33.036	328.275	250.025
12-09	.075	3.006	1.159	7.860	29.617	3.03	.000	29.617	357.892	264.534
12-10	.068	2.756	1.062	7.860	26.483	3.21	.000	26.483	384.375	276.328
12-11	.062	2.526	.973	7.860	23.611	3.41	.000	23.611	407.986	285.888
12-12	.056	2.316	.892	7.860	20.980	3.62	.000	20.980	428.966	293.610
12-13	.051	2.123	.817	7.860	18.569	3.85	.000	18.569	447.535	299.824
S TOT	1.376	42.978	16.758	94.320	447.535	12.83	.000	447.535	447.535	299.824
AFTER	.341	16.133	6.181	104.175	95.691	12.83	.000	95.691	543.226	321.295
TOTAL	1.718	59.111	22.940	198.495	543.226	12.83	.000	543.226	543.226	321.295

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	.0	2.0	LIFE, YRS.	27.33	8.00	350.055
GROSS ULT., MB & MMF	262.986	9975.349	DISCOUNT %	10.00	10.00	321.295
GROSS CUM., MB & MMF	247.017	6464.082	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	297.037
GROSS RES., MB & MMF	15.969	3511.267	DISCOUNTED PAYOUT, YRS.	.00	15.00	267.119
NET RES., MB & MMF	2.084	458.208	UNDISCOUNTED NET/INVEST.	.00	20.00	229.479
NET REVENUE, M$	37.343	788.147	DISCOUNTED NET/INVEST.	.00	25.00	201.969
INITIAL PRICE, $	17.920	1.710	RATE-OF-RETURN, PCT.	100.00	35.00	164.614
INITIAL N.I., PCT.	13.050	13.050	INITIAL W.I., PCT.	18.000	50.00	131.357
					70.00	106.014
					100.00	84.876

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:21
PUP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M	TOTAL NET SALES  M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	1.5	23.784	42.811	.000	19.482	33.697	.000	19.26	2.42	375.217	81.547	456.764
12-04	2.0	19.323	34.781	.000	15.827	27.376	.000	19.26	2.42	304.834	66.250	371.084
12-05	2.0	13.801	24.843	.000	11.305	19.554	.000	19.26	2.42	217.733	47.320	265.053
12-06	2.0	10.945	19.702	.000	8.965	15.507	.000	19.26	2.42	172.675	37.528	210.203
12-07	2.0	9.165	16.498	.000	7.507	12.986	.000	19.26	2.42	144.594	31.425	176.019
12-08	2.0	7.937	14.286	.000	6.501	11.245	.000	19.26	2.42	125.210	27.212	152.422
12-09	2.0	7.031	12.656	.000	5.759	9.962	.000	19.26	2.42	110.927	24.108	135.035
12-10	2.0	6.333	11.400	.000	5.188	8.973	.000	19.26	2.42	99.913	21.714	121.627
12-11	2.0	5.776	10.398	.000	4.732	8.184	.000	19.26	2.42	91.130	19.805	110.935
12-12	2.0	5.321	9.577	.000	4.358	7.539	.000	19.26	2.42	83.942	18.243	102.185
12-13	2.0	4.940	8.892	.000	4.047	6.999	.000	19.26	2.42	77.938	16.938	94.876
S TOT	2.0	14.358	205.844	.000	93.671	162.022	.000	19.26	2.42	1804.111	392.092	2196.203
AFTER	2.0	11.722	21.099	.000	9.601	16.607	.000	19.26	2.42	184.920	40.189	225.109
TOTAL	2.0	26.079	226.943	.000	103.273	178.629	.000	19.26	2.42	1989.031	432.281	2421.312

-END-   MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	26.265	6.524	4.240	24.498	395.237	2.45	450.000	-54.763	-54.763	-59.607
12-04	21.338	5.300	3.444	32.664	308.337	3.08	.000	308.337	253.574	184.331
12-05	15.241	3.786	2.460	32.664	210.902	3.72	.000	210.902	464.476	335.837
12-06	12.087	3.002	1.951	32.664	160.499	4.30	.000	160.499	624.975	440.595
12-07	10.122	2.514	1.634	32.664	129.086	4.85	.000	129.086	754.060	517.165
12-08	8.765	2.177	1.415	32.664	107.402	5.38	.000	107.402	861.462	575.069
12-09	7.765	1.929	1.253	32.664	91.424	5.88	.000	91.424	952.886	619.871
12-10	6.994	1.737	1.129	32.664	79.103	6.36	.000	79.103	1031.989	655.107
12-11	6.379	1.584	1.030	32.664	69.278	6.83	.000	69.278	1101.267	683.159
12-12	5.876	1.459	.948	32.664	61.237	7.29	.000	61.237	1162.504	705.699
12-13	5.456	1.355	.881	32.664	54.521	7.74	.000	54.521	1217.024	723.942
S TOT	126.288	31.367	20.385	351.138	1667.024	8.97	450.000	1217.024	1217.024	723.942
AFTER	12.944	3.215	2.089	87.104	119.756	8.97	.000	119.756	1336.781	757.840
TOTAL	139.232	34.582	22.475	438.242	1786.781	8.97	450.000	1336.781	1336.781	757.840

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	2.0	.0	LIFE, YRS.	14.67	8.00	840.362
GROSS ULT., MB & MMF	126.079	244.267	DISCOUNT %	10.00	10.00	757.840
GROSS CUM., MB & MMF	.000	17.324	UNDISCOUNTED PAYOUT, YRS.	2.18	12.00	686.273
GROSS RES., MB & MMF	126.079	226.943	DISCOUNTED PAYOUT, YRS.	2.24	15.00	595.533
NET RES., MB & MMF	103.273	178.629	UNDISCOUNTED NET/INVEST.	3.97	20.00	477.696
NET REVENUE, M$	1989.031	432.281	DISCOUNTED NET/INVEST.	2.90	25.00	389.431
INITIAL PRICE, $	19.260	2.420	RATE-OF-RETURN, PCT.	100.00	35.00	268.242
INITIAL N.I., PCT.	81.911	78.711	INITIAL W.I., PCT.	100.000	50.00	162.315
					70.00	87.052
					100.00	32.705

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	21:52:06
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END-   MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.0	3.115	7.609	.000	2.551	5.989	.000	18.43	2.57	47.019	15.392	62.411
12-03	2.1	3.365	8.924	.000	2.756	7.024	.000	18.50	2.56	50.982	17.982	68.963
12-04	3.0	7.202	24.558	.000	5.899	19.330	.000	18.73	2.53	110.520	48.975	159.496
12-05	1.4	3.653	13.777	.000	2.992	10.844	.000	18.85	2.52	56.403	27.377	83.780
12-06	1.0	2.189	8.757	.000	1.793	6.893	.000	18.92	2.52	33.927	17.369	51.296
12-07	1.0	1.532	6.130	.000	1.255	4.825	.000	18.92	2.52	23.749	12.158	35.907
12-08	1.0	1.073	4.291	.000	.879	3.377	.000	18.92	2.52	16.624	8.511	25.135
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	22.130	74.046	.000	18.127	58.282	.000	18.71	2.54	339.225	147.764	486.989
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	22.130	74.046	.000	18.127	58.282	.000	18.71	2.54	339.225	147.764	486.989

-END-   MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.291	1.231	.579	48.012	9.298	14.96	.000	9.298	9.298	8.897
12-03	3.569	1.439	.640	49.620	13.697	14.07	100.000	-86.303	-77.006	-62.807
12-04	7.736	3.918	1.478	67.308	79.055	8.82	.000	79.055	2.049	-.257
12-05	3.948	2.190	.776	28.820	48.045	7.45	.000	48.045	50.094	34.311
12-06	2.375	1.390	.475	19.296	27.760	8.00	.000	27.760	77.854	52.482
12-07	1.662	.973	.333	19.296	13.643	10.81	.000	13.643	91.498	60.617
12-08	1.164	.681	.233	19.296	3.762	14.83	.000	3.762	95.260	62.678
12-09
12-10
12-11
12-12
12-13
S TOT	23.746	11.821	4.514	251.648	195.260	14.83	100.000	95.260	95.260	62.678
AFTER	.000	.000	.000	.000	.000	14.83	.000	.000	95.260	62.678
TOTAL	23.746	11.821	4.514	251.648	195.260	14.83	100.000	95.260	95.260	62.678

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	3.0	1.0	LIFE, YRS.	7.00	8.00	67.935
GROSS ULT., MB & MMF	178.464	1603.230	DISCOUNT %	10.00	10.00	62.678
GROSS CUM., MB & MMF	156.334	1529.184	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	57.912
GROSS RES., MB & MMF	22.130	74.046	DISCOUNTED PAYOUT, YRS.	.00	15.00	51.569
NET RES., MB & MMF	18.127	58.282	UNDISCOUNTED NET/INVEST.	1.95	20.00	42.789
NET REVENUE, M$	339.225	147.764	DISCOUNTED NET/INVEST.	1.75	25.00	35.783
INITIAL PRICE, $	18.737	2.536	RATE-OF-RETURN, PCT.	100.00	35.00	25.570
INITIAL N.I., PCT.	81.911	78.711	INITIAL W.I., PCT.	100.000	50.00	16.228
					70.00	9.648
					100.00	5.318

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	21:52:06
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	2.0	3.115	7.609	.000	2.551	5.989	.000	18.43	2.57	47.019	15.392	62.411
12-03	2.0	2.916	7.127	.000	2.388	5.610	.000	18.43	2.57	44.019	14.417	58.436
12-04	2.0	2.735	6.687	.000	2.240	5.264	.000	18.43	2.57	41.282	13.528	54.810
12-05	1.3	.526	1.267	.000	.431	.998	.000	18.43	2.57	7.936	2.564	10.500
12-06
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	1.3	9.291	22.691	.000	7.610	17.860	.000	18.43	2.57	140.256	45.901	186.156
AFTER	1.3	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.3	9.291	22.691	.000	7.610	17.860	.000	18.43	2.57	140.256	45.901	186.156

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.291	1.231	.579	48.012	9.298	14.96	.000	9.298	9.298	8.897
12-03	3.081	1.153	.542	48.012	5.647	15.88	.000	5.647	14.945	13.818
12-04	2.890	1.082	.508	48.012	2.317	16.84	.000	2.317	17.262	15.664
12-05	.556	.205	.097	9.524	.118	17.39	.000	.118	17.380	15.751
12-06
12-07
12-08
12-09
12-10
12-11
12-12
12-13
S TOT	9.818	3.672	1.727	153.560	17.380	17.39	.000	17.380	17.380	15.751
AFTER	.000	.000	.000	.000	.000	17.39	.000	.000	17.380	15.751
TOTAL	9.818	3.672	1.727	153.560	17.380	17.39	.000	17.380	17.380	15.751

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	2.0	1.0	LIFE, YRS.	3.33	8.00	16.046
GROSS ULT., MB & MMF	165.625	1534.746	DISCOUNT %	10.00	10.00	15.751
GROSS CUM., MB & MMF	156.334	1512.055	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	15.470
GROSS RES., MB & MMF	9.291	22.691	DISCOUNTED PAYOUT, YRS.	.00	15.00	15.071
NET RES., MB & MMF	7.610	17.860	UNDISCOUNTED NET/INVEST.	.00	20.00	14.462
NET REVENUE, M$	140.256	45.901	DISCOUNTED NET/INVEST.	.00	25.00	13.913
INITIAL PRICE, $	18.430	2.570	RATE-OF-RETURN, PCT.	100.00	35.00	12.965
INITIAL N.I., PCT.	81.911	78.711	INITIAL W.I., PCT.	100.000	50.00	11.826
					70.00	10.673
					100.00	9.435

SOUTHWEST PARTNERS, LP	DATE	:	02/15/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	21:52:06
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  SWPART

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
12-03	.1	.449	1.797	.000	.368	1.415	.000	18.92	2.52	6.963	3.565	10.528
12-04	1.0	4.468	17.871	.000	3.660	14.066	.000	18.92	2.52	69.239	35.447	104.686
12-05	1.0	3.127	12.510	.000	2.562	9.846	.000	18.92	2.52	48.467	24.813	73.280
12-06	1.0	2.189	8.757	.000	1.793	6.893	.000	18.92	2.52	33.927	17.369	51.296
12-07	1.0	1.532	6.130	.000	1.255	4.825	.000	18.92	2.52	23.749	12.158	35.907
12-08	1.0	1.073	4.291	.000	.879	3.377	.000	18.92	2.52	16.624	8.511	25.135
12-09
12-10
12-11
12-12
12-13
S TOT	1.0	12.839	51.355	.000	10.516	40.422	.000	18.92	2.52	198.969	101.863	300.832
AFTER	1.0	.000	.000	.000	.000	.000	.000	.00	.00	.000	.000	.000
TOTAL	1.0	12.839	51.355	.000	10.516	40.422	.000	18.92	2.52	198.969	101.863	300.832

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	.000	.000	.000	.000	.000	.00	.000	.000	.000	.000
12-03	.487	.285	.098	1.608	8.049	4.10	100.000	-91.951	-91.951	-76.625
12-04	4.847	2.836	.970	19.296	76.737	4.66	.000	76.737	-15.213	-15.921
12-05	3.393	1.985	.679	19.296	47.927	6.03	.000	47.927	32.714	18.560
12-06	2.375	1.390	.475	19.296	27.760	8.00	.000	27.760	60.475	36.731
12-07	1.662	.973	.333	19.296	13.643	10.81	.000	13.643	74.118	44.866
12-08	1.164	.681	.233	19.296	3.762	14.83	.000	3.762	77.880	46.926
12-09
12-10
12-11
12-12
12-13
S TOT	13.928	8.149	2.788	98.088	177.880	14.83	100.000	77.880	77.880	46.926
AFTER	.000	.000	.000	.000	.000	14.83	.000	.000	77.880	46.926
TOTAL	13.928	8.149	2.788	98.088	177.880	14.83	100.000	77.880	77.880	46.926

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	7.00	8.00	51.889
GROSS ULT., MB & MMF	12.839	68.484	DISCOUNT %	10.00	10.00	46.926
GROSS CUM., MB & MMF	.000	17.129	UNDISCOUNTED PAYOUT, YRS.	3.32	12.00	42.441
GROSS RES., MB & MMF	12.839	51.355	DISCOUNTED PAYOUT, YRS.	3.46	15.00	36.498
NET RES., MB & MMF	10.516	40.422	UNDISCOUNTED NET/INVEST.	1.78	20.00	28.327
NET REVENUE, M$	198.969	101.863	DISCOUNTED NET/INVEST.	1.56	25.00	21.869
INITIAL PRICE, $	18.920	2.520	RATE-OF-RETURN, PCT.	65.30	35.00	12.605
INITIAL N.I., PCT.	81.911	78.711	INITIAL W.I., PCT.	100.000	50.00	4.402
					70.00	-1.025
					100.00	-4.118

APPENDIX B22(a)

March 6, 2002

Southwest Royalties, Inc.

407 N. Big Spring

Midland, Texas 79701-4326

Gentlemen:

At your request, we have reviewed the estimates of the remaining proved reserves attributable to certain properties of the Tex-Hal Partners (The Fund) which is administered by Southwest Royalties, Inc. (Southwest Royalties), as of January 1, 2002, as prepared by its engineering and geological staff. The properties that we reviewed are comprised of 62 reserve determinations and are located in the state of Texas.

The net reserves attributable to the properties that we reviewed account for 95.2 percent of the total net remaining liquid hydrocarbon reserves and 99.7 percent of the total net remaining gas reserves. The properties that we reviewed represent 95.6 percent of the total proved discounted future net income based on the unescalated prices and costs as taken from reserve and income projections prepared by Southwest Royalties, Inc. as of January 1, 2002.

The estimated reserves presented in this report are related to hydrocarbon prices. Southwest Royalties has informed us that in the preparation of their reserve and income projections, as of January 1, 2002, they used December 2001 hydrocarbon prices; however, actual future prices may vary significantly from December 2001. Therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The estimated net reserves attributable to The Fund’s interest in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Remaining Reserves and Income

Attributable to Certain Properties of

Tex-Hal Partners Fund

As of January 1, 2002

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Reviewed by Ryder Scott
Oil/Condensate—Barrels		25,606		249,759		232,934		508,299
Gas—MMCF		305		2,142		4,703		7,150
Income Data
Future Gross Revenue	$	970,605	$	7,693,615	$	11,870,400	$	20,534,620
Deductions		507,113		1,847,312		8,220,762		10,575,187
Future Net Income (FNI)	$	463,492	$	5,846,303	$	3,649,638	$	9,959,433
Discounted FNI @ 10%	$	369,687	$	3,134,257	$	1,214,513	$	4,718,457

Southwest Royalties, Inc.

March 6, 2002

Page 2

	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing
Net Reserves of Properties
Not Reviewed by Ryder Scott
Oil/Condensate—Barrels		0		25,417		0		25,417
Gas—MMCF		0		23		0		23
Income Data
Future Gross Revenue	$	0	$	450,901	$	0	$	450,901
Deductions		0		85,260		0		85,260
Future Net Income (FNI)	$	0	$	365,641	$	0	$	365,641
Discounted FNI @ 10%	$	0	$	219,332	$	0	$	219,332
Total Net Reserves
Oil/Condensate—Barrels		25,606		275,176		232,934		533,716
Gas—MMCF		305		2,165		4,703		7,173
Income Data
Future Gross Revenue	$	970,605	$	8,144,516	$	11,870,400	$	20,985,521
Deductions		507,113		1,932,572		8,220,762		10,660,447
Future Net Income (FNI)	$	463,492	$	6,211,944	$	3,649,638	$	10,325,074
Discounted FNI @ 10%	$	369,687	$	3,353,589	$	1,214,513	$	4,937,789

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

The proved reserves presented in this report comply with SEC definitions and guidelines, as outlined below. SEC Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 3

(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and

(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves.    Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves.    Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff’s view on specific questions pertaining to proved oil and gas reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 4

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35)

In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary

recovery when a field is in the late stages of depletion?... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)

Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.

Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed.

Review Procedure and Opinion

In performing our reserve review, we have relied upon data furnished by Southwest Royalties with respect to property interests owned, production and well tests from examined wells, geological structural and isopach maps, well logs, core analyses, and pressure measurements. These data were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. Our review included such tests and procedures as we considered necessary under the circumstances to render the conclusions set forth herein.

We also reviewed the operating costs utilized by Southwest Royalties in their evaluation. In our opinion, Southwest Royalties’ estimates of future operating costs were reasonable and fairly reflect past trends.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 5

In our opinion, Southwest Royalties’ estimates of future reserves for the reviewed properties were prepared in accordance with generally accepted procedures for the estimation of future reserves, and we found no bias in the utilization and analysis of data in estimates for these properties. In general, we were in reasonable agreement with Southwest Royalties’ estimates of remaining proved reserves for the properties which we reviewed; however, in certain cases there was more than an acceptable variance in Southwest Royalties’ estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Southwest Royalties when its reserve estimates were prepared. In these cases, Southwest Royalties revised its estimates to conform to our estimates. As a consequence, it is our opinion that the data presented herein for the properties that we reviewed fairly reflect the estimated net reserves owned by The Fund.

Certain technical personnel of Southwest Royalties are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and work papers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our review.

Other Properties

Other properties, as used herein, are those properties of The Fund which we did not review. The reserves attributable to the other properties account for 4.8 percent of the total net remaining liquid hydrocarbon reserves and 0.3 percent of the total net remaining gas reserves. The same technical personnel of Southwest Royalties prepared the reserve estimates for the properties that we reviewed and for the other properties.

Reserve Estimates

The reserves for the properties that we reviewed were estimated by performance methods, analogy or the volumetric method. The reserve estimates by the performance method utilized extrapolations of various historical data in those cases where such data were definitive. Reserves were estimated by analogy in those behind pipe and undeveloped cases where volumetric data were deemed inadequate for a definitive estimate of reserves. Reserves were estimated by the volumetric method in those cases where there were inadequate historical data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate and the volumetric data were adequate for a reasonable estimate.

The reserves presented herein, as estimated by Southwest Royalties and reviewed by us, are estimates only and should not be construed as being exact quantities. Moreover, estimates of reserves may increase or decrease as a result of future operations.

General

In general, the reserve estimates for the properties that we reviewed are based on data generally available through August, 2001. Gas imbalances, if any, were not taken into account in the gas reserve estimates reviewed.

Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Southwest Royalties, Inc.

March 6, 2002

Page 6

This report was prepared for the exclusive use of The Fund and Southwest Royalties. The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
	/s/    C. PATRICK MCINTURFF         C. Patrick McInturff, P.E. Petroleum Engineer

CPM/sw

Approved:

/s/    L. B. BRANUM            

L. B. Branum, P.E.
Vice President

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:20:22
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	25.7	88.701	704.630	.000	50.560	401.822	.000	16.94	1.88	856.625	756.732	1613.357
12-03	47.8	142.094	1343.744	.000	80.994	766.026	.000	16.97	1.86	1374.206	1426.303	2800.510
12-04	57.8	118.996	1280.267	.000	67.828	729.815	.000	16.97	1.86	1150.780	1360.913	2511.694
12-05	57.8	87.807	1017.063	.000	50.050	579.770	.000	16.96	1.86	848.897	1080.644	1929.541
12-06	56.2	76.621	860.571	.000	43.674	490.531	.000	16.96	1.86	740.697	913.119	1653.816
12-07	55.9	65.625	764.196	.000	37.406	435.592	.000	16.96	1.86	634.335	810.600	1444.935
12-08	55.0	57.295	690.552	.000	32.658	393.615	.000	16.96	1.86	554.024	732.142	1286.166
12-09	55.0	51.570	632.706	.000	29.395	360.642	.000	16.96	1.86	498.639	670.822	1169.461
12-10	54.2	46.997	579.731	.000	26.788	330.447	.000	16.96	1.86	454.409	614.177	1068.586
12-11	53.8	42.749	538.081	.000	24.367	306.706	.000	16.96	1.86	413.324	570.005	983.328
12-12	52.5	37.311	498.291	.000	21.268	284.026	.000	16.96	1.86	360.710	527.932	888.642
12-13	47.3	25.258	456.589	.000	14.397	260.256	.000	16.95	1.86	244.029	483.873	727.902
S TOT	1.0	841.025	9366.422	.000	479.384	5339.246	.000	16.96	1.86	8130.675	9947.262	18077.940
AFTER	1.0	95.318	3216.746	.000	54.332	1833.545	.000	16.97	1.86	922.051	3403.243	4325.294
TOTAL	1.0	936.344	12583.170	.000	533.716	7172.791	.000	16.96	1.86	9052.726	13350.500	22403.230

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	39.405	56.755	45.516	137.137	1334.545	2.37	2055.333	-720.788	-720.788	-705.959
12-03	63.213	106.973	78.910	256.337	2295.077	2.42	2913.333	-618.256	-1339.045	-1276.165
12-04	52.936	102.069	70.701	303.904	1982.084	2.80	39.333	1942.751	603.707	258.801
12-05	39.049	81.048	54.283	303.123	1452.038	3.26	.000	1452.038	2055.744	1301.427
12-06	34.072	68.484	46.538	291.309	1213.413	3.51	.000	1213.413	3269.157	2093.124
12-07	29.179	60.795	40.649	289.537	1024.774	3.82	.000	1024.774	4293.931	2700.773
12-08	25.485	54.911	36.173	283.040	886.557	4.07	.000	886.557	5180.489	3178.598
12-09	22.937	50.312	32.886	283.040	780.286	4.35	.000	780.286	5960.774	3560.894
12-10	20.903	46.063	30.049	277.133	694.438	4.57	.000	694.438	6655.212	3870.163
12-11	19.013	42.750	27.647	274.130	619.788	4.82	.000	619.788	7275.000	4121.137
12-12	16.593	39.595	24.974	265.020	542.461	5.05	.000	542.461	7817.460	4320.871
12-13	11.225	36.290	20.412	227.365	432.609	5.11	.000	432.609	8250.069	4465.715
S TOT	374.011	746.045	508.736	3191.075	13258.070	10.92	5008.000	8250.069	8250.069	4465.715
AFTER	42.414	255.243	120.829	1831.806	2075.001	10.92	.000	2075.001	10325.070	4937.789
TOTAL	416.425	1001.288	629.566	5022.882	15333.070	10.92	5008.000	10325.070	10325.070	4937.789

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	120.0	45.0	LIFE, YRS.	35.33	8.00	5642.063
GROSS ULT., MB & MMF	13651.100	26320.100	DISCOUNT %	10.00	10.00	4937.790
GROSS CUM., MB & MMF	12714.760	13736.940	UNDISCOUNTED PAYOUT, YRS.	2.69	12.00	4343.343
GROSS RES., MB & MMF	936.344	12583.170	DISCOUNTED PAYOUT, YRS.	2.83	15.00	3611.127
NET RES., MB & MMF	533.716	7172.791	UNDISCOUNTED NET/INVEST.	3.06	20.00	2695.663
NET REVENUE, M$	9052.725	13350.500	DISCOUNTED NET/INVEST.	2.08	25.00	2036.111
INITIAL PRICE, $	16.892	1.886	RATE-OF-RETURN, PCT.	68.36	35.00	1168.272
INITIAL N.I., PCT.	57.000	57.007	INITIAL W.I., PCT.	66.667	50.00	449.512
					70.00	-32.367
					100.00	-357.555

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:20:03
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	11.0	7.083	169.076	.000	4.037	96.556	.000	16.40	2.02	66.214	195.042	261.256
12-03	8.8	5.571	99.903	.000	3.176	57.036	.000	16.40	2.02	52.080	115.213	167.294
12-04	7.0	4.795	65.264	.000	2.733	37.263	.000	16.40	2.02	44.826	75.271	120.097
12-05	6.8	4.322	50.724	.000	2.464	28.956	.000	16.40	2.02	40.405	58.492	98.897
12-06	5.2	3.948	31.785	.000	2.250	18.123	.000	16.40	2.02	36.905	36.609	73.514
12-07	4.9	3.557	26.378	.000	2.028	15.036	.000	16.40	2.02	33.253	30.372	63.625
12-08	4.0	2.493	20.517	.000	1.421	11.695	.000	16.40	2.02	23.306	23.624	46.930
12-09	4.0	2.317	18.734	.000	1.321	10.679	.000	16.40	2.02	21.657	21.571	43.227
12-10	3.2	2.153	11.739	.000	1.227	6.691	.000	16.40	2.02	20.124	13.516	33.640
12-11	3.0	2.000	9.897	.000	1.140	5.641	.000	16.40	2.02	18.700	11.395	30.095
12-12	3.0	1.859	9.287	.000	1.060	5.293	.000	16.40	2.02	17.376	10.693	28.069
12-13	3.0	1.727	8.715	.000	.985	4.968	.000	16.40	2.02	16.147	10.035	26.181
S TOT	2.5	41.826	522.020	.000	23.841	297.937	.000	16.40	2.02	390.993	601.833	992.825
AFTER	2.5	3.097	12.477	.000	1.765	7.112	.000	16.40	2.02	28.946	14.366	43.312
TOTAL	2.5	44.923	534.497	.000	25.606	305.049	.000	16.40	2.02	419.939	616.198	1036.137

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.046	14.628	7.307	77.008	159.267	5.07	.000	159.267	159.267	152.732
12-03	2.396	8.641	4.688	61.060	90.509	6.05	.000	90.509	249.776	231.494
12-04	2.062	5.645	3.372	48.656	60.362	6.68	.000	60.362	310.138	279.213
12-05	1.859	4.387	2.780	47.475	42.397	7.75	.000	42.397	352.535	309.678
12-06	1.698	2.746	2.072	35.661	31.338	8.00	.000	31.338	383.873	330.134
12-07	1.530	2.278	1.795	33.889	24.133	8.71	.000	24.133	408.006	344.464
12-08	1.072	1.772	1.323	27.392	15.371	9.36	.000	15.371	423.377	352.756
12-09	.996	1.618	1.218	27.392	12.003	10.07	.000	12.003	435.380	358.643
12-10	.926	1.014	.951	21.485	9.264	10.41	.000	9.264	444.645	362.773
12-11	.860	.855	.851	20.304	7.225	10.99	.000	7.225	451.869	365.701
12-12	.799	.802	.794	20.304	5.370	11.69	.000	5.370	457.239	367.681
12-13	.743	.753	.741	20.304	3.641	12.44	.000	3.641	460.881	368.903
S TOT	17.986	45.137	27.891	440.931	460.881	14.55	.000	460.881	460.881	368.903
AFTER	1.332	1.077	1.227	37.064	2.612	14.55	.000	2.612	463.492	369.687
TOTAL	19.317	46.215	29.118	477.995	463.492	14.55	.000	463.492	463.492	369.687

	OIL	GAS			P.W.%	P.W., M$
GROSS WELLS	99.0	15.0	LIFE, YRS.	14.00	8.00	384.584
GROSS ULT., MB & MMF	12759.680	14146.410	DISCOUNT %	10.00	10.00	369.687
GROSS CUM., MB & MMF	12714.760	13611.920	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	356.193
GROSS RES., MB & MMF	44.923	534.497	DISCOUNTED PAYOUT, YRS.	.00	15.00	338.181
NET RES., MB & MMF	25.606	305.049	UNDISCOUNTED NET/INVEST.	.00	20.00	312.933
NET REVENUE, M$	419.939	616.198	DISCOUNTED NET/INVEST.	.00	25.00	292.244
INITIAL PRICE, $	16.400	2.020	RATE-OF-RETURN, PCT.	100.00	35.00	260.317
INITIAL N.I., PCT.	57.000	57.036	INITIAL W.I., PCT.	66.667	50.00	227.126
					70.00	197.896
					100.00	170.161

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:20:10
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	8.8	24.712	368.691	.000	14.086	210.154	.000	16.99	1.84	239.319	386.683	626.002
12-03	16.3	66.264	373.266	.000	37.771	212.762	.000	16.99	1.84	641.725	391.482	1033.207
12-04	20.8	61.999	307.157	.000	35.339	175.080	.000	16.99	1.84	600.415	322.146	922.561
12-05	21.0	42.855	263.217	.000	24.427	150.034	.000	16.99	1.84	415.022	276.062	691.083
12-06	21.0	38.382	238.606	.000	21.878	136.005	.000	16.99	1.84	371.706	250.250	621.955
12-07	21.0	32.013	214.498	.000	18.247	122.264	.000	16.99	1.84	310.023	224.966	534.989
12-08	21.0	27.853	194.259	.000	15.876	110.728	.000	16.99	1.84	269.738	203.739	473.477
12-09	21.0	24.713	176.586	.000	14.087	100.654	.000	16.99	1.84	239.332	185.203	424.536
12-10	21.0	22.246	160.968	.000	12.680	91.752	.000	16.99	1.84	215.433	168.823	384.256
12-11	21.0	20.256	147.061	.000	11.546	83.825	.000	16.99	1.84	196.160	154.238	350.398
12-12	21.0	18.638	134.627	.000	10.623	76.737	.000	16.99	1.84	180.492	141.197	321.689
12-13	21.0	17.323	123.478	.000	9.874	70.383	.000	16.99	1.84	167.763	129.504	297.267
S TOT	1.0	397.254	2702.414	.000	226.435	1540.376	.000	16.99	1.84	3847.127	2834.292	6681.419
AFTER	1.0	85.511	1095.323	.000	48.741	624.334	.000	16.99	1.84	828.113	1148.775	1976.888
TOTAL	1.0	482.765	3797.737	.000	275.176	2164.710	.000	16.99	1.84	4675.240	3983.066	8658.307

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	11.009	29.001	17.580	17.008	551.404	1.52	375.333	176.071	176.071	155.383
12-03	29.519	29.361	29.230	29.475	915.622	1.61	393.333	522.288	698.359	598.552
12-04	27.619	24.161	26.123	36.608	808.049	1.77	39.333	768.716	1467.075	1205.273
12-05	19.091	20.705	19.539	37.008	594.741	1.95	.000	594.741	2061.816	1632.283
12-06	17.098	18.769	17.583	37.008	531.497	2.03	.000	531.497	2593.314	1979.046
12-07	14.261	16.872	15.116	37.008	451.732	2.16	.000	451.732	3045.045	2246.881
12-08	12.408	15.280	13.374	37.008	395.407	2.27	.000	395.407	3440.452	2459.982
12-09	11.009	13.890	11.989	37.008	350.639	2.39	.000	350.639	3791.091	2631.762
12-10	9.910	12.662	10.851	37.008	313.826	2.52	.000	313.826	4104.917	2771.521
12-11	9.023	11.568	9.894	37.008	282.905	2.65	.000	282.905	4387.822	2886.050
12-12	8.303	10.590	9.084	37.008	256.705	2.78	.000	256.705	4644.526	2980.520
12-13	7.717	9.713	8.395	37.008	234.434	2.91	.000	234.434	4878.960	3058.951
S TOT	176.968	212.572	188.756	416.163	5686.960	10.92	808.000	4878.960	4878.960	3058.951
AFTER	38.093	86.158	55.579	464.075	1332.983	10.92	.000	1332.983	6211.942	3353.590
TOTAL	215.061	298.730	244.336	880.237	7019.942	10.92	808.000	6211.942	6211.942	3353.590

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	11.0	10.0	LIFE, YRS.	35.33	8.00	3718.320
GROSS ULT., MB & MMF	482.765	3902.882	DISCOUNT %	10.00	10.00	3353.590
GROSS CUM., MB & MMF	.000	105.145	UNDISCOUNTED PAYOUT, YRS.	.68	12.00	3047.196
GROSS RES., MB & MMF	482.765	3797.737	DISCOUNTED PAYOUT, YRS.	.70	15.00	2670.914
NET RES., MB & MMF	275.176	2164.710	UNDISCOUNTED NET/INVEST.	8.69	20.00	2200.120
NET REVENUE, M$	4675.241	3983.066	DISCOUNTED NET/INVEST.	5.48	25.00	1858.100
INITIAL PRICE, $	16.990	1.840	RATE-OF-RETURN, PCT.	100.00	35.00	1397.321
INITIAL N.I., PCT.	57.000	57.000	INITIAL W.I., PCT.	66.667	50.00	992.790
					70.00	691.557
					100.00	449.737

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
ALL PROPERTIES	TIME	:	15:20:17
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	5.9	56.906	166.864	.000	32.436	95.112	.000	16.99	1.84	551.093	175.007	726.099
12-03	22.8	70.258	870.574	.000	40.047	496.227	.000	16.99	1.85	680.401	919.608	1600.009
12-04	30.0	52.202	907.846	.000	29.755	517.472	.000	16.99	1.86	505.539	963.496	1469.036
12-05	30.0	40.630	703.123	.000	23.159	400.780	.000	16.99	1.86	393.471	746.090	1139.561
12-06	30.0	34.291	590.180	.000	19.546	336.403	.000	16.99	1.86	332.087	626.260	958.347
12-07	30.0	30.055	523.319	.000	17.131	298.292	.000	16.99	1.86	291.059	555.262	846.321
12-08	30.0	26.949	475.776	.000	15.361	271.192	.000	16.99	1.86	260.981	504.780	765.760
12-09	30.0	24.540	437.385	.000	13.988	249.310	.000	16.99	1.86	237.650	464.048	701.698
12-10	30.0	22.599	407.025	.000	12.881	232.004	.000	16.99	1.86	218.852	431.838	650.690
12-11	29.8	20.493	381.123	.000	11.681	217.240	.000	16.99	1.86	198.463	404.372	602.835
12-12	28.5	16.815	354.378	.000	9.585	201.995	.000	16.99	1.86	162.841	376.043	538.884
12-13	23.3	6.208	324.396	.000	3.538	184.905	.000	16.99	1.86	60.119	344.335	404.454
S TOT	4.9	401.945	6141.988	.000	229.109	3500.933	.000	16.99	1.86	3892.556	6511.137	10403.690
AFTER	4.9	6.711	2108.946	.000	3.825	1202.099	.000	16.99	1.86	64.992	2240.102	2305.094
TOTAL	4.9	408.656	8250.934	.000	232.934	4703.032	.000	16.99	1.86	3957.548	8751.239	12708.790

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	25.350	13.125	20.629	43.121	623.874	2.12	1680.000	-1056.126	-1056.126	-1014.074
12-03	31.298	68.971	44.992	165.802	1288.946	2.53	2520.000	-1231.054	-2287.180	-2106.211
12-04	23.255	72.262	41.206	218.640	1113.673	3.06	.000	1113.673	-1173.507	-1225.685
12-05	18.100	55.957	31.965	218.640	814.899	3.61	.000	814.899	-358.608	-640.534
12-06	15.276	46.970	26.883	218.640	650.578	4.07	.000	650.578	291.971	-216.055
12-07	13.389	41.645	23.739	218.640	548.909	4.45	.000	548.909	840.880	109.428
12-08	12.005	37.858	21.477	218.640	475.780	4.79	.000	475.780	1316.659	365.861
12-09	10.932	34.804	19.679	218.640	417.644	5.11	.000	417.644	1734.303	570.490
12-10	10.067	32.388	18.247	218.640	371.348	5.42	.000	371.348	2105.651	735.869
12-11	9.129	30.328	16.901	216.818	329.659	5.70	.000	329.659	2435.309	869.386
12-12	7.491	28.203	15.096	207.708	280.386	5.98	.000	280.386	2715.695	972.670
12-13	2.765	25.825	11.276	170.053	194.534	6.11	.000	194.534	2910.229	1037.861
S TOT	179.058	488.335	292.089	2333.982	7110.229	9.67	4200.000	2910.229	2910.229	1037.861
AFTER	2.990	168.008	64.023	1330.668	739.406	9.67	.000	739.406	3649.636	1214.513
TOTAL	182.047	656.343	356.112	3664.650	7849.636	9.67	4200.000	3649.636	3649.636	1214.513

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	10.0	20.0	LIFE, YRS.	21.58	8.00	1539.159
GROSS ULT., MB & MMF	408.656	8270.809	DISCOUNT %	10.00	10.00	1214.513
GROSS CUM., MB & MMF	.000	19.875	UNDISCOUNTED PAYOUT, YRS.	4.55	12.00	939.954
GROSS RES., MB & MMF	408.656	8250.934	DISCOUNTED PAYOUT, YRS.	5.66	15.00	602.031
NET RES., MB & MMF	232.934	4703.032	UNDISCOUNTED NET/INVEST.	1.87	20.00	182.610
NET REVENUE, M$	3957.548	8751.240	DISCOUNTED NET/INVEST.	1.32	25.00	-114.233
INITIAL PRICE, $	16.990	1.859	RATE-OF-RETURN, PCT.	23.08	35.00	-489.366
INITIAL N.I., PCT.	57.000	57.000	INITIAL W.I., PCT.	66.667	50.00	-770.404
					70.00	-921.820
					100.00	-977.454

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
PROPS REV BY RYDER SCOTT	TIME	:	21:37:26
TOTAL PROVED RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	24.7	79.141	696.026	.000	45.110	396.917	.000	16.94	1.88	764.038	747.707	1511.746
12-03	46.8	138.270	1340.302	.000	78.814	764.064	.000	16.97	1.86	1337.171	1422.694	2759.865
12-04	56.8	117.466	1278.891	.000	66.956	729.030	.000	16.97	1.86	1135.966	1359.470	2495.436
12-05	56.8	87.195	1016.512	.000	49.701	579.456	.000	16.96	1.86	842.972	1080.066	1923.038
12-06	55.2	71.709	856.150	.000	40.874	488.011	.000	16.96	1.86	693.127	908.482	1601.610
12-07	54.9	61.852	760.800	.000	35.256	433.656	.000	16.96	1.86	597.795	807.038	1404.833
12-08	54.0	54.088	687.666	.000	30.830	391.970	.000	16.96	1.86	522.965	729.115	1252.080
12-09	54.0	48.844	630.252	.000	27.841	359.244	.000	16.96	1.86	472.239	668.249	1140.488
12-10	53.2	44.680	577.646	.000	25.467	329.258	.000	16.96	1.86	431.969	611.990	1043.958
12-11	52.8	40.780	536.308	.000	23.244	305.696	.000	16.96	1.86	394.249	568.146	962.395
12-12	51.5	35.637	496.785	.000	20.313	283.167	.000	16.96	1.86	344.497	526.352	870.849
12-13	46.3	23.835	455.308	.000	13.586	259.526	.000	16.95	1.86	230.247	482.530	712.778
S TOT	1.0	803.497	9332.646	.000	457.993	5319.994	.000	16.96	1.86	7767.236	9911.839	17679.070
AFTER	1.0	88.256	3210.389	.000	50.306	1829.922	.000	16.97	1.86	853.660	3396.576	4250.236
TOTAL	1.0	891.753	12543.040	.000	508.299	7149.916	.000	16.96	1.86	8620.896	13308.420	21929.310

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	35.146	56.078	42.616	135.537	1242.369	2.42	2023.333	-780.964	-780.964	-762.516
12-03	61.510	106.702	77.750	254.737	2259.167	2.43	2913.333	-654.166	-1435.130	-1364.092
12-04	52.254	101.960	70.237	302.304	1968.680	2.80	39.333	1929.347	494.217	160.223
12-05	38.777	81.005	54.098	301.523	1447.636	3.25	.000	1447.636	1941.853	1199.664
12-06	31.884	68.136	45.048	289.709	1166.833	3.56	.000	1166.833	3108.686	1960.928
12-07	27.499	60.528	39.504	287.937	989.365	3.86	.000	989.365	4098.051	2547.577
12-08	24.056	54.684	35.200	281.440	856.700	4.11	.000	856.700	4954.750	3009.305
12-09	21.723	50.119	32.059	281.440	755.147	4.39	.000	755.147	5709.897	3379.280
12-10	19.871	45.899	29.346	275.533	673.309	4.61	.000	673.309	6383.206	3679.134
12-11	18.135	42.611	27.049	272.530	602.069	4.86	.000	602.069	6985.275	3922.930
12-12	15.847	39.476	24.466	263.420	527.640	5.08	.000	527.640	7512.915	4117.206
12-13	10.591	36.190	19.980	225.765	420.251	5.15	.000	420.251	7933.166	4257.913
S TOT	357.293	743.388	497.352	3171.875	12909.170	10.92	4976.000	7933.166	7933.166	4257.913
AFTER	39.268	254.743	118.687	1811.273	2026.265	10.92	.000	2026.265	9959.432	4718.457
TOTAL	396.561	998.131	616.039	4983.148	14935.430	10.92	4976.000	9959.431	9959.432	4718.457

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	119.0	38.0	LIFE, YRS.	35.33	8.00	5403.184
GROSS ULT., MB & MMF	13606.510	24832.190	DISCOUNT %	10.00	10.00	4718.457
GROSS CUM., MB & MMF	12714.760	12289.160	UNDISCOUNTED PAYOUT, YRS.	2.74	12.00	4140.618
GROSS RES., MB & MMF	891.753	12543.040	DISCOUNTED PAYOUT, YRS.	2.89	15.00	3429.006
NET RES., MB & MMF	508.299	7149.916	UNDISCOUNTED NET/INVEST.	3.00	20.00	2539.579
NET REVENUE, M$	8620.895	13308.420	DISCOUNTED NET/INVEST.	2.04	25.00	1899.047
INITIAL PRICE, $	16.889	1.885	RATE-OF-RETURN, PCT.	64.51	35.00	1056.829
INITIAL N.I., PCT.	57.000	57.007	INITIAL W.I., PCT.	66.667	50.00	360.474
					70.00	-104.607
					100.00	-415.721

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:22
PDP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	11.0	7.083	169.076	.000	4.037	96.556	.000	16.40	2.02	66.214	195.042	261.256
12-03	8.8	5.571	99.903	.000	3.176	57.036	.000	16.40	2.02	52.080	115.213	167.294
12-04	7.0	4.795	65.264	.000	2.733	37.263	.000	16.40	2.02	44.826	75.271	120.097
12-05	6.8	4.322	50.724	.000	2.464	28.956	.000	16.40	2.02	40.405	58.492	98.897
12-06	5.2	3.948	31.785	.000	2.250	18.123	.000	16.40	2.02	36.905	36.609	73.514
12-07	4.9	3.557	26.378	.000	2.028	15.036	.000	16.40	2.02	33.253	30.372	63.625
12-08	4.0	2.493	20.517	.000	1.421	11.695	.000	16.40	2.02	23.306	23.624	46.930
12-09	4.0	2.317	18.734	.000	1.321	10.679	.000	16.40	2.02	21.657	21.571	43.227
12-10	3.2	2.153	11.739	.000	1.227	6.691	.000	16.40	2.02	20.124	13.516	33.640
12-11	3.0	2.000	9.897	.000	1.140	5.641	.000	16.40	2.02	18.700	11.395	30.095
12-12	3.0	1.859	9.287	.000	1.060	5.293	.000	16.40	2.02	17.376	10.693	28.069
12-13	3.0	1.727	8.715	.000	.985	4.968	.000	16.40	2.02	16.147	10.035	26.181
S TOT	2.5	41.826	522.020	.000	23.841	297.937	.000	16.40	2.02	390.993	601.833	992.825
AFTER	2.5	3.097	12.477	.000	1.765	7.112	.000	16.40	2.02	28.946	14.366	43.312
TOTAL	2.5	44.923	534.497	.000	25.606	305.049	.000	16.40	2.02	419.939	616.198	1036.137

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBC	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	3.046	14.628	7.307	77.008	159.267	5.07	.000	159.267	159.267	152.732
12-03	2.396	8.641	4.688	61.060	90.509	6.05	.000	90.509	249.776	231.494
12-04	2.062	5.645	3.372	48.656	60.362	6.68	.000	60.362	310.138	279.213
12-05	1.859	4.387	2.780	47.475	42.397	7.75	.000	42.397	352.535	309.678
12-06	1.698	2.746	2.072	35.661	31.338	8.00	.000	31.338	383.873	330.134
12-07	1.530	2.278	1.795	33.889	24.133	8.71	.000	24.133	408.006	344.464
12-08	1.072	1.772	1.323	27.392	15.371	9.36	.000	15.371	423.377	352.756
12-09	.996	1.618	1.218	27.392	12.003	10.07	.000	12.003	435.380	358.643
12-10	.926	1.014	.951	21.485	9.264	10.41	.000	9.264	444.645	362.773
12-11	.860	.855	.851	20.304	7.225	10.99	.000	7.225	451.869	365.701
12-12	.799	.802	.794	20.304	5.370	11.69	.000	5.370	457.239	367.681
12-13	.743	.753	.741	20.304	3.641	12.44	.000	3.641	460.881	368.903
S TOT	17.986	45.137	27.891	440.931	460.881	14.55	.000	460.881	460.881	368.903
AFTER	1.332	1.077	1.227	37.064	2.612	14.55	.000	2.612	463.492	369.687
TOTAL	19.317	46.215	29.118	477.995	463.492	14.55	.000	463.492	463.492	369.687

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	99.0	8.0	LIFE, YRS.	14.00	8.00	384.584
GROSS ULT., MB & MMF	12759.680	12720.430	DISCOUNT %	10.00	10.00	369.687
GROSS CUM., MB & MMF	12714.760	12185.940	UNDISCOUNTED PAYOUT, YRS.	.00	12.00	356.193
GROSS RES., MB & MMF	44.923	534.497	DISCOUNTED PAYOUT, YRS.	.00	15.00	338.181
NET RES., MB & MMF	25.606	305.049	UNDISCOUNTED NET/INVEST.	.00	20.00	312.933
NET REVENUE, M$	419.939	616.198	DISCOUNTED NET/INVEST.	.00	25.00	292.244
INITIAL PRICE, $	16.400	2.020	RATE-OF-RETURN, PCT.	100.00	35.00	260.317
INITIAL N.I., PCT.	57.000	57.037	INITIAL W.I., PCT.	66.667	50.00	227.126
					70.00	197.896
					100.00	170.161

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:24
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE:  1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	7.8	15.151	360.086	.000	8.636	205.249	.000	16.99	1.84	146.732	377.658	524.390
12-03	15.3	62.440	369.825	.000	35.591	210.800	.000	16.99	1.84	604.690	387.872	992.562
12-04	19.8	60.469	305.780	.000	34.467	174.295	.000	16.99	1.84	585.601	320.702	906.303
12-05	20.0	42.243	262.666	.000	24.079	149.720	.000	16.99	1.84	409.096	275.484	684.580
12-06	20.0	33.470	234.185	.000	19.078	133.485	.000	16.99	1.84	324.136	245.613	569.749
12-07	20.0	28.240	211.102	.000	16.097	120.328	.000	16.99	1.84	273.483	221.404	494.887
12-08	20.0	24.646	191.373	.000	14.048	109.082	.000	16.99	1.84	238.678	200.712	439.390
12-09	20.0	21.987	174.133	.000	12.533	99.256	.000	16.99	1.84	212.932	182.630	395.562
12-10	20.0	19.928	158.882	.000	11.359	90.563	.000	16.99	1.84	192.993	166.636	359.628
12-11	20.0	18.286	145.289	.000	10.423	82.815	.000	16.99	1.84	177.086	152.379	329.465
12-12	20.0	16.963	133.120	.000	9.669	75.878	.000	16.99	1.84	164.279	139.616	303.896
12-13	20.0	15.900	122.197	.000	9.063	69.653	.000	16.99	1.84	153.982	128.161	282.142
S TOT	1.0	359.725	2668.638	.000	205.043	1521.124	.000	16.99	1.84	3483.687	2798.868	6282.555
AFTER	1.0	78.449	1088.967	.000	44.716	620.711	.000	16.99	1.84	759.721	1142.109	1901.830
TOTAL	1.0	438.174	3757.605	.000	249.759	2141.835	.000	16.99	1.84	4243.409	3940.977	8184.385

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	6.750	28.324	14.679	15.408	459.229	1.52	343.333	115.895	115.895	98.826
12-03	27.816	29.090	28.070	27.875	879.712	1.60	393.333	486.378	602.273	510.624
12-04	26.938	24.053	25.659	35.008	794.645	1.76	39.333	755.312	1357.585	1106.695
12-05	18.818	20.661	19.353	35.408	590.340	1.92	.000	590.340	1947.925	1530.520
12-06	14.910	18.421	16.093	35.408	484.917	2.05	.000	484.917	2432.842	1846.849
12-07	12.580	16.605	13.971	35.408	416.323	2.17	.000	416.323	2849.165	2093.685
12-08	10.979	15.053	12.401	35.408	365.549	2.29	.000	365.549	3214.713	2290.689
12-09	9.795	13.697	11.162	35.408	325.500	2.41	.000	325.500	3540.213	2450.147
12-10	8.878	12.498	10.148	35.408	292.697	2.53	.000	292.697	3832.911	2580.492
12-11	8.146	11.428	9.297	35.408	265.186	2.65	.000	265.186	4098.097	2687.843
12-12	7.557	10.471	8.576	35.408	241.883	2.78	.000	241.883	4339.980	2776.855
12-13	7.083	9.612	7.963	35.408	222.076	2.91	.000	222.076	4562.056	2851.148
S TOT	160.250	209.915	177.372	396.963	5338.056	10.92	776.000	4562.056	4562.056	2851.148
AFTER	34.947	85.658	53.437	443.541	1284.247	10.92	.000	1284.247	5846.302	3134.257
TOTAL	195.197	295.573	230.808	840.504	6622.303	10.92	776.000	5846.302	5846.302	3134.257

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	10.0	10.0	LIFE, YRS.	35.33	8.00	3479.441
GROSS ULT., MB & MMF	438.174	3840.953	DISCOUNT %	10.00	10.00	3134.258
GROSS CUM., MB & MMF	.000	83.348	UNDISCOUNTED PAYOUT, YRS.	.75	12.00	2844.471
GROSS RES., MB & MMF	438.174	3757.605	DISCOUNTED PAYOUT, YRS.	.77	15.00	2488.793
NET RES., MB & MMF	249.759	2141.835	UNDISCOUNTED NET/INVEST.	8.53	20.00	2044.036
NET REVENUE, M$	4243.409	3940.976	DISCOUNTED NET/INVEST.	5.38	25.00	1721.036
INITIAL PRICE, $	16.990	1.840	RATE-OF-RETURN, PCT.	100.00	35.00	1285.878
INITIAL N.I., PCT.	57.000	57.000	INITIAL W.I., PCT.	66.667	50.00	903.751
					70.00	619.316
					100.00	391.571

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
PROPERTIES REV BY RYDER SCOTT	TIME	:	21:37:21
PUD RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES M$	NET GAS SALES M$	TOTAL NET SALES M$
12-02	5.9	56.906	166.864	.000	32.436	95.112	.000	16.99	1.84	551.093	175.007	726.099
12-03	22.8	70.258	870.574	.000	40.047	496.227	.000	16.99	1.85	680.401	919.608	1600.009
12-04	30.0	52.202	907.846	.000	29.755	517.472	.000	16.99	1.86	505.539	963.496	1469.036
12-05	30.0	40.630	703.123	.000	23.159	400.780	.000	16.99	1.86	393.471	746.090	1139.561
12-06	30.0	34.291	590.180	.000	19.546	336.403	.000	16.99	1.86	332.087	626.260	958.347
12-07	30.0	30.055	523.319	.000	17.131	298.292	.000	16.99	1.86	291.059	555.262	846.321
12-08	30.0	26.949	475.776	.000	15.361	271.192	.000	16.99	1.86	260.981	504.780	765.760
12-09	30.0	24.540	437.385	.000	13.988	249.310	.000	16.99	1.86	237.650	464.048	701.698
12-10	30.0	22.599	407.025	.000	12.881	232.004	.000	16.99	1.86	218.852	431.838	650.690
12-11	29.8	20.493	381.123	.000	11.681	217.240	.000	16.99	1.86	198.463	404.372	602.835
12-12	28.5	16.815	354.378	.000	9.585	201.995	.000	16.99	1.86	162.841	376.043	538.884
12-13	23.3	6.208	324.396	.000	3.538	184.905	.000	16.99	1.86	60.119	344.335	404.454
S TOT	4.9	401.945	6141.988	.000	229.109	3500.933	.000	16.99	1.86	3892.556	6511.137	10403.690
AFTER	4.9	6.711	2108.946	.000	3.825	1202.099	.000	16.99	1.86	64.992	2240.102	2305.094
TOTAL	4.9	408.656	8250.934	.000	232.934	4703.032	.000	16.99	1.86	3957.548	8751.239	12708.790

-END- MO-YR	OIL SEV TAX M$	GAS SEV TAX M$	AD VAL TAX M$	LEASE OP EXPENSES M$	NET REVENUE M$	LIFTING COST $/EBO	CAPITAL INVEST M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	25.350	13.125	20.629	43.121	623.874	2.12	1680.000	-1056.126	-1056.126	-1014.074
12-03	31.298	68.971	44.992	165.802	1288.946	2.53	2520.000	-1231.054	-2287.180	-2106.211
12-04	23.255	72.262	41.206	218.640	1113.673	3.06	.000	1113.673	-1173.507	-1225.685
12-05	18.100	55.957	31.965	218.640	814.899	3.61	.000	814.899	-358.608	-640.534
12-06	15.276	46.970	26.883	218.640	650.578	4.07	.000	650.578	291.971	-216.055
12-07	13.389	41.645	23.739	218.640	548.909	4.45	.000	548.909	840.880	109.428
12-08	12.005	37.858	21.477	218.640	475.780	4.79	.000	457.780	1316.659	365.861
12-09	10.932	34.804	19.679	218.640	417.644	5.11	.000	417.644	1734.303	570.490
12-10	10.067	32.388	18.247	218.640	371.348	5.42	.000	371.348	2105.651	735.869
12-11	9.129	30.328	16.901	216.818	329.659	5.70	.000	329.659	2435.309	869.386
12-12	7.491	28.203	15.096	207.708	280.386	5.98	.000	280.386	2715.695	972.670
12-13	2.765	25.825	11.276	170.053	194.534	6.11	.000	194.534	2910.229	1037.861
S TOT	179.058	488.335	292.089	2333.982	7110.229	9.67	4200.000	2910.229	2910.229	1037.861
AFTER	2.990	168.008	64.023	1330.668	739.406	9.67	.000	739.406	3649.636	1214.513
TOTAL	182.047	656.343	356.112	3664.650	7849.636	9.67	4200.000	3649.636	3649.636	1214.513

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	10.0	20.0	LIFE, YRS.	21.58	8.00	1539.159
GROSS ULT., MB & MMF	408.656	8270.809	DISCOUNT %	10.00	10.00	1214.513
GROSS CUM., MB & MMF	.000	19.875	UNDISCOUNTED PAYOUT, YRS.	4.55	12.00	939.954
GROSS RES., MB & MMF	408.656	8250.934	DISCOUNTED PAYOUT, YRS.	5.66	15.00	602.031
NET RES., MB & MMF	232.934	4703.032	UNDISCOUNTED NET/INVEST.	1.87	20.00	182.610
NET REVENUE, M$	3957.548	8751.240	DISCOUNTED NET/INVEST.	1.32	25.00	-114.233
INITIAL PRICE, $	16.990	1.859	RATE-OF-RETURN, PCT.	23.08	35.00	-489.366
INITIAL N.I., PCT.	57.000	57.000	INITIAL W.I., PCT.	66.667	50.00	-770.404
					70.00	-921.820
					100.00	-977.454

TEX-HAL PARTNERS FUND	DATE	:	02/15/02
PROPS NOT REV BY RYDER SCOTT	TIME	:	21:52:07
PNP RESERVES	DBS FILE	:	SWR0102C
$19.84/BO AND $2.57/MCF NYMEX	SETUP FILE	:	BASE0102
	SEQ NUMBER	:	*****

RESERVES AND ECONOMICS

QUALIFIER:  RSC0102  TEXHAL

EFFECTIVE DATE: 1/02

-END- MO-YR	WELLS	GROSS OIL PROD   MBBLS	GROSS GAS PROD MMCF	GROSS NGL PROD MBBLS	NET OIL PROD MBBLS	NET GAS PROD   MMCF	NET NGL PROD MBBLS	NET OIL PRICE $/BBL	NET GAS PRICE $/MCF	NET LIQ SALES     M$	NET GAS SALES   M$	TOTAL NET SALES M$
12-02	1.0	9.561	8.604	.000	5.450	4.905	.000	16.99	1.84	92.587	9.024	101.612
12-03	1.0	3.824	3.442	.000	2.180	1.962	.000	16.99	1.84	37.035	3.610	40.645
12-04	1.0	1.530	1.377	.000	.872	.785	.000	16.99	1.84	14.814	1.444	16.258
12-05	1.0	.612	.551	.000	.349	.314	.000	16.99	1.84	5.926	.578	6.503
12-06	1.0	4.912	4.421	.000	2.800	2.520	.000	16.99	1.84	47.570	4.637	52.207
12-07	1.0	3.773	3.396	.000	2.151	1.936	.000	16.99	1.84	36.540	3.562	40.102
12-08	1.0	3.207	2.886	.000	1.828	1.645	.000	16.99	1.84	31.059	3.027	34.086
12-09	1.0	2.726	2.453	.000	1.554	1.398	.000	16.99	1.84	26.400	2.573	28.973
12-10	1.0	2.317	2.085	.000	1.321	1.189	.000	16.99	1.84	22.440	2.187	24.627
12-11	1.0	1.970	1.773	.000	1.123	1.010	.000	16.99	1.84	19.074	1.859	20.933
12-12	1.0	1.674	1.507	.000	.954	.859	.000	16.99	1.84	16.213	1.580	17.793
12-13	1.0	1.423	1.281	.000	.811	.730	.000	16.99	1.84	13.781	1.343	15.124
S TOT	1.0	37.529	33.776	.000	21.391	19.252	.000	16.99	1.84	363.440	35.424	398.864
AFTER	1.0	7.062	6.356	.000	4.025	3.623	.000	16.99	1.84	68.392	6.666	75.058
TOTAL	1.0	44.591	40.132	.000	25.417	22.875	.000	16.99	1.84	431.832	42.090	473.922

-END- MO-YR	OIL SEV TAX   M$	GAS SEV TAX   M$	AD VAL TAX   M$	LEASE OP EXPENSES     M$	NET REVENUE M$	LIFTING COST   $/EBO	CAPITAL INVEST     M$	FUT NET CASHFLOW M$	CUM CASHFLOW M$	10.0% CUM DISC CF M$
12-02	4.259	.677	2.900	1.600	92.175	1.51	32.000	60.175	60.175	56.557
12-03	1.704	.271	1.160	1.600	35.910	1.89	.000	35.910	96.086	87.927
12-04	.681	.108	.464	1.600	13.404	2.85	.000	13.404	109.490	98.578
12-05	.273	.043	.186	1.600	4.402	5.24	.000	4.402	113.891	101.763
12-06	2.188	.348	1.490	1.600	46.580	1.75	.000	46.580	160.472	132.197
12-07	1.681	.267	1.145	1.600	35.409	1.90	.000	35.409	195.881	153.196
12-08	1.429	.227	.973	1.600	29.858	2.01	.000	29.858	225.739	169.293
12-09	1.214	.193	.827	1.600	25.139	2.15	.000	25.139	250.878	181.615
12-10	1.032	.164	.703	1.600	21.128	2.30	.000	21.128	272.006	191.029
12-11	.877	.139	.597	1.600	17.719	2.49	.000	17.719	289.725	198.207
12-12	.746	.119	.508	1.600	14.821	2.71	.000	14.821	304.546	203.665
12-13	.634	.101	.432	1.600	12.358	2.97	.000	12.358	316.904	207.802
S TOT	16.718	2.657	11.385	19.200	348.904	15.25	32.000	316.904	316.904	207.802
AFTER	3.146	.500	2.142	20.533	48.736	15.25	.000	48.736	365.640	219.332
TOTAL	19.864	3.157	13.527	39.733	397.641	15.25	32.000	365.641	365.640	219.332

	OIL	GAS			P.W. %	P.W., M$
GROSS WELLS	1.0	.0	LIFE, YRS.	24.83	8.00	238.879
GROSS ULT., MB & MMF	44.591	61.929	DISCOUNT %	10.00	10.00	219.332
GROSS CUM., MB & MMF	.000	21.797	UNDISCOUNTED PAYOUT, YRS.	.35	12.00	202.725
GROSS RES., MB & MMF	44.591	40.132	DISCOUNTED PAYOUT, YRS.	.36	15.00	182.121
NET RES., MB & MMF	25.417	22.875	UNDISCOUNTED NET/INVEST.	12.43	20.00	156.084
NET REVENUE, M$	431.832	42.090	DISCOUNTED NET/INVEST.	7.85	25.00	137.064
INITIAL PRICE, $	16.990	1.840	RATE-OF-RETURN, PCT.	100.00	35.00	111.444
INITIAL N.I., PCT.	57.000	57.000	INITIAL W.I., PCT.	66.667	50.00	89.039
					70.00	72.241
					100.00	58.166

APPENDIX C

FORM OF AGREEMENT AND PLAN OF MERGER

THIS AGREEMENT AND PLAN OF MERGER dated as of             , 20             (the “Agreement”), is entered into by and among Southwest Royalties, Inc., a Delaware corporation (“Southwest”), Southwest Consolidated Partnerships, Inc., a Delaware corporation and a wholly-owned subsidiary of Southwest (“SCP”), and each of the limited partnerships referred to below (each, a “Partnership” and collectively, the “Partnerships”).

RECITALS

A.    Southwest is the managing general partner of each of the following Partnerships:

Partnership Name	State of Formation
Southwest Oil & Gas Income Fund VII-A, L.P.	Delaware
Southwest Royalties Institutional Income Fund VII-B, L.P.	Delaware
Southwest Oil & Gas Income Fund VIII-A, L.P.	Delaware
Southwest Royalties Institutional Income Fund VIII-B, L.P.	Delaware
Southwest Oil & Gas Income Fund IX-A, L.P.	Delaware
Southwest Royalties Institutional Income Fund IX-B, L.P.	Delaware
Southwest Oil & Gas Income Fund X-A, L.P.	Delaware
Southwest Royalties Institutional Income Fund X-A, L.P.	Delaware
Southwest Oil & Gas Income Fund X-B, L.P.	Delaware
Southwest Royalties Institutional Income Fund X-B, L.P.	Delaware
Southwest Oil & Gas Income Fund X-C, L.P.	Delaware
Southwest Royalties Institutional Income Fund X-C, L.P.	Delaware
Southwest Developmental Drilling Fund 91-A, L.P.	Delaware
Southwest Developmental Drilling Fund 92-A, L.P.	Delaware
Southwest Partners, L.P.	Delaware
Southwest Combination Income/Drilling Program 1988, L.P.	Delaware
Southwest Developmental Drilling Fund 1990, L.P.	Delaware
Southwest Developmental Drilling Fund 1993, L.P.	Delaware
Southwest Developmental Drilling Fund 1994, L.P.	Delaware
Southwest Royalties, Inc. Income Fund V, L.P.	Tennessee
Southwest Royalties, Inc. Income Fund VI, L.P.	Tennessee

B.    The respective boards of directors of SCP and Southwest have determined that it is in the best interests of SCP and Southwest (in its individual capacity and as the managing general partner of each Partnership), to merge each Partnership with and into SCP, and the boards of directors of each corporation have approved the merger of each Partnership listed above, upon the terms and subject to the conditions contained herein.

C.    Southwest intends to solicit the vote of the limited partners of each Partnership holding at least seventy-five percent (75%) of the outstanding limited partnership interests of the Partnership to approve the merger of the Partnership. Subject to certain limitations, upon consummation of the merger of each Partnership, the Limited Partners will have the right to receive a number of shares of common stock, par value $0.01 per share, of SCP (the “SCP Common Stock”).

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AGREEMENT

NOW, THEREFORE, in consideration of the representations, warranties, covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and legal sufficiency of which are hereby acknowledged, the parties, intending to be bound hereby, agree as follows:

ARTICLE I

DEFINITIONS

“Affiliate” shall mean, with respect to any specified Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with, such specified Person.

For purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall mean this Agreement and Plan of Merger, together with all exhibits and schedules attached hereto.

“Approved for Listing” shall mean, with respect to shares of Southwest Common Stock issuable in connection with the Roll-up, that such shares have been approved for listing on the Nasdaq (National Market), subject to official notice of issuance.

“Closing” shall have the meaning specified in Section 2.4.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Contract” shall mean any loan or credit agreement, note, bond, indenture, mortgage, deed of trust, lease, franchise, permit, authorization, license, contract, instrument, employee benefit plan or practice or other binding agreement, obligation or commitment.

“DGCL” shall mean the Delaware General Corporation Law.

“DRULPA” has the meaning specified in Section 2.5.

“Effective Time” shall have the meaning specified in Section 2.5.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“GAAP” shall mean United States generally accepted accounting principles as set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board.

“Governmental Authority” shall mean any foreign, federal, state or local court, administrative agency, board, bureau or commission or other governmental department, authority or instrumentality.

“Limited Partner” means a partner of record, other than Southwest, of a Partnership.

“Material Adverse Effect,” with respect to any Person, shall mean a material adverse effect on the business, assets, liabilities, results of operations or condition (financial or otherwise) of such Person and its Subsidiaries, taken as a whole, or on the ability of such Person to perform its obligations hereunder.

“Merger” shall mean the merger of the Partnerships with and into SCP.

“Notes” shall mean the 10½% senior notes due 2004 issued by Southwest.

“Partnerships” shall mean the limited partnerships listed above in Clause A of the recitals to this Agreement.

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“Partnership Interest” or “partnership interest” shall mean a partnership interest in a Partnership.

“Person” shall mean a natural person, corporation, company, partnership, limited partnership or other entity, including a Governmental Authority.

“Prospectus/Proxy Statement” has the meaning specified in Section 6.3.

“Roll-up” means, collectively, the Merger and the subsequent merger of SCP with and into Southwest Managed Assets, Inc., a Delaware corporation.

“Roll-up Registration Statement” shall mean the Registration Statement on Form S-4 by Southwest pursuant to which Southwest is registering its common stock to be issued in connection with the Roll-up under the Securities Act and the Exchange Act.

“SEC” shall mean the U.S. Securities and Exchange Commission.

“Securities Act” shall mean the Securities Act of 1933, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“Southwest” shall have the meaning specified in the preamble hereof.

“SCP” shall have the meaning specified in the preamble hereof.

“SCP Common Stock” shall mean the common stock, par value $.10 per share, of Southwest.

“Special Meeting” shall mean the combined meeting of the limited partners of the Partnerships at which the limited partners of each Partnership will consider and vote upon the merger of their respective Partnership with and into SCP.

“Subsidiary” shall mean, with respect to any Person, a corporation, partnership or other entity in which such Person, a Subsidiary of such Person or such Person and one or more Subsidiaries of such Person, directly or indirectly, has either (i) a majority ownership in the equity thereof, (ii) the power, under ordinary circumstances, to elect, or to direct the election of, a majority of the board of directors or other governing body of such entity, (iii) the title or function of general partner, or the right to designate the Person having such title or function or (iv) control thereof.

“Surviving Corporation” shall have the meaning set forth in Section 2.1.

“Termination Date” shall mean the date, if any, on which this Agreement is terminated pursuant to  Section 7.1.

“TRULPA” has the meaning specified in Section 2.5.

“Wommack” has the meaning set forth in the Recitals to this Agreement.

ARTICLE II

THE MERGER OF EACH PARTNERSHIP

2.1    Merger of Each Partnership.

(a)    At the Effective Time, each Partnership shall be merged with and into SCP, in accordance with the terms and conditions hereinafter set forth and in accordance with the DGCL. Thereupon, the separate existence of each Partnership shall cease, and SCP shall continue as the surviving corporation (sometimes referred to herein as the “Surviving Corporation”).

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(b)    The certificate of incorporation of SCP before the merger of each Partnership shall be and remain the certificate of incorporation of SCP after the Effective Time, until the same shall thereafter be altered, amended, or repealed in accordance with law and SCP’s certificate of incorporation. The bylaws of SCP as in effect at the Effective Time shall be and remain the bylaws of SCP, as the surviving corporation, until the same shall thereafter be altered, amended, or repealed in accordance with law, SCP’s certificate of incorporation or such bylaws.

(c)    At the Effective Time, each of the persons who was serving as an officer of SCP immediately prior to the Effective Time shall continue to be an officer of SCP and shall continue to serve in such capacity at the pleasure of the board of directors of SCP or, if earlier, until their respective death or resignation. At the Effective Time, each of the persons who was serving as a director of SCP immediately prior to the Effective Time shall continue to be a director of SCP, and each shall serve in such capacity until the next annual meeting of stockholders of SCP and until his or her successor is elected and qualified or, if earlier, until his death, resignation, or removal from office.

2.2    Effect on Partnership Interests.    At the Effective Time, by virtue of the merger of each Partnership and without any action on the part of SCP or the other partners of the Partnerships, each partnership interest outstanding immediately prior thereto shall be converted into the right to receive a portion of the amount of SCP Common Stock allocated to the Partnership, which portion is set forth on Exhibit A attached hereto as determined by the procedures set forth on Exhibit B attached hereto. Without limiting the foregoing, as more specifically discussed in the Prospectus/Proxy Statement, a portion of the value of each Partnership undertaking the Merger will be allocated to Southwest as holder of general and/or limited partnership.

2.3    Cancellation of Partnership Interests.

(a)    All partnership interests of each Partnership, when converted into the right to receive SCP Common Stock, shall no longer be outstanding and shall automatically be canceled and retired, and the Limited Partner shall be removed from the appropriate Partnership ownership ledger. Each Limited Partner shall cease to have any rights with respect thereto, except the right to receive the amount of SCP Common Stock to be delivered in consideration therefor.

(b)    The partnership interests, whether general or limited, in each Partnership held directly or indirectly by Southwest shall be canceled; provided, however, that as a result of the merger of each Partnership, SCP will own one-hundred percent (100%) of the properties of each Partnership, including properties attributable to the partnership interests in the Partnership held by Southwest prior to the Merger.

2.4    Closing.    Unless the transactions herein contemplated shall have been abandoned and this Agreement terminated pursuant to Section 8.1, the closing of the Merger and the other transactions contemplated hereby (the “Closing”) shall take place at the offices of              at              a.m./p.m, central time, on the date on which the last of the conditions set forth in Article VII is fulfilled or waived (except for those conditions that, by the express terms thereof, are not capable of being satisfied until the Effective Time), or at such other time and place as the Partnerships and SCP shall agree.

2.5    Effective Time of Merger of Each Partnership.    Upon satisfaction of the conditions set forth in Article VII hereof and as soon as practicable after the Closing, this Merger Agreement, or a certificate of merger setting forth the information required by, and otherwise in compliance with the DGCL and, if applicable, Section 17-211 of the Revised Uniform Limited Partnership Act of the State of Delaware (the “DRULPA”) with respect to the merger of each Partnership, shall be delivered for filing with the Secretary of State of the State of Delaware. At such time, if applicable, a certificate of merger with respect to the merger of each Partnership setting forth the information required by, and otherwise in compliance with, Section 61-2-11 of the Tennessee Revised Uniform Limited Partnership Act of the State of Tennessee (the “TRULPA”) shall be delivered for filing with the Secretary of State of the State of Tennessee. The merger of each Partnership shall become effective upon the later of (a) the day and at the time the Secretary of State of the State of Delaware files this Agreement or such

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certificate of merger in compliance with Section 263 of the DGCL and, if applicable, Section 17-211 of the DRULPA, and (b) if applicable, the day and at the time the Secretary of State of the State of Tennessee files such certificate of merger in compliance with Section 61-2-11 of the TRULPA (the time of such effectiveness is herein called the “Effective Time”). Notwithstanding the foregoing, by action of its board of directors, Southwest, in its individual capacity or as the general partner of each Partnership, may terminate this Agreement at any time prior to the earlier of (a) the filing of this Agreement or the certificate of merger with respect to the merger of such Partnership in compliance with Section 263 of the DGCL and, if applicable, Section 17-211 of the DRULPA with the Secretary of State of the State of Delaware and (b) if applicable, the filing of the certificate of merger with respect to the merger of the Partnership in compliance with Section 61-2-11 of the TRULPA with Secretary of State of the State of Tennessee.

2.6    Closing of Transfer Books.    After the Closing Date, there shall not be any further registration of transfers on the ownership ledger of any Partnership of the partnership interests that were issued and outstanding immediately before the Closing Date and were converted into the right to receive SCP Common Stock.

2.7    Effect of Merger of Each Partnership.    At the Effective Time of the merger of each Partnership, SCP, without further action, as provided by the laws of the State of Delaware shall succeed to and possess all the rights, privileges, powers, and franchises, of a public as well as of a private nature, of the Partnerships; and all property, real, personal and mixed, and all debts due on whatsoever account, including subscriptions to shares, and all other choses in action, and all and every other interest of or belonging to or to due each Partnership shall be deemed to be vested in SCP without further act or deed; and the title to any real estate, or any interest therein, vested in SCP or each Partnership shall not revert or be in any way impaired by reason of the merger of each Partnership. Such transfer to and vesting in SCP shall be deemed to occur by operation of law, and no consent or approval of any other person shall be required in connection with any such transfer or vesting unless such consent or approval is specifically required in the event of merger or consolidation by law or express provision in any contract, agreement, decree, order, or other instrument to which SCP or a Partnership is a party or by which either of them is bound. At and after the Effective Time, SCP shall be responsible and liable for all debts, liabilities, and duties of each Partnership, including franchise taxes, if any, which may be enforced against SCP to the same extent as if said debts, liabilities, and duties had been incurred or contracted by it. Neither the rights of creditors nor any liens upon the property of any Partnership or SCP shall be impaired by the merger of any Partnership.

2.8    SCP Common Stock.    At the Effective Time, each outstanding share of common stock of SCP shall remain outstanding and shall continue to represent one share of common stock of SCP.

2.9    Exchange of Partnership Interests for SCP Common Stock.

(a)    Exchange Procedures.    At the Effective Time, the limited partnership interests surrendered shall be canceled, and SCP shall issue to each Person whose partnership interests were converted pursuant to Section 2.2 into the right to receive shares of SCP Common Stock the shares of SCP Common Stock that such holder has received pursuant to Section 2.2, as contemplated by Section 2.9(c).

If any person claims that such person is a holder of a limited partnership interest of a Partnership and is therefore entitled to shares of SCP Common Stock as provided in this Agreement, notwithstanding the absence of such Person’s name on the ownership ledger of the applicable partnership, SCP shall cause to be delivered in exchange for such partnership interest the consideration deliverable in respect thereof as determined in accordance with this Article II. When authorizing the delivery of such consideration in exchange therefore, SCP may, in its sole discretion and as a condition precedent to the delivery thereof, require the owner of such partnership interest to give SCP a bond, in form and substance reasonably satisfactory to SCP, and in such sum as SCP may reasonably direct, as indemnity against any claim that may be made against SCP with respect to the partnership interest alleged to be held by such person.

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(b)    No Further Ownership Rights in Partnerships.    All shares of SCP Common Stock issued upon the surrender for exchange of partnership interests in the Partnerships shall be deemed to have been issued in full satisfaction of all rights pertaining to such partnership interests.

(c)    No Fractional Shares.    Notwithstanding anything herein to the contrary, no certificate or scrip representing fractional shares of SCP Common Stock shall be issued upon the surrender for exchange of partnership interests in the Partnerships, and such fractional share interests will not entitle the owner thereof to vote or to any rights as a holder of partnership interests in any Partnership. All fractional shares of SCP Common Stock that a holder of SCP Common Stock would otherwise be entitled to receive as a result of the Merger shall be aggregated, and if a fractional share results from such aggregation, such fraction shall be rounded to the nearest whole share.

(d)    No Liability.    The Surviving Corporation shall not be liable to any Limited Partner for shares of SCP Common Stock delivered to a public official pursuant to any applicable abandoned property, escheat or similar law.

ARTICLE III

REPRESENTATIONS AND WARRANTIES OF EACH PARTNERSHIP

As of the Effective Time, each Partnership hereby represents and warrants to Southwest as follows:

3.1    Formation; Qualification.  The Partnership is duly formed under and is validly existing and in good standing under the laws of the State of Delaware or Tennessee, as applicable. The Partnership has all requisite partnership power and authority to own, operate or lease its properties and to carry on its business as now being conducted. The Partnership is duly qualified to do business as a foreign limited partnership and is in good standing in each jurisdiction where the character of its properties owned, operated or leased, or the nature of its activities, makes such qualifications necessary.

3.2    Capitalization.    All of the outstanding partnership interests of the Partnership are free of all liens, encumbrances, defects and preemptive rights and are fully paid. Except as described in the Prospectus/Proxy Statement, there are no outstanding subscriptions, options or other arrangements or commitments obligating the Partnership to issue any additional partnership interests.

3.3    No Conflicts.    Assuming this Agreement is approved by the requisite vote of the limited partners of the Partnership, consummation of the transactions contemplated hereby and compliance with the terms and provisions of this Agreement will not conflict with, result in a breach of, require notice under or constitute a default under (i) its certificate of limited partnership or partnership agreement, (ii) any material judgment, order, injunction, decree or ruling of any court or governmental authority or (iii) any material agreement, indenture or instrument to which the Partnership is a party.

3.4    Authority, Authorization and Enforceability.    Each Partnership has all requisite power and authority to enter into and perform the provisions of this Agreement. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary partnership action on the part of the Partnership other than the approval of its limited partners. Subject to such approval, this Agreement has been duly executed and delivered by the Partnership and constitutes a valid and binding obligation of the Partnership enforceable in accordance with its terms.

3.5    SEC Reports; Financial Statements.

(a)    With respect to each Reporting Partnership (as defined below), the Partnership’s (A) Annual Report on Form 10-K for the year ended             ,              (B) Quarterly Report on Form 10-Q for the quarter

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ended             ,              and (C) all other reports or registration statements filed with the Securities and Exchange Commission (the “SEC”) since             ,              (collectively, the “Partnership’s SEC Reports”) (1) were prepared in accordance with the applicable requirements of the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”), and (2) as of their respective dates, did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they are made, not misleading.

(b)    Each of the financial statements of the Partnership for the year ended             ,              and for the three months ended             ,              contained in the Partnership’s supplement to the Prospectus/Proxy Statement and, with respect to each Reporting Partnership, in the Partnership’s SEC Reports have been prepared in accordance with generally accepted accounting principles applied on a consistent basis throughout the periods involved (except as may be indicated in the notes thereto) and each fairly presents the financial position of the Partnership as of the respective dates thereof and the results of operations and cash flows of the Partnership for the periods indicated, except that the unaudited interim financial statements are subject to normal and recurring year-end adjustments that are not expected to be material in amount.

(c)    For purposes hereof, the term “Reporting Partnership” means:

Southwest Oil & Gas Income Fund VII-A, L.P.

Southwest Royalties Institutional Income Fund VII-B, L.P.

Southwest Oil & Gas Income Fund VIII-A, L.P.

Southwest Royalties Institutional Income Fund VIII-B, L.P.

Southwest Oil & Gas Income Fund IX-A, L.P.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Southwest Oil & Gas Income Fund X-A, L.P.

Southwest Royalties Institutional Income Fund X-A, L.P.

Southwest Oil & Gas Income Fund X-B, L.P.

Southwest Royalties Institutional Income Fund X-B, L.P.

Southwest Oil & Gas Income Fund X-C, L.P.

Southwest Royalties Institutional Income Fund X-C, L.P.

Southwest Developmental Drilling Fund 91-A, L.P.

Southwest Developmental Drilling Fund 92-A, L.P.

Southwest Royalties, Inc. Income Fund V

Southwest Royalties, Inc. Income Fund VI

3.6    No Material Adverse Change.    Since             ,             , the Partnership has conducted its operations in the ordinary and usual course of business and has paid all of its obligations as they have become due; and the business of the Partnership has not undergone any material adverse change since such date.

3.7    Accuracy of Information.    None of the information supplied or to be supplied by the Partnership for inclusion in the Prospectus/Proxy Statement, as amended or supplemented, will, at the time of the mailing of the Prospectus/Proxy Statement, the time of the special meeting of the limited partners of the Partnership (each, a “Special Meeting”) or the Closing Date, be false or misleading with respect to any material fact, contain any untrue statement of material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.

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ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SOUTHWEST

Southwest hereby represents and warrants to each Partnership as follows:

4.1    Organization; Qualification.    Southwest is a corporation duly formed under the DGCL and is validly existing and in good standing under the laws of the State of Delaware. Southwest has all requisite corporate power and authority to own, operate or lease its properties and to carry on its business as now being conducted. Southwest is duly qualified to do business as a foreign corporation and is in good standing in each jurisdiction where the character of its properties owned, operated or leased, or the nature of its activities, makes such qualifications necessary.

4.2    No Conflicts.    Consummation of the transactions contemplated hereby and compliance with the terms and provisions of this Agreement will not conflict with, result in a breach of, require notice under or constitute a default under (i) its certificate of incorporation or bylaws, (ii) any material judgment, order, injunction, decree or ruling of any court or governmental authority or (iii) except as disclosed in the Prospectus/Proxy Statement, any material agreement, indenture or instrument to which Southwest is a party.

4.3    Authority, Authorization and Enforceability.    Southwest has all requisite corporate power and authority to execute and deliver this Agreement and to perform the provisions of this Agreement. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of Southwest. This Agreement has been duly executed and delivered by Southwest and constitutes a valid and binding obligation of Southwest enforceable in accordance with its terms.

4.4    SEC Reports; Financial Statements.

(a)    Southwest’s (A) Annual Report on Form 10-K for the year ended             ,              (B) Quarterly Report on Form 10-Q for the quarter ended             ,              , and (C) all other reports or registration statements filed with the SEC since             ,              (collectively, “Southwest’s SEC Reports”) (1) were prepared in accordance with the applicable requirements of the Securities Act and the Exchange Act, and (2) as of their respective dates, did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they are made, not misleading.

(b)    Each of the financial statements of Southwest for the year ended             ,              and for the three months ended             ,              contained in Southwest’s SEC Reports has been prepared in accordance with generally accepted accounting principles applied on a consistent basis throughout the periods involved (except as may be indicated in the notes thereto) and each fairly presents the financial position of Southwest as of the respective dates thereof and the results of operations and cash flows of Southwest for the periods indicated, except that the unaudited interim financial statements are subject to normal and recurring year-end adjustments that are not expected to be material in amount.

4.5    Ordinary Course.    Since             , Southwest has conducted its operations in the ordinary and usual course of business and has paid all of its obligations as they have become due.

4.6    Accuracy of Information.    None of the information supplied or to be supplied by Southwest for inclusion in the Prospectus/Proxy Statement, as amended or supplemented, will, at the time of the mailing of the Prospectus/Proxy Statement, the time of the Special Meeting of each Partnership or the Closing Date, be false or misleading with respect to any material fact, contain any untrue statement of material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.

4.7    Capacity as General Partner.  Southwest is the managing general partner of each Partnership.

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ARTICLE V

REPRESENTATIONS AND WARRANTIES OF SCP

SCP hereby represents and warrants to each Partnership as follows:

5.1    Organization; Qualification.    SCP is a corporation duly formed under the DGCL and is validly existing and in good standing under the laws of the State of Delaware. SCP has all requisite corporate power and authority to own, operate or lease its properties and to carry on its business as now being conducted. SCP is duly qualified to do business as a foreign corporation and is in good standing in each jurisdiction where the character of its properties owned, operated or leased, or the nature of its activities, makes such qualifications necessary.

5.2    No Conflicts.    Consummation of the transactions contemplated hereby and compliance with the terms and provisions of this Agreement will not conflict with, result in a breach of, require notice under or constitute a default under (i) its certificate of incorporation or bylaws, (ii) any material judgment, order, injunction, decree or ruling of any court or governmental authority or (iii) any material agreement, indenture or instrument to which SCP is a party.

5.3    Authority, Authorization and Enforceability.    SCP has all requisite corporate power and authority to execute and deliver this Agreement and to perform the provisions of this Agreement. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of SCP. This Agreement has been duly executed and delivered by SCP and constitutes a valid and binding obligation of SCP enforceable in accordance with its terms.

5.4    No Material Adverse Change.    Since             , SCP has conducted its operations in the ordinary and usual course of business and has paid all of its obligations as they have become due; and the business of SCP has not undergone any material adverse change since such date.

ARTICLE VI

ADDITIONAL AGREEMENTS

6.1    Conduct of Business Pending the Merger of Each Partnership.    Each Partnership covenants and agrees that, between the date of this Agreement and the Closing Date, unless the other parties shall otherwise agree in writing or as otherwise contemplated in this Agreement, it shall conduct its businesses only in the ordinary course of business and in a manner consistent with past practice, and it shall not take any action except for actions consistent with such practice. Each Partnership shall use its reasonable best efforts to preserve intact its business organization, to keep available the services of its present officers, employees and consultants, and to preserve its relationships with customers, suppliers and other persons with which it has significant business dealings.

6.2    Special Meetings; Proxies.    As soon as reasonably practicable after the execution of this Agreement, Southwest and SCP will take all action necessary to duly call, give notice of, convene and hold the Special Meetings, or take action by written consent, to consider and vote upon approval of this Agreement and the transactions contemplated hereby. Southwest and SCP will use its reasonable best efforts to solicit from the limited partners proxies in favor of this Agreement, and to take all other action necessary or advisable to secure any vote or consent of the limited partners of each Partnership required by the partnership agreement of the Partnership or this Agreement or applicable law to effect the merger of the Partnership.

6.3    Prospectus/Proxy Statement.    Southwest shall file with the SEC under the Exchange Act a preliminary prospectus/proxy statement, and prospectus supplements, for each Special Meeting (the definitive form of such proxy statement/prospectus is referred to as the “Prospectus/Proxy Statement”). Southwest shall use all reasonable commercial efforts to have the Prospectus/Proxy Statement cleared with the SEC as promptly as practicable. Southwest shall cause the Prospectus/Proxy Statement to be mailed to the limited partners of each Partnership as soon as practicable in accordance with applicable federal and state law.

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6.4    Authorization for Shares.    Prior to the Effective Time, Southwest and SCP shall have taken all action necessary to permit Southwest to issue the number of shares of SCP Common Stock required to be issued pursuant to this Agreement.

6.5    Additional Agreements.    Subject to the terms and conditions herein provided, each of the parties hereto agrees to use all reasonable commercial efforts to obtain in a timely manner all necessary waivers, consents and approvals and to effect all necessary registrations and filings, and to use all reasonable commercial efforts to take, or cause to be taken, all other actions and to do, or cause to be done, all other things necessary, proper or advisable under applicable laws and regulations to consummate and make effective as promptly as practicable the transactions contemplated by this Agreement.

ARTICLE VII

CONDITIONS PRECEDENT TO THE MERGER OF EACH PARTNERSHIP

7.1    Conditions to Each Party’s Obligations to Effect the Merger of Each Partnership.    The respective obligations of each party to effect the merger of each Partnership shall be subject to the fulfillment (or waiver in whole or in part by the intended beneficiary thereof in its sole discretion) at or prior to the Closing Date of the following conditions:

(a)    The parties to the merger of each Partnership having made all filings and registrations with, and notifications to, all third parties, including, without limitation, lenders and all appropriate regulatory authorities, required for consummation of the transactions contemplated by this Agreement (other than the filing and recordation of appropriate merger documents required by the DGCL and the DRULPA, as applicable), and all approvals and authorizations and consents of all third parties, including, without limitation, lenders and all regulatory authorities, required for consummation of the transactions contemplated by this Agreement shall have been received and shall be in full force and effect, except for such filings, registrations, notifications, approvals, authorizations and consents, the failure of which to make or obtain would not have a material adverse effect on the business or financial condition of Southwest or any Partnership.

(b)    Either Southwest Royalties, Inc., Income Fund VI, L.P., or Southwest Partners, L.P., shall have approved a merger or combination with Southwest pursuant to a separate agreement by seventy-five percent (75%) in interest of the limited partners of such partnerships.

(c)    The Roll-up Registration Statement shall have become effective in accordance with the Securities Act and the Exchange Act and shall not be the subject of any stop order or proceedings seeking a stop order; all necessary permits and authorizations under state securities or Blue Sky laws, the Securities Act and the Exchange Act relating to the issuance and trading of shares of Southwest Common Stock to be issued in connection with the Roll-up shall have been obtained and shall be in effect; and such shares of Southwest Common Stock and such other shares required to be reserved for issuance in connection with the Roll-up shall have been Approved for Listing.

(d)    All consents, approvals and authorizations of any Governmental Authority legally required for the consummation of the transactions contemplated by this Agreement shall have been obtained and be in effect at the Effective Time, except those consents the failure to obtain would not be reasonably likely to have a Material Adverse Effect on Southwest or any Partnership.

(e)    No court of competent jurisdiction or other Governmental Authority shall have issued an order, decree, ruling or judgment that is still in effect restraining, enjoining or prohibiting the Roll-up.

(f)    No action, proceeding or investigation by any Governmental Authority with respect to the Roll-up shall be pending that seeks to restrain, enjoin, prohibit or delay consummation of the transactions

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contemplated by this Agreement or to impose any material restrictions or requirements thereon or on either Southwest or any Partnership with respect thereto.

(g)    No action shall have been taken, and no statute, rule, regulation or executive order shall have been enacted, entered, promulgated or enforced by any Governmental Authority with respect to the Roll-up that, individually or in the aggregate, would (i) restrain, prohibit or delay the consummation of the Roll-up or (ii) impose material restrictions or requirements thereon or on either Southwest or any Partnership with respect thereto.

7.2    Conditions to Obligations of Southwest and SCP to Effect the Merger of Each Partnership.    The obligations of Southwest and SCP to effect the merger of each Partnership shall be subject to the fulfillment (or waiver in whole or in part by the intended beneficiary thereof in its sole discretion), at or prior to the Closing Date, of the following additional conditions:

(a)    This Agreement shall have been approved by the limited partners of each Partnership holding at least seventy-five (75%) of the outstanding limited partnership interests voting in person or by proxy at the Special Meeting at which a quorum is present, with respect to each merger.

(b)    Each Partnership shall have performed in all material respects its covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time, and the representations and warranties of Each Partnership contained in this Agreement shall be true and correct in all material respects as of the date of this Agreement and as of the Effective Time as if made as of the Effective Time (except to the extent such representations and warranties address matters as of a particular date), except in each case (i) where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest or any Partnership or (ii) to the extent specifically contemplated or permitted by this Agreement.

(c)    A majority of the holders of the 10½% Senior Notes due 2004, Series B, shall have consented to or waived all applicable provisions of the Indenture, dated October 14, 1997, by and among Southwest, Southwest Royalties Holdings, Inc., as the parent guarantor, and State Street Bank and Trust Company, N.A., as trustee.

7.3    Conditions to Obligations of Each Partnership to Effect the Merger of Such Partnership.    The obligations of each Partnership to effect the merger of such Partnership shall be subject to the fulfillment (or waiver in whole or in part by the intended beneficiary thereof in its sole discretion) at or prior to the Closing Date of the following additional conditions:

(a)    Southwest and SCP shall have performed in all material respects its respective covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time and the representations and warranties of Southwest and SCP contained in this Agreement shall be true and correct in all material respects as of the date of this Agreement and as of the Effective Time as if made as of the Effective Time (except to the extent such representations and warranties address matters as of a particular date), except in each case (i) where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest, SCP or any Partnership; (ii) to the extent specifically contemplated or permitted by this Agreement;

(b)    Southwest and SCP shall have obtained the consent or approval of each Person whose consent or approval shall be required for the consummation of the Merger under any Contract, to which Southwest or SCP shall be a party or by which its properties and assets are bound, except (i) where the failure to so obtain such consents and approvals, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest or the Surviving Corporation or upon the consummation of the transactions contemplated by this Agreement or (ii) to the extent that alternative arrangements (reasonably

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acceptable to the Partnerships) relating to the failure to obtain any such consent or approval are otherwise provided for; and

7.3(c)    Notwithstanding the foregoing, the Merger has been approved by the holders of a majority of the outstanding shares of Southwest common stock and Class A common stock voting together as a single class.

ARTICLE VIII

TERMINATION

8.1    Termination.    This Agreement may be terminated and the merger of any Partnership contemplated hereby may be abandoned, in whole or in part, at any time prior to the Effective Time, whether before or after approval of the merger of the Partnership by its limited partners:

(a)    by the mutual consent of each party hereto, which consent shall be effected by action of the Board of Directors of SCP and Southwest as managing general partner of the Limited Partnerships;

(b)    by any party if any court of competent jurisdiction or any other Governmental Authority shall have issued an order, decree, ruling or judgment (other than a temporary restraining order) restraining, enjoining or otherwise prohibiting the Roll-up and such order, decree, ruling or judgment shall have become final and nonappealable, provided that, if the party seeking to terminate this Agreement pursuant to this clause (b) is a party to the applicable proceeding, such party shall have used all commercially reasonable efforts to remove such order, decree, ruling or judgment;

(c)    by any Partnership with respect to the Partnership’s merger if (i) Southwest or SCP shall have failed to perform in all material respects its respective covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time, or (ii) the respective representations and warranties of Southwest or SCP contained in this Agreement are or shall become untrue in any material respect (except to the extent such representations and warranties address matters as of a particular date), except where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest or SCP;

(d)    by Southwest or SCP if (i) any Partnership shall not have performed in all material respects its covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time, or (ii) the representations and warranties of any Partnership contained in this Agreement are or shall become untrue in any material respect (except to the extent such representations and warranties address matters as of a particular date), except where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest, SCP or such Partnership.

8.2    Effect of Termination.    In the event of termination of this Agreement pursuant to Section 8.1, this Agreement shall terminate, without any liability on the part of any party or its directors, officers or stockholders.

8.3    Amendment.    This Agreement may not be amended except by an instrument in writing signed by SCP and each Partnership.

8.4    Waivers.    At any time prior to the Effective Time, any party may, to the extent legally allowed, (i) extend the time for the performance of any of the obligations or acts of any other party; (ii) waive any inaccuracies in the representations and warranties of the other party contained herein or in any document delivered pursuant to this Agreement and (iii) waive compliance with any of the agreements or conditions of any other party contained herein; provided, however, that no failure or delay by Southwest, SCP or any Partnership in exercising any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right hereunder. Any agreement on the

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part of Southwest or any Partnership to any such extension or waiver shall be valid only if set forth in an instrument in writing signed on behalf of such party.

ARTICLE IX

MISCELLANEOUS

9.1    Notices.    All notices and other communications hereunder shall be in writing and shall be deemed given upon (a) a transmitter’s confirmation of a receipt of a facsimile transmission (but only if followed by confirmed delivery of a standard overnight courier the following business day or if delivered by hand the following business day), (b) confirmed delivery of a standard overnight courier or when delivered by hand or (c) the expiration of five business days after the date mailed by certified or registered mail (return receipt requested), postage prepaid, to the parties at the following addresses (or at such other addresses for a party as shall be specified by like notice):

If to any Partnership to:

Southwest Royalties Holdings, Inc.

407 N. Big Spring

Suite 300

Midland, Texas 79701

Attn: H. H. Wommack, III

If to Southwest or SCP to:

Southwest Royalties, Inc. 407 N. Big Spring

Suite 300

Midland, Texas 79701

Attn: H. H. Wommack, III

with a copy (which shall not constitute effective notice) to:

Baker, Donelson, Bearman & Caldwell

A Professional Corporation

1800 Republic Centre

633 Chestnut Street

Chattanooga, Tennessee 37450-1800

Attention: J. Porter Durham, Jr., Esquire

9.2    Certain Construction Rules.    The article and section headings and the table of contents contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. As used in this Agreement, unless otherwise provided to the contrary, (a) all references to days or months shall be deemed references to calendar days or months and (b) any reference to a “Section,” “Article,” “Exhibit” or “Schedule” shall be deemed to refer to a section or article of this Agreement or an exhibit or schedule to this Agreement. The words “hereof,” “herein” and “hereunder” and words of similar import referring to this Agreement refer to this Agreement as a whole and not to any particular provision of this Agreement. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” Unless otherwise specifically provided for herein, the term “or” shall not be deemed to be exclusive.

9.3    Severability.    If any provision of this Agreement or the application of any such provision to any Person or circumstance, shall be declared judicially to be invalid, unenforceable or void, such decision shall not have the effect of invalidating or voiding the remainder of this Agreement, it being the intent and agreement of Southwest, SCP and each Partnership that this Agreement shall be deemed amended by modifying such provision to the extent necessary to render it valid, legal and enforceable while preserving its intent or, if such modification

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is not possible, by substituting therefor another provision that is legal and enforceable and that achieves the same objective.

9.4    Assignment; Binding Effect.    Neither this Agreement nor any of the rights, benefits or obligations hereunder may be assigned by Southwest, SCP or any Partnership (whether by operation of law or otherwise) without the prior written consent of all of the other parties. Subject to the preceding sentence, this Agreement will be binding upon, inure to the benefit of and be enforceable by Southwest, SCP and each Partnership and their respective successors and permitted assigns.

9.5    No Third Party Beneficiaries.    Nothing in this Agreement, express or implied, is intended to or shall confer upon any Person (other than Southwest, SCP and each Partnership or their respective successors or permitted assigns) any legal or equitable right, benefit or remedy of any nature whatsoever under or by reason of this Agreement, and no Person (other than as so specified) shall be deemed a third party beneficiary under or by reason of this Agreement.

9.6    Limited Liability.    Notwithstanding any other provision of this Agreement, no stockholder, director, officer, Affiliate, agent or representative of Southwest, SCP and each Partnership, in its capacity as such, shall have any liability in respect of or relating to the covenants, obligations, representations or warranties of such party under this Agreement or in respect of any certificate delivered with respect hereto or thereto and, to the fullest extent legally permissible, each of Southwest, SCP and the Partnerships, for itself and its stockholders, directors, officers and Affiliates, waives and agrees not to seek to assert or enforce any such liability that any such Person otherwise might have pursuant to applicable law.

9.7    Entire Agreement.    This Agreement constitutes the entire agreement of all the parties hereto and supersedes all prior and contemporaneous agreements and understandings, both written and oral, between the parties, or either of them, with respect to the subject matter hereof.

9.8    Governing Law.    This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware without giving effect to the conflicts of law principles thereof.

9.9    Counterparts.    This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original, but all of which together shall constitute one agreement binding on Southwest and each Partnership, notwithstanding that not all parties are signatories to the original or the same counterpart.

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[Signature page to Agreement and Plan of Merger]

IN WITNESS WHEREOF, each of the parties hereto has executed this Agreement as of the date first written above.

SOUTHWEST CONSOLIDATED PARTNERSHIPS

By:                                                                                                                            

PARTNERSHIPS:

Southwest Oil & Gas Income Fund VII-A, L.P.

Southwest Royalties Institutional Income Fund VII-B, L.P.

Southwest Oil & Gas Income Fund VIII-A, L.P.

Southwest Royalties Institutional Income Fund VIII-B, L.P.

Southwest Oil & Gas Income Fund IX-A, L.P.

Southwest Royalties Institutional Income Fund IX-B, L.P.

Southwest Oil & Gas Income Fund X-A, L.P.

Southwest Royalties Institutional Income Fund X-A, L.P.

Southwest Oil & Gas Income Fund X-B, L.P.

Southwest Royalties Institutional Income Fund X-B, L.P.

Southwest Oil & Gas Income Fund X-C, L.P.

Southwest Royalties Institutional Income Fund X-C, L.P.

Southwest Developmental Drilling Fund 91-A, L.P.

Southwest Developmental Drilling Fund 92-A, L.P.

Southwest Partners, L.P.

Southwest Combination Income/Drilling Program 1988, L.P.

Southwest Developmental Drilling Fund 1990, L.P.

Southwest Developmental Drilling Fund 1993, L.P.

Southwest Developmental Drilling Fund 1994, L.P.

Southwest Royalties, Inc. Income Fund V, L.P.

Southwest Royalties, Inc. Income Fund VI, L.P.

By:     Southwest Royalties, Inc., as the managing general partner of each Partnership

By:                                                                                                               

By:     Southwest Royalties, Inc., as attorney-in-fact for the limited partners of each Partnership

By:                                                                                                            

SOUTHWEST ROYALTIES, INC.

By:                                                                                                                            

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EXHIBIT A

Allocation of SCP Common Stock

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EXHIBIT B

Conversion Procedure

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APPENDIX D

FORM OF AGREEMENT AND PLAN OF MERGER

THIS AGREEMENT AND PLAN OF MERGER dated as of             , 20             (the “Agreement”), is entered into by and among Southwest Royalties, Inc., a Delaware corporation (“Southwest”), Southwest Consolidated Partnerships, Inc., a Delaware corporation (“SCP”), and Southwest Managed Assets, Inc., a Delaware corporation (“SMA”), a wholly-owned subsidiary of Southwest.

RECITALS

A.  The respective boards of directors of SCP and SMA have determined that it is in the best interests of the parties that SCP should merge with and into SMA, and the boards of directors have approved such merger, upon the terms and subject to the conditions contained herein.

B.  Upon consummation of the such merger, the stockholders of SCP will have the right to receive a number of shares of common stock, par value $0.01 per share, of Southwest (the “Southwest Common Stock”).

AGREEMENT

NOW, THEREFORE, in consideration of the representations, warranties, covenants and agreements set forth in this Agreement, and for other good and valuable consideration, the receipt and legal sufficiency of which are hereby acknowledged, the parties, intending to be bound hereby, agree as follows:

ARTICLE I

DEFINITIONS

“Affiliate” shall mean, with respect to any specified Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with, such specified Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” shall mean this Agreement and Plan of Merger, together with all exhibits and schedules attached hereto.

“Approved for Listing” shall mean, with respect to shares of Southwest Common Stock issuable in connection with the Roll-up, that such shares have been approved for listing on the Nasdaq (National Market), subject to official notice of issuance.

“Closing” shall have the meaning specified in Section 2.4.

“Code” shall mean the Internal Revenue Code of 1986, as amended.

“Contract” shall mean any loan or credit agreement, note, bond, indenture, mortgage, deed of trust, lease, franchise, permit, authorization, license, contract, instrument, employee benefit plan or practice or other binding agreement, obligation or commitment.

“DGCL” shall mean the General Corporation Law of the State of Delaware.

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“Effective Time” shall have the meaning specified in Section 2.5.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“GAAP” shall mean United States generally accepted accounting principles as set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board.

“Governmental Authority” shall mean any foreign, federal, state or local court, administrative agency, board, bureau or commission or other governmental department, authority or instrumentality.

“Material Adverse Effect,” with respect to any Person, shall mean a material adverse effect on the business, assets, liabilities, results of operations or condition (financial or otherwise) of such Person and its Subsidiaries, taken as a whole, or on the ability of such Person to perform its obligations hereunder.

“Merger” or “merger” shall mean the merger of SCP with and into SMA.

“Notes” shall mean the 10½% senior notes due 2004 issued by Southwest.

“Person” shall mean a natural person, corporation, company, partnership, limited partnership or other entity, including a Governmental Authority.

“Prospectus/Proxy Statement” has the meaning specified in Section 6.3.

“Roll-up” shall mean, collectively, the merger of 21 limited partnerships (which are identified in that certain merger agreement of even date herewith by and among such limited partnerships and SCP) with and into SCP and the merger of SCP with and into SMA.

“Roll-up Registration Statement” shall mean the Registration Statement on Form S-4 by Southwest pursuant to which Southwest is registering its Southwest Common Stock to be issued in connection with the Roll-up under the Securities Act and the Exchange Act.

“SEC” shall mean the U.S. Securities and Exchange Commission.

“Securities Act” shall mean the Securities Act of 1933, as amended, together with the rules and regulations of the SEC promulgated thereunder.

“Southwest” shall have the meaning specified in the preamble hereof.

“Southwest Common Stock” shall mean the common stock, par value $.01 per share, of Southwest.

“SCP” shall have the meaning specified in the preamble hereof.

“SCP Common Stock” shall mean the common stock, par value $.10 per share, of SCP.

“Subsidiary” shall mean, with respect to any Person, a corporation, partnership or other entity in which such Person, a Subsidiary of such Person or such Person and one or more Subsidiaries of such Person, directly or indirectly, has either (i) a majority ownership in the equity thereof, (ii) the power, under ordinary circumstances, to elect, or to direct the election of, a majority of the board of directors or other governing body of such entity, (iii) the title or function of general partner, or the right to designate the Person having such title or function or (iv) control thereof.

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“Surviving Corporation” shall have the meaning set forth in Section 2.1.

“Termination Date” shall mean the date, if any, on which this Agreement is terminated pursuant to

Section 7.1.

ARTICLE II

THE MERGER

2.1    Merger of the Parties.

(a)    At the Effective Time, SCP shall be merged with and into SMA, in accordance with the terms and conditions hereinafter set forth and in accordance with the DGCL. Thereupon the separate existence of SCP shall cease, and SMA shall continue as the surviving corporation (sometimes referred to herein as the “Surviving Corporation”).

(b)    The certificate of incorporation of SMA before the merger shall be and remain the certificate of incorporation of SMA after the Effective Time, until the same shall thereafter be altered, amended, or repealed in accordance with law and SMA’s certificate of incorporation. The bylaws of SMA as in effect at the Effective Time shall be and remain the bylaws of SMA, as the surviving corporation, until the same shall thereafter be altered, amended, or repealed in accordance with law, SMA’s certificate of incorporation or such bylaws.

(c)    At the Effective Time, each of the persons who was serving as an officer of SMA immediately prior to the Effective Time shall continue to be an officer of SMA and shall continue to serve in such capacity at the pleasure of the board of directors of SMA or, if earlier, until their respective death or resignation. At the Effective Time, each of the persons who was serving as a director of SMA immediately prior to the Effective Time shall continue to be a director of SMA, and each shall serve in such capacity until the next annual meeting of stockholders of SMA and until his or her successor is elected and qualified or, if earlier, until his death, resignation, or removal from office.

2.2    Effect on Shares of SCP.    At the Effective Time, by virtue of the merger of the parties and without any action on the part of SCP, SMA or Southwest, each share of common stock of SCP outstanding immediately prior thereto shall be converted into the right to receive the number of shares of Southwest Common Stock as set forth on Exhibit A attached hereto. Furthermore, Southwest shall reserve in escrow for the benefit of the Persons who are to receive Southwest Common Stock pursuant to this Agreement, shares of Southwest’s Series B Special Stock in such amount as set forth on Exhibit B attached hereto. Such Series B shares shall be convertible into additional shares of Southwest common stock which shall be issued into the escrow and thereafter distributed to the Persons in such amounts as set forth on Exhibit B upon the conversion of Southwest’s Series A Special Stock as further specified in the Prospectus/Proxy Statement.

2.3    Cancellation of Shares of SCP.    Each share of SCP common stock, when converted into the right to receive Southwest Common Stock, shall no longer be outstanding and shall automatically be canceled and retired. Each stockholder shall cease to have any rights with respect thereto, except the right to receive the amount of Southwest Common Stock to be delivered in consideration therefor.

2.4    Closing.    Unless the transactions herein contemplated shall have been abandoned and this Agreement terminated pursuant to Section 8.1, the closing of the merger and the other transactions contemplated hereby (the “Closing”) shall take place at the offices of             at              a.m./p.m., central time, on the date on which the last of the conditions set forth in Article VII is fulfilled or waived (except for those conditions that, by the express terms thereof, are not capable of being satisfied until the Effective Time), or at such other time and place as the parties shall agree in writing.

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2.5    Effective Time of Merger.    Upon satisfaction of the conditions set forth in Article VII hereof and as soon as practicable after the Closing, this Merger Agreement, or a certificate of merger setting forth the information required by, and otherwise in compliance with the DGCL shall be delivered for filing with the Secretary of State of the State of Delaware. The merger shall become effective upon the day and at the time the Secretary of State of the State of Delaware files this Agreement or such certificate of merger in compliance with Section 263 of the DGCL (the time of such effectiveness is herein called the “Effective Time”). Notwithstanding the foregoing, by action of its board of directors, SMA may terminate this Agreement at any time prior to the filing of this Agreement or the certificate of merger with respect to the merger in compliance with Section 263 of the DGCL.

2.6    Closing of Transfer Books.    After the Closing Date, there shall not be any further registration of transfers on the stock ledger of the shares of SCP common stock that were issued and outstanding immediately before the Closing Date and were converted into the right to receive Southwest Common Stock.

2.7    Effect of Merger of Each Partnership.    At the Effective Time of the merger, SMA, without further action, as provided by the laws of the State of Delaware, shall succeed to and possess all the rights, privileges, powers, and franchises, of a public as well as of a private nature, of SCP; and all property, real, personal and mixed, and all debts due on whatsoever account, including subscriptions to shares, and all other choses in action, and all and every other interest of or belonging to or due to SCP shall be deemed to be vested in SMA without further act or deed; and the title to any real estate, or any interest therein, vested in SMA shall not revert or be in any way impaired by reason of the merger. Such transfer to and vesting in SMA shall be deemed to occur by operation of law, and no consent or approval of any other person shall be required in connection with any such transfer or vesting unless such consent or approval is specifically required in the event of merger or consolidation by law or express provision in any contract, agreement, decree, order, or other instrument to which SMA or SCP is a party or by which either of them is bound. At and after the Effective Time, SMA shall be responsible and liable for all debts, liabilities, and duties of SCP, including franchise taxes, if any, which may be enforced against SMA to the same extent as if said debts, liabilities, and duties had been incurred or contracted by it. Neither the rights of creditors nor any liens upon the property of SCP shall be impaired by the merger.

2.8    SMA Common Stock.    At the Effective Time, each outstanding share of common stock of SMA shall remain outstanding and shall continue to represent one share of common stock of SMA.

2.9    Exchange of SCP Common Stock for Southwest Common Stock.

(a)    Exchange Agent.    Prior to the Effective Time, Southwest shall deposit with a bank or trust company (the “Exchange Agent”), for the benefit of the holders of the shares of SCP Common Stock and for exchange in accordance with this Article II, through the Exchange Agent, certificates representing the shares of Southwest Common Stock (such shares of Southwest Common Stock, being hereinafter referred to as the “Exchange Fund”) issuable pursuant to Section 2.2 in exchange for shares of SCP Common Stock. The Exchange Agent shall, pursuant to irrevocable instructions, deliver the Southwest Common Stock contemplated to be issued pursuant to Section 2.2 from the shares of stock held in the Exchange Fund. The Exchange Fund shall not be used for any other purpose.

(b)    Exchange Procedures.    As promptly as practicable after the Effective Time, Southwest shall cause the Exchange Agent to mail or deliver to each Person whose SCP Common Stock was converted pursuant to Section 2.2 into the right to receive shares of Southwest Common Stock a letter of transmittal (which shall be in such form and have such provisions as Southwest and SCP may reasonably specify) which shall confirm the surrender of the SCP Common Stock in exchange for certificates representing the shares of Southwest Common Stock that such holder has received pursuant to this Article II, and the cancellation of the shares of SCP Common Stock so surrendered. The Exchange Agent shall not be entitled to vote or exercise any rights of ownership with respect to the Southwest Common Stock held by it from time to time hereunder, except that it shall receive and hold all dividends or other distributions paid or distributed with respect thereto for the account of persons entitled thereto.

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(c)    No Further Ownership Rights in Partnerships.    All shares of Southwest Common Stock issued upon the surrender for exchange of SCP Common Stock shall be deemed to have been issued in full satisfaction of all rights pertaining to the SCP Common Stock.

(d)    No Fractional Shares.    Notwithstanding anything herein to the contrary, no certificate or scrip representing fractional shares of Southwest Common Stock shall be issued upon the surrender for exchange of shares of SCP Common Stock. All fractional shares of Southwest Common Stock that a holder of SCP Common Stock would otherwise be entitled to receive as a result of the merger shall be aggregated, and if a fractional share results from such aggregation, such holder shall be entitled to receive, in lieu thereof, an amount equal to the nearest whole share of Southwest Common Stock.

(e)    No Liability.    The Surviving Corporation shall not be liable to any holder of SCP Common Stock for shares of Southwest Common Stock delivered to a public official pursuant to any applicable abandoned property, escheat or similar law.

ARTICLE III

REPRESENTATIONS AND WARRANTIES OF SCP

As of the Effective Time, SCP hereby represents and warrants to Southwest and SMA as follows:

3.1    Formation; Qualification.    SCP is a corporation duly formed under the DGCL and is validly existing and in good standing under the laws of the State of Delaware. SCP has all requisite power and authority to own, operate or lease its properties and to carry on its business as now being conducted. SCP is duly qualified to do business as a foreign corporation and is in good standing in each jurisdiction where the character of its properties owned, operated or leased, or the nature of its activities, makes such qualifications necessary.

3.2    Capitalization.    All of the outstanding shares of SCP Common Stock are free of all liens, encumbrances, defects and preemptive rights and are fully paid. There are no outstanding subscriptions, options or other arrangements or commitments obligating SCP to issue any additional shares of common stock.

3.3    No Conflicts.    Assuming this Agreement is approved by the requisite vote of the Stockholders of SCP, consummation of the transactions contemplated hereby and compliance with the terms and provisions of this Agreement will not conflict with, result in a breach of, require notice under or constitute a default under (i) its certificate of incorporation or bylaws, (ii) any material judgment, order, injunction, decree or ruling of any court or governmental authority or (iii) any material agreement, indenture or instrument to which SCP is a party.

3.4    Authority, Authorization and Enforceability.    SCP has all requisite power and authority to enter into and perform the provisions of this Agreement. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary action on the part of SCP other than the approval of its stockholders. Subject to such approval, this Agreement has been duly executed and delivered by SCP and constitutes a valid and binding obligation of SCP enforceable in accordance with its terms.

3.5    Ordinary Course.    Since             ,             , SCP has conducted its operations in the ordinary and usual course of business and has paid all of its obligations as they have become due.

3.6    Accuracy of Information.    None of the information supplied or to be supplied by SCP for inclusion in the Prospectus/Proxy Statement, as amended or supplemented, will, at the time of the mailing of the Prospectus/Proxy Statement or the Closing Date, be false or misleading with respect to any material fact, contain any untrue statement of material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.

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ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SOUTHWEST

Southwest hereby represents and warrants to SCP as follows:

4.1    Organization; Qualification.    Southwest is a corporation duly formed under the DGCL and is validly existing and in good standing under the laws of the State of Delaware. Southwest has all requisite corporate power and authority to own, operate or lease its properties and to carry on its business as now being conducted. Southwest is duly qualified to do business as a foreign corporation and is in good standing in each jurisdiction where the character of its properties owned, operated or leased, or the nature of its activities, makes such qualifications necessary.

4.2    No Conflicts.    Consummation of the transactions contemplated hereby and compliance with the terms and provisions of this Agreement will not conflict with, result in a breach of, require notice under or constitute a default under (i) its certificate of incorporation or bylaws, (ii) any material judgment, order, injunction, decree or ruling of any court or governmental authority or (iii) except as disclosed in the Prospectus/Proxy Statement, any material agreement, indenture or instrument to which Southwest is a party

4.3    Authority, Authorization and Enforceability.    Southwest has all requisite corporate power and authority to execute and deliver this Agreement and to perform the provisions of this Agreement. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of Southwest. This Agreement has been duly executed and delivered by Southwest and constitutes a valid and binding obligation of Southwest enforceable in accordance with its terms.

4.4    SEC Reports; Financial Statements.

(a)    Southwest’s (A) Annual Report on Form 10-K for the year ended             ,              (B) Quarterly Report on Form 10-Q for the quarter ended             ,              , and (C) all other reports or registration statements filed with the SEC since             ,              (collectively, “Southwest’s SEC Reports”) (1) were prepared in accordance with the applicable requirements of the Securities Act and the Exchange Act, and (2) as of their respective dates, did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they are made, not misleading.

(b)    Each of the financial statements of Southwest for the year ended             ,              and for the three months ended             ,              contained in Southwest’s SEC Reports has been prepared in accordance with generally accepted accounting principles applied on a consistent basis throughout the periods involved (except as may be indicated in the notes thereto) and each fairly presents the financial position of Southwest as of the respective dates thereof and the results of operations and cash flows of Southwest for the periods indicated, except that the unaudited interim financial statements are subject to normal and recurring year-end adjustments that are not expected to be material in amount.

4.5    No Material Adverse Change.    Since             , Southwest has conducted its operations in the ordinary and usual course of business and has paid all of its obligations as they have become due; and the business of Southwest has not undergone any material adverse change since such date.

4.6    Accuracy of Information.    None of the information supplied or to be supplied by Southwest for inclusion in the Prospectus/Proxy Statement, as amended or supplemented, will, at the time of the mailing of the Prospectus/Proxy Statement or the Closing Date, be false or misleading with respect to any material fact, contain any untrue statement of material fact or omit to state any material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading.

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ARTICLE V

REPRESENTATIONS AND WARRANTIES OF SMA

SMA hereby represents and warrants to each Partnership as follows:

5.1    Organization; Qualification.    SMA is a corporation duly formed under the DGCL and is validly existing and in good standing under the laws of the State of Delaware. SMA has all requisite corporate power and authority to own, operate or lease its properties and to carry on its business as now being conducted. SMA is duly qualified to do business as a foreign corporation and is in good standing in each jurisdiction where the character of its properties owned, operated or leased, or the nature of its activities, makes such qualifications necessary.

5.2    No Conflicts.    Consummation of the transactions contemplated hereby and compliance with the terms and provisions of this Agreement will not conflict with, result in a breach of, require notice under or constitute a default under (i) its certificate of incorporation or bylaws, (ii) any material judgment, order, injunction, decree or ruling of any court or governmental authority or (iii) any material agreement, indenture or instrument to which SMA is a party.

5.3    Authority, Authorization and Enforceability.    SMA has all requisite corporate power and authority to execute and deliver this Agreement and to perform the provisions of this Agreement. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary corporate action on the part of SMA. This Agreement has been duly executed and delivered by SMA and constitutes a valid and binding obligation of SMA enforceable in accordance with its terms.

5.4    No Material Adverse Change.    Since             , SMA has conducted its operations in the ordinary and usual course of business and has paid all of its obligations as they have become due; and the business of SMA has not undergone any material adverse change since such date.

ARTICLE VI

ADDITIONAL AGREEMENTS

6.1    Conduct of Business Pending the Merger.    Southwest, SCP and SMA covenant and agree that, between the date of this Agreement and the Closing Date, unless the other parties shall otherwise agree in writing or as otherwise contemplated in this Agreement, it shall conduct its businesses only in the ordinary course of business and in a manner consistent with past practice, and it shall not take any action except for actions consistent with such practice. Southwest, SCP and SMA shall each use its reasonable best efforts to preserve intact its business organization, to keep available the services of its present officers, employees and consultants, and to preserve its relationships with customers, suppliers and other persons with which it has significant business dealings.

6.2    Special Meetings; Proxies.    As soon as reasonably practicable after the execution of this Agreement, the parties will take all action necessary to approve this Agreement and the transactions contemplated hereby. The parties will take all other action necessary or advisable to secure any vote or written consent of the stockholders of each party required by this Agreement or applicable law to effect the merger.

6.3    Prospectus/Proxy Statement.    Southwest shall file with the SEC under the Exchange Act a preliminary prospectus/proxy statement with respect to registration and issuance of the Southwest Common Stock as provided therein (the definitive form of such prospectus/proxy statement is referred to as the “Prospectus/Proxy Statement ”). Southwest shall use all reasonable commercial efforts to have the Prospectus/Proxy Statement cleared with the SEC as promptly as practicable.

6.4    Authorization for Shares.    Prior to the Effective Time, Southwest shall have taken all action necessary to permit Southwest to issue the number of shares of Southwest Common Stock required to be issued pursuant to this Agreement.

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6.5    Additional Agreements.    Subject to the terms and conditions herein provided, each of the parties hereto agrees to use all reasonable commercial efforts to obtain in a timely manner all necessary waivers, consents and approvals and to effect all necessary registrations and filings, and to use all reasonable commercial efforts to take, or cause to be taken, all other actions and to do, or cause to be done, all other things necessary, proper or advisable under applicable laws and regulations to consummate and make effective as promptly as practicable the transactions contemplated by this Agreement.

ARTICLE VII

CONDITIONS PRECEDENT TO THE MERGER

7.1    Conditions to Each Party’s Obligations to Effect the Merger.    The respective obligations of each party to effect the merger shall be subject to the fulfillment (or waiver in whole or in part by the intended beneficiary thereof in its sole discretion) at or prior to the Closing Date of the following conditions:

(a)    The parties to the merger having made all filings and registrations with, and notifications to, all third parties, including, without limitation, lenders and all appropriate regulatory authorities, required for consummation of the transactions contemplated by this Agreement (other than the filing and recordation of appropriate merger documents required by the DGCL), and all approvals and authorizations and consents of all third parties, including, without limitation, lenders and all regulatory authorities, required for consummation of the transactions contemplated by this Agreement shall have been received and shall be in full force and effect, except for such filings, registrations, notifications, approvals, authorizations and consents, the failure of which to make or obtain would not have a material adverse effect on the business or financial condition of Southwest, SCP or SMA.

(b)    Either Southwest Royalties, Inc. Income Fund VI, L.P., or Southwest Partners, L.P., shall have approved of some form of merger or combination with Southwest or its subsidiary pursuant to a separate agreement by at least a majority of units of limited partnership interests.

(c)    The Roll-up Registration Statement shall have become effective in accordance with the Securities Act and the Exchange Act and shall not be the subject of any stop order or proceedings seeking a stop order; all necessary permits and authorizations under state securities or Blue Sky laws, the Securities Act and the Exchange Act relating to the issuance and trading of shares of Southwest Common Stock to be issued in connection with the Roll-up shall have been obtained and shall be in effect; and such shares of Southwest Common Stock and such other shares required to be reserved for issuance in connection with the Roll-up shall have been Approved for Listing.

(d)    All consents, approvals and authorizations of any Governmental Authority legally required for the consummation of the transactions contemplated by this Agreement shall have been obtained and be in effect at the Effective Time, except those consents the failure to obtain would not be reasonably likely to have a Material Adverse Effect on Southwest, SCP or SMA.

(e)    No court of competent jurisdiction or other Governmental Authority shall have issued an order, decree, ruling or judgment that is still in effect restraining, enjoining or prohibiting the Roll-up.

(f)    No action, proceeding or investigation by any Governmental Authority with respect to the Roll-up shall be pending that seeks to restrain, enjoin, prohibit or delay consummation of the transactions contemplated by this Agreement or to impose any material restrictions or requirements thereon or on either Southwest, SCP or SMA with respect thereto.

(g)    No action shall have been taken, and no statute, rule, regulation or executive order shall have been enacted, entered, promulgated or enforced by any Governmental Authority with respect to the Roll-up that,

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individually or in the aggregate, would (i) restrain, prohibit or delay the consummation of the Roll-up or (ii) impose material restrictions or requirements thereon or on either Southwest, SCP or SMA with respect thereto.

7.2    Conditions to Obligations of Southwest and SMA to Effect the Merger.    The obligations of Southwest and SMA to effect the merger shall be subject to the fulfillment (or waiver in whole or in part by the intended beneficiary thereof in its sole discretion), at or prior to the Closing Date, of the following additional conditions:

(a)    This Agreement shall have been approved by the stockholders of SCP holding at least seventy-five (75%) of the outstanding common stock of SCP voting by written consent with respect to each merger.

(b)    SCP shall have performed in all material respects its covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time, and the representations and warranties of SCP contained in this Agreement shall be true and correct in all material respects as of the date of this Agreement and as of the Effective Time as if made as of the Effective Time (except to the extent such representations and warranties address matters as of a particular date), except in each case (i) where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest or SMA or (ii) to the extent specifically contemplated or permitted by this Agreement.

(c)    A majority of the holders of the 10½% Senior Notes due 2004, Series B, shall have consented to or waived all applicable provisions of the Indenture, dated October 14, 1997, by and among Southwest, Southwest Royalties Holdings, Inc., as the parent guarantor, and State Street Bank and Trust Company, N.A., as trustee.

7.3    Conditions to Obligations of SCP to Effect the Merger.    The obligations of SCP to effect the merger shall be subject to the fulfillment (or waiver in whole or in part by the intended beneficiary thereof in its sole discretion) at or prior to the Closing Date of the following additional conditions:

(a) Southwest and SMA shall have performed in all material respects its respective covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time and the representations and warranties of Southwest and SMA contained in this Agreement shall be true and correct in all material respects as of the date of this Agreement and as of the Effective Time as if made as of the Effective Time (except to the extent such representations and warranties address matters as of a particular date), except in each case (i) where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on SCP; (ii) to the extent specifically contemplated or permitted by this Agreement;

(b) Southwest and SMA shall have obtained the consent or approval of each Person whose consent or approval shall be required for the consummation of the merger under any Contract, to which Southwest or SMA shall be a party or by which its properties and assets are bound, except (i) where the failure to so obtain such consents and approvals, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on SCP or upon the consummation of the transactions contemplated by this Agreement or (ii) to the extent that alternative arrangements (reasonably acceptable to the SCP) relating to the failure to obtain any such consent or approval are otherwise provided for; and

(c) Notwithstanding the foregoing, the Merger has been approved by the holders of a majority of the outstanding shares of Southwest common stock and Class A common stock, voting together as a single class.

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ARTICLE VIII

TERMINATION

8.1    Termination.    This Agreement may be terminated and the merger contemplated hereby may be abandoned, in whole or in part, at any time prior to the Effective Time, whether before or after approval of the merger of the parties thereto:

(a)    by the mutual consent of each party hereto, which consent shall be effected by action of the Board of Directors of SCP, SMA and Southwest;

(b)    by any party if any court of competent jurisdiction or any other Governmental Authority shall have issued an order, decree, ruling or judgment (other than a temporary restraining order) restraining, enjoining or otherwise prohibiting the Roll-up and such order, decree, ruling or judgment shall have become final and nonappealable, provided that, if the party seeking to terminate this Agreement pursuant to this clause (b) is a party to the applicable proceeding, such party shall have used all commercially reasonable efforts to remove such order, decree, ruling or judgment;

(c)    by SCP with respect to the merger if (i) Southwest or SMA shall have failed to perform in all material respects its respective covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time, or (ii) the respective representations and warranties of Southwest or SMA contained in this Agreement are or shall become untrue in any material respect (except to the extent such representations and warranties address matters as of a particular date), except where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest or SMA;

(d)    by Southwest or SMA if (i) SCP shall not have performed in all material respects its covenants and agreements contained in this Agreement required to be performed at or prior to the Effective Time, or (ii) the representations and warranties of SCP contained in this Agreement are or shall become untrue in any material respect (except to the extent such representations and warranties address matters as of a particular date), except where the failure to be true and correct, individually or in the aggregate, would not be reasonably likely to have a Material Adverse Effect on Southwest, SCP or SMA.

8.2    Effect of Termination.    In the event of termination of this Agreement pursuant to Section 8.1, this Agreement shall terminate, without any liability on the part of any party or its directors, officers or stockholders.

8.3    Amendment.    This Agreement may not be amended except by an instrument in writing signed by Southwest, SCP and SMA.

8.4    Waivers.    At any time prior to the Effective Time, any party may, to the extent legally allowed, (i) extend the time for the performance of any of the obligations or acts of any other party; (ii) waive any inaccuracies in the representations and warranties of the other party contained herein or in any document delivered pursuant to this Agreement and (iii) waive compliance with any of the agreements or conditions of any other party contained herein; provided, however, that no failure or delay by Southwest, SCP or SMA in exercising any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right hereunder. Any agreement on the part of Southwest SMA, or SCP to any such extension or waiver shall be valid only if set forth in an instrument in writing signed on behalf of such party.

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ARTICLE IX

MISCELLANEOUS

9.1    Notices.    All notices and other communications hereunder shall be in writing and shall be deemed given upon (a) a transmitter’s confirmation of a receipt of a facsimile transmission (but only if followed by confirmed delivery of a standard overnight courier the following business day or if delivered by hand the following business day), (b) confirmed delivery of a standard overnight courier or when delivered by hand or (c) the expiration of five business days after the date mailed by certified or registered mail (return receipt requested), postage prepaid, to the parties at the following addresses (or at such other addresses for a party as shall be specified by like notice):

If to SCP to:

Southwest Royalties Holdings, Inc.

407 N. Big Spring

Suite 300

Midland, Texas 79701

Attn: H. H. Wommack, III

If to Southwest or SMA to:

Southwest Royalties, Inc.

407 N. Big Spring

Suite 300

Midland, Texas 79701

Attn: H. H. Wommack, III

with a copy (which shall not constitute effective notice) to:

Baker, Donelson, Bearman & Caldwell

A Professional Corporation

1800 Republic Centre

633 Chestnut Street

Chattanooga, Tennessee 37450-1800

Attention: J. Porter Durham, Jr., Esquire

9.2    Certain Construction Rules.    The article and section headings and the table of contents contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. As used in this Agreement, unless otherwise provided to the contrary, (a) all references to days or months shall be deemed references to calendar days or months and (b) any reference to a “Section,” “Article,” “Exhibit” or “Schedule” shall be deemed to refer to a section or article of this Agreement or an exhibit or schedule to this Agreement. The words “hereof,” “herein” and “hereunder” and words of similar import referring to this Agreement refer to this Agreement as a whole and not to any particular provision of this Agreement. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” Unless otherwise specifically provided for herein, the term “or” shall not be deemed to be exclusive.

9.3    Severability.    If any provision of this Agreement or the application of any such provision to any Person or circumstance, shall be declared judicially to be invalid, unenforceable or void, such decision shall not have the effect of invalidating or voiding the remainder of this Agreement, it being the intent and agreement of Southwest, SCP and SMA that this Agreement shall be deemed amended by modifying such provision to the extent necessary to render it valid, legal and enforceable while preserving its intent or, if such modification is not possible, by substituting therefor another provision that is legal and enforceable and that achieves the same objective.

9.4    Assignment; Binding Effect.    Neither this Agreement nor any of the rights, benefits or obligations hereunder may be assigned by Southwest, SCP or SMA (whether by operation of law or otherwise) without the

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prior written consent of all of the other parties. Subject to the preceding sentence, this Agreement will be binding upon, inure to the benefit of and be enforceable by Southwest, SCP and SMA and their respective successors and permitted assigns.

9.5    No Third Party Beneficiaries.    Nothing in this Agreement, express or implied, is intended to or shall confer upon any Person (other than Southwest, SCP and SMA or their respective successors or permitted assigns) any legal or equitable right, benefit or remedy of any nature whatsoever under or by reason of this Agreement, and no Person (other than as so specified) shall be deemed a third party beneficiary under or by reason of this Agreement.

9.6    Limited Liability.    Notwithstanding any other provision of this Agreement, no stockholder, director, officer, Affiliate, agent or representative of Southwest, SCP and SMA, in its capacity as such, shall have any liability in respect of or relating to the covenants, obligations, representations or warranties of such party under this Agreement or in respect of any certificate delivered with respect hereto or thereto and, to the fullest extent legally permissible, each of Southwest, SCP and SMA, for itself and its stockholders, directors, officers and Affiliates, waives and agrees not to seek to assert or enforce any such liability that any such Person otherwise might have pursuant to applicable law.

9.7    Entire Agreement.    This Agreement constitutes the entire agreement of all the parties hereto and supersedes all prior and contemporaneous agreements and understandings, both written and oral, between the parties, or either of them, with respect to the subject matter hereof.

9.8    Governing Law.    This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware without giving effect to the conflicts of law principles thereof.

9.9    Counterparts.    This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original, but all of which together shall constitute one agreement binding on the parties, notwithstanding that not all parties are signatories to the original or the same counterpart.

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[Signature page to Agreement and Plan of Merger]

IN WITNESS WHEREOF, each of the parties hereto has executed this Agreement as of the date first written above.

SOUTHWEST CONSOLIDATED PARTNERSHIPS, INC.

By:                                                                                                                            

Its:                                                                                                                           

SOUTHWEST MANAGED ASSETS, INC.

By:                                                                                                                            

Its:                                                                                                                            

SOUTHWEST ROYALTIES, INC.

By:                                                                                                                            

Its:                                                                                                                            

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EXHIBIT A

Conversion to Southwest Common Stock

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EXHIBIT B

Series B Shares

D-15

APPENDIX E

[Date]

Board of Directors of Southwest Royalties, Inc.

Managing General Partner of the Partnerships Identified in Exhibit I

407 North Big Spring, Suite 300

Midland, Texas 79701

Gentlemen:

Southwest Royalties, Inc. (“Southwest”), the managing general partner of the partnerships identified in Exhibit I attached hereto (“the Partnerships”), has advised us that Southwest and the Partnerships are contemplating a transaction (the “Transaction”) pursuant to an agreement (the “Merger Agreement”) in which each Partnership will merge with and into Southwest Managed Assets, Inc., a wholly-owned subsidiary of Southwest, and the partner interests owned by the limited partners (the “Limited Partners”) in each Partnership will be exchanged for shares of common and special stock of Southwest. The number of common and special shares of Southwest to be allocated to each Partnership in connection with the Transaction will be determined by a relative net asset value (“NAV”) formula. Specifically, the NAV of Southwest and each Partnership will be calculated for the purpose of determining each party’s respective ownership interest in Southwest upon completion of the Transaction. The NAV of Southwest and each Partnership will be determined by calculating the value of Southwest’s and each Partnership’s oil and gas reserves (the “Reserve Value”) as of July 1, 2002, and the net working capital (the “Working Capital Balance”) as of June 30, 2002. The Reserve Value, the Working Capital Balance and the net book value of any non-oil and gas assets will be summed for Southwest and each of the Partnerships, and then any debt owed by Southwest or the applicable Partnership will be subtracted in order to arrive at the NAV for each entity. In addition, the limited partner interests and general partner interests of Southwest in each Partnership will be subtracted from the NAV of each Partnership and added to the NAV of Southwest in order to arrive at an adjusted NAV for each entity. Southwest will bear the cost of all merger-related expenses and this amount will be deducted from Southwest’s calculated NAV to determine Southwest’s Merger Value. These adjusted NAVs will represent the merger value (the “Merger Value”) of Southwest and of each Partnership. We have been advised that the Merger Value will be allocated and distributed in the form of Southwest common and special shares to the partners of the Partnerships in accordance with the provisions of each partnership agreement.

We have been further advised that the Reserve Value has been established by Southwest based upon the present value of estimated future net revenues (after certain expenses and charges) from each Partnership’s proved oil and gas reserves as of July 1, 2002, utilizing NYMEX prices for 2002, 2003, 2004, 2005, 2006 and thereafter of $26.46, $24.74, $23.30, $22.44 and $21.84 per barrel of oil and $3.42, $3.86, $3.96, $3.99 and $4.02 per thousand cubic feet of gas, and a discount rate of 10% for proved developed producing reserves, 15% for proved non-producing reserves and 20% for proved undeveloped reserves. We have been further advised that the Reserve Value is based upon the reserve report audited by Ryder Scott Company, L.P. (“Ryder Scott”), an independent petroleum engineering and consulting firm, as of January 1, 2002 (based on U.S. Securities and Exchange Commission Regulation S-X Article 4 – Rules of General Application, Reg. 210.4-10, hereafter “Regulation S-X 4-10”), and recalculated by Southwest using the forecasted production curve in effect as of July 1, 2002 and the aforementioned prices (the “Reserve Analysis”).

We have been advised that the Limited Partners in each Partnership will have the opportunity to approve or reject the participation by their Partnership in the Transaction pursuant to a proxy statement/prospectus (the “Proxy Statement/Prospectus”) and a Limited Partners meeting which will be prepared and held, respectively, in connection with the Transaction.

You have requested that Friedman Billings Ramsey & Co., Inc. (“FBR”) provide an opinion as to the fairness from a financial point of view of the Merger Value ascribed to each Partnership and the allocation thereof in the form of Southwest common and special stock to: (i) the Limited Partners of each Partnership, including all possible combinations of the Partnerships; and (ii) Southwest as the managing general partner of each Partnership.

Board of Directors of Southwest Royalties, Inc.

Managing General Partner of the Partnerships Identified in Exhibit I

[Date]

Page 2

Founded in 1989, FBR is a NYSE listed, international investment banking firm with offices across the United States and Europe. FBR has provided research, institutional sales and trading, investment banking, asset management and private client financial services to clients located throughout the United States and Europe. FBR’s investment banking activities include M&A advisory and fairness opinion services, initial public offerings, secondary and follow-on public offerings, private placements, venture capital and industry and company research and analysis. FBR focuses its investment banking practice on six industry sectors: Financial Services, Real Estate, Technology, Energy, Diversified Industries and Healthcare. FBR, as part of its investment banking business, is regularly engaged in the valuation of securities in connection with mergers, acquisitions, and reorganizations and for corporate and other transactional purposes.

During the past two years, Southwest has engaged FBR to render financial advisory services in connection with various proposed transactions other than the Transaction, some of which closed and some of which were never consummated. Principally, by means of an engagement letter dated October 31, 2001, as amended December 31, 2001 and as further amended April 4, 2002 (the “Prior Engagement Letter”), Southwest engaged FBR to provide financial advisory services in connection with the offer commencing March 5, 2002 for $123.685 million in aggregate principal amount of outstanding Southwest 10½% Senior Notes in exchange for $60 million principal amount of Senior Secured Notes and 900,000 shares of Southwest’s Class A common stock, which offer expired April 19, 2002 (the “Recapitalization”). Pursuant to the terms of the Prior Engagement Letter, FBR was specifically not retained to provide financial advisory services for or provide any analysis or opinion concerning the Transaction. FBR was paid a total of $1,750,000 in connection with services provided pursuant to the Prior Engagement Letter and other services, all of which were provided prior to FBR’s engagement to provide a fairness opinion for the Transaction. The term of the Prior Engagement Letter is scheduled to expire on October 19, 2002; however, FBR may in the future seek to earn additional fees from Southwest by providing investment banking services.

In arriving at the opinion set forth below, we have:

· Reviewed the Preliminary Proxy Statement/Prospectus;

· Reviewed a draft of the Merger Agreement, which Southwest has indicated to be in substantially the form that will be executed in connection with the Transaction;

· Reviewed financial statements of each Partnership for the three and six months ended March 31, 2002 and June 30, 2002 and for the years ended December 31, 2001 and 2000. Where applicable, the Partnership’s Forms 10-Q and Forms 10-K were reviewed for the same time periods;

· Reviewed the Reserve Analyses of each Partnership and Southwest prepared by Southwest as of July 1, 2002;

· Reviewed the Reserve Analyses of each Partnership and Southwest audited by Ryder Scott in accordance with Regulation S-X 4-10 as of December 31, 2001;

· Reviewed the calculations prepared by Southwest of the Merger Value per $500 original investment in each Partnership;

· Reviewed information provided by Southwest regarding other alternatives to the merger of each Partnership;

· Reviewed information provided by Southwest to be used in the development of the Going Concern Value, Liquidation Value and Right of Presentment Value per $500 original investment in each Partnership;

· Interviewed key management personnel of Southwest regarding the oil and gas reserves, the financial condition of each Partnership and the terms of the Transaction;

Board of Directors of Southwest Royalties, Inc.

Managing General Partner of the Partnerships Identified in Exhibit I

[Date]

Page 3

· Reviewed, in the context of the Transaction, the terms and conditions of the Recapitalization;

· Reviewed the financial statements of Southwest for the three months ended March 31, 2002, the five months ended May 31, 2002, the six months ended June 30, 2002, and the twelve months ended December 31, 2002. Also reviewed were Southwest’s Form 10-K for the years ended December 31, 2000 and 1999;

· Reviewed pro forma financial data for Southwest assuming the completion of the Transaction with full participation of the Partnerships;

· Reviewed recent secondary market trading activity for interests in the Partnerships, if available;

· Investigated any reported solicited or unsolicited tender offers for interests in any of the Partnerships; and

· Conducted such other studies, analyses, inquiries and investigations as we deemed appropriate.

In rendering this opinion, we have relied, without independent verification, on the completeness in all material respects of all financial and other information (including the partnership agreements) that was furnished or otherwise communicated to us by Southwest and the Partnerships. We have been advised by Southwest that the oil and gas properties owned by the Partnerships are subject to operating agreements (the “Operating Agreements”) with Southwest and other third parties and that: (i) such Operating Agreements provide for the payment of overhead charges and that such charges are reasonable and consistent when compared to amounts charged for similar services by other oil and gas operators in the general operating region where the Partnership assets are located; (ii) except for cause, such Operating Agreements do not provide for the termination of Southwest or other third parties as operator; and (iii) such Operating Agreements do not provide for the revision of overhead charges, except as escalated under the terms of such Operating Agreements. Furthermore, we have been advised by Southwest that if each Partnership’s reserves were offered for sale to a third party, a condition of such sale would be that the oil and gas reserves would continue to be subject to the Operating Agreements which provide for the payment of overhead charges, and that it would be appropriate to assume, when estimating the value of such reserves, that such charges would continue to burden the economic value of the Partnership’s oil and gas assets.

We have not performed an independent appraisal of the oil and gas reserves or other assets and liabilities of the Partnerships. We have not conducted any engineering studies and have relied on estimates of Ryder Scott and Southwest with respect to oil and gas reserve volumes, and of Southwest with respect to prices, operating costs, and overhead charges.

We have relied on the assurance of Southwest and each Partnership that: (i) the Reserve Analysis provided to us was in the judgment of Southwest and the Partnerships reasonably prepared on bases consistent with actual historical experience and reflect their best currently available estimates and good faith judgments; (ii) there are no estimates of costs to remediate environmental conditions included in the Reserve Analysis; (iii) any historical financial data, balance sheet data, transaction cost estimates, Merger, Going Concern, Liquidation and Right of Presentment Value information provided by Southwest is complete in all material respects; (iv) all allocations included within the calculations of Merger Values, Going Concern Values, Liquidation Values and Right of Presentment Values have been made in accordance with the Partnership Agreement for each Partnership, and that such allocations do not differ regardless of whether made on the basis of revenue-sharing or liquidation provisions in the partnership agreements; (v) no material changes have occurred in the information reviewed or in the value of the oil and gas reserves as of July 1, 2002 or the balance sheets as of June 30, 2002 of each Partnership between the date the information was provided to us and the date of this letter; (vi) the relative ownership interest of the Limited Partners and Southwest as the general partner of each Partnership is accurately included in accordance with the applicable partnership agreement in all analyses provided to us by Southwest,

Board of Directors of Southwest Royalties, Inc.

Managing General Partner of the Partnerships Identified in Exhibit I

[Date]

Page 4

and that Mr. H. H. Wommack, III will, prior to the consummation of the Transaction, transfer his 1% general partnership interest in certain Partnerships to Southwest for no consideration; (vii) there is no information regarding Southwest or any of the Partnerships that would materially impact the oil and gas properties, the Reserve Analysis or the balance sheets of Southwest and each Partnership or that would cause the information supplied to us to be incomplete or misleading in any material respect.

We have not been requested to, and therefore did not: (i) make any recommendation to Southwest, the Partnerships or the Limited Partners with respect to whether to approve or reject the Transaction; (ii) determine or negotiate the amount or form of the Merger Value for any Partnership to be paid for the interests of any Limited Partner in the Transaction; or (iii) offer the assets of any Partnership for sale to any third party.

FBR further states that it did not express any opinion as to: (i) the financial impact on Southwest or any of the Partnerships that do not participate in the Transaction; (ii) the tax consequences of the Transaction for Southwest, the Partnerships or the Limited Partners of any of the Partnerships;(iii) the impact upon the value of Partnerships’ reserves if the oil and gas assets were operated under operating agreements with terms different from the agreements presently in place; (iv) the impact upon the value of the Partnerships if they were administered in accordance with partnership agreements having terms different from those agreements presently governing the Partnerships; (v) the value of the Partnerships or the Partnerships’ assets if they were managed and/or operated by a party other than Southwest; (vi) whether or not alternative methods of determining the Merger Value for each Partnership were plausible and whether or not such alternative methods would have also provided fair results or results substantially similar to the methodology used; (vii) alternatives to the Transaction, including the offering of such assets for sale to third-party buyers; (viii) the value of the shares of Southwest common stock and special stock or the market performance of Southwest common stock if they were to ever become publicly registered and listed for trading on an organized exchange; (ix) the financial condition of Southwest or any of the Partnerships, including solvency and liquidity matters; or (x) any other terms of the Transaction.

FBR strongly encourages that Partnership unit holders consider the amount of Southwest’s indebtedness and the timing of the maturity of such indebtedness in making a decision whether or not to vote in favor of the Transaction. As of June 30, 2002, Southwest had $123.825 million of debt principal payments due in 2004. Specifically, $55.0 million of principal is due under the Revolving Credit Agreement maturing on April 30, 2004, $60.0 million of principal is due under the Variable Interest Senior Notes maturing June 20, 2004 and $8.825 million of principal is due under the 10.5% Senior Notes maturing October 15, 2004. There is no guarantee that Southwest will be able to either fund these principal repayments from internally generated cash flow or refinance these amounts when they become due. Partnership unit holders voting in favor of the Transaction should also be aware that the aforementioned indebtedness has a claim against the assets of Southwest that is superior to that of holders of Southwest’s special or common shares. FBR has not expressed any opinion on the financial condition of Southwest or of any of the Partnerships.

This letter does not purport to be a complete description of the analyses performed or the matters considered in rendering this opinion. The analyses and the summary set forth herein must be considered as a whole, and selecting portions of such summary or analyses without considering all factors and analyses would create an incomplete view of the process underlying this opinion. In rendering this opinion, judgment was applied to a variety of complex analyses and assumptions. The assumptions made and the judgments applied in rendering the opinion are not readily susceptible to partial analysis or summary description. The fact that any specific analysis is referred to herein is not meant to indicate that such analysis was given greater weight than any other analyses.

Our opinion is based on business, economic, oil and gas market, and other conditions as of the date of our analysis and addresses the Merger Value in the context of information available as of the date of our analysis. Events occurring after that date could affect the value of the assets of the Partnerships or the assumptions used in preparing this opinion.

Board of Directors of Southwest Royalties, Inc.

Managing General Partner of the Partnerships Identified in Exhibit I

[Date]

Page 5

Based upon and subject to the foregoing, it is our opinion that, as of the date of this letter and subject to the assumptions, limitations and qualifications contained herein, the Merger Value ascribed to each Partnership in connection with the Transaction and the allocation thereof in the form of Southwest common and special stock to: (i) the Limited Partners of each Partnership, including all possible combinations of the Partnerships; and (ii) Southwest as the managing general partner of each Partnership is fair, from a financial point of view, to the Limited Partners of each Partnership and to Southwest as the general partner of each Partnership.

Yours truly,

Friedman, Billings, Ramsey & Co., Inc.

Exhibit I

List of Subject Partnerships:

1.	Southwest Royalties, Inc. Income Fund V, LP
2.	Southwest Royalties, Inc. Income Fund VI, LP
3.	Southwest Oil & Gas Income Fund VII-A, LP
4.	Southwest Royalties Institutional Income Fund VII-B, LP
5.	Southwest Oil & Gas Income Fund VIII-A, LP
6.	Southwest Royalties Institutional Income Fund VIII-B, LP
7.	Southwest Oil & Gas Income Fund IX-A, LP
8.	Southwest Royalties Institutional Income Fund IX-B, LP
9.	Southwest Oil & Gas Income Fund X-A, LP
10.	Southwest Royalties Institutional Income Fund X-A, LP
11.	Southwest Oil & Gas Income Fund X-B, LP
12.	Southwest Royalties Institutional Income Fund X-B, LP
13.	Southwest Oil & Gas Income Fund X-C, LP
14.	Southwest Royalties Institutional Income Fund X-C, LP
15.	Southwest Developmental Drilling Fund 1990, LP
16.	Southwest Developmental Drilling Fund 91-A, LP
17.	Southwest Developmental Drilling Fund 92-A, LP
18.	Southwest Developmental Drilling Fund 1993, LP
19.	Southwest Developmental Drilling Fund 1994, LP
20.	Southwest Partners, LP
21.	Southwest Combination Income/Drilling Program 1988, LP

6

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES, INC. INCOME FUND V, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties, Inc. Income Fund V, L.P., which we call Income Fund V, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Income Fund V. The purpose of the special meeting is for you to vote upon the merger of Income Fund V with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Income Fund V is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Income Fund V:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Income Fund V

• Compensation and distributions from Income Fund V

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial data and operating data for Income Fund V for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Income Fund V’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001 and 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Income Fund V as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Income Fund V, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Income Fund V in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not incorrect, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Income Fund V’s assets. The Merger Value of Income Fund V is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Income Fund V, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger, and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Income Fund V by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Income Fund V. We believe, however, that Income Fund V will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Income Fund V. Our decision is based on the following factors in order of significance:

• Our method of valuation for Income Fund V uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Income Fund V, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the going concern value, the liquidation value and the final presentment value of Income Fund V. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

[Explain higher net book value here] For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INCOME FUND V

The Merger Value for Income Fund V was determined by calculating its Net Asset Value and then dividing Income Fund V’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Income Fund V’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Income Fund V’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Income Fund V. As indicated below, the number of shares of common stock issuable per unit of limited partner interest in Income Fund V is 2.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Income Fund V
		Net Present Value of Reserves	$	917,495.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	45,608.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Income Fund V	$	963,103.00	calculated

3

					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Income Fund V	$	963,103.00	calculated
	less	GP % owned by Southwest in Income Fund V (10%)	$	96,310.30	Partnership records
	less	LP % owned by Southwest in Income Fund V (34.18%)	$	329,188.61	Partnership records
	equals	Net Asset Value of Income Fund V owned by limited partners (excluding Southwest’s ownership %)	$	537,604.09	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Income Fund V (excluding Southwest’s ownership %)	$	537,604.09	calculated
	equals	The percentage of ownership of Income Fund V (other than Southwest) to the total Net Asset Value		0.68%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Income Fund V (other than Southwest)		0.68%	calculated
	equals	The number of shares of common stock attributable to Income Fund V (other than to Southwest)		11,562.53	calculated
(7)		The number of shares of common stock attributable to Income Fund V (other than to Southwest)		11,563	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Income Fund V		4,651	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Income Fund V		2	calculated

4

				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Income Fund V (other than to Southwest)	2,313	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Income Fund V	4,651	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Income Fund V	.50	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK— Series B Special Stock to be Issued in the Merger” in the proxy statement/prospectus. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Income Fund V for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	109,200	$	109,200	$	109,200	$	54,600
Administrative Overhead per Operating Agreements	$	96,495	$	100,649	$	92,217	$	52,879
Cash Distributions Paid to General Partners as General Partners(1)	$	22,500	$	25,000	$	5,000	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	60,575	$	63,084	$	9,983	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Income Fund V’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	202,500	$	225,000	$	45,000	$	94,050	$	322,200	$	—
Return of Capital: 94%

⁽¹⁾ Because of depletion (which is usually greater in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

5

SUPPLEMENTAL INFORMATION TABLE FOR INCOME FUND V

Aggregate Initial Investment by the Limited Partners:	$	7,499	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	7,061	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	867	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	57.79	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		0	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	64.42	(2)(4)
—as of December 31, 2001:	$	66.30	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	40.04	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	40.38	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	48.28	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Income Fund V is equal to (1) the sum of (A) the present value of estimated future net revenues from Income Fund V’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Income Fund V is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Income Fund V is based upon (1) the sum of (A) the estimated net cash flow from the sale of Income Fund V’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Income Fund V’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Income Fund V is based upon (1) the sum of (A) the sale of Income Fund V’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Income Fund V’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Income Fund V and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Income Fund V is based upon (1) the sum of (A) Income Fund V’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Income Fund V.

6

INCOME FUND V

Set forth below is basic information about Income Fund V and its business and operations. It does not contain all the information about Income Fund V that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Income Fund V

General

Income Fund V was organized as a Tennessee limited partnership on May 1, 1986, after receipt from limited partners of $1 million in capital contributions. The offering of limited partner interests began January 22, 1986, reached minimum capital requirements on May 1, 1986 and concluded July 22, 1986, with total limited partner contributions of $7.5 million.

Principal Products, Marketing and Distribution

Income Fund V has acquired and holds royalty interests and net profit interests in oil and gas properties located in Texas and Oklahoma.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	48%	52%
2000	53%	47%
1999	56%	44%

As the table indicates, Income Fund V’s revenue is almost evenly divided between its oil and gas production.

Customer Dependence

No material portion of Income Fund V’s business is dependent on a single purchaser, or very few purchasers, where the loss of one would have a material adverse impact on Income Fund V. Three purchasers accounted for 77% of Income Fund V’s total oil and gas production during 2001: Duke Energy Field Services for 33%, Plain All American Pipeline, L.P. for 28% and Sid Richardson Energy Services for 16%. Three purchasers accounted for 76% of Income Fund V’s total oil and gas production during 2000: Phillips 66 Company for 34%, Plain All American Pipeline, L.P. for 32% and Vintage Petroleum, Inc. for 10%. Three purchasers accounted for 64% of Income Fund V’s total oil and gas production during 1999: Scurlock Permian LLC for 28%, Phillips 66 Company for 26% and Vintage Petroleum Inc. for 10%. All purchasers of Income Fund V’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Income Fund V’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Income Fund V’s sales of oil and gas production.

Properties

As of December 31, 2001, Income Fund V possessed an interest in oil and gas properties located in Pottawatomie County, Oklahoma; and Crane, Dawson, Midland, Ward, Winkler and Upton Counties, Texas. These properties consist of various interests in approximately 59 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999 other than ordinary production declines and reserve depletion.

7

Significant Properties

The following table reflects the significant properties in which Income Fund V has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Reserves*
			Oil (Bbls)	Gas (Mcf)
Damson-Rhoda Walker Ward County, Texas	12/86 at 44% to 100% net profits interest	7	13,000	53,000
Devonian Midland County, Texas	5/86 at 28% to 100% net profits interests	1	4,000	73,000
Mewbourne Crane County, Texas	1/87 at 50% to 100% net profits interest	7	17,000	99,000
Walton Acquisition Winkler County, Texas	12/86 at 22.5% to 40% net profits interest	6	—	93,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Income Fund V’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.85 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.70 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INCOME FUND V” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Income Fund V. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Income Fund V has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Income Fund V’s present reserves.

Because Income Fund V does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Income Fund V retains a carried interest under the terms of a farm-out or receives cash.

8

Income Fund V, or the owners of properties in which Income Fund V owns an interest, can engage in workover projects or supplementary recovery projects to extract behind the pipe reserves which, qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INCOME FUND V” of this prospectus supplement.

Market for Income Fund V’s Limited Partnership Interests and Related Matters

Market Information

After completion of Income Fund V’s first full fiscal year of operations and each year thereafter, the managing general partner has offered, and will continue to offer, to purchase each limited partner’s interest in Income Fund V, at a price based on tangible assets of Income Fund V, plus the net present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented at the sole discretion of the managing general partner. However, the managing general partner’s obligation to purchase limited partner interests is limited to an expenditure of an amount not to exceed 10% of the total limited partner interest initially subscribed for by partners. In 2001, 613.5 units of limited partner interest were offered to and purchased by the managing general partner at an average base price of $350.53 per unit. In 2000, 605.9 units of limited partner interest were offered to and purchased by the managing general partner at an average base price of $116.72 per unit. In 1999, 167.7 units of limited partner interest were offered to and purchased by the managing general partner at an average base price of $51.12 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 559 holders of limited partner interest in Income Fund V.

Distributions

Pursuant to Article IV, Section 4.01 of Income Fund V’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Income Fund V’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Income Fund V], as determined at the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $225,000, with $202,500 distributed to the limited partners and $22,500 to the general partners. For the year ended December 31, 2001, distributions of $27.00 per unit of limited partner interest were made, based upon 7,499 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $250,000, with $225,000 distributed to the limited partners and $25,000 distributed to the general partners. For the year ended December 31, 2000, distributions of $30.00 per unit of limited partner interest were made, based upon 7,499 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $50,000, with $45,000 distributed to the partners and $5,000 to the general partners. For the year ended December 31, 1999, distributions of $6.00 per unit of limited partner interest were made, based upon 7,499 units of limited partner interest outstanding.

9

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR INCOME FUND V

The following table presents summary selected financial information and operating data for Income Fund V for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INCOME FUND V” found elsewhere in this prospectus supplement and the financial statements and related notes for Income Fund V included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operating Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	250,056		532,028		767,101		972,133		690,967		600,412		1,034,406
Net income (loss)	(31,210	)	199,617		33,430		254,351		117,488		(724,042	)	102,274
Partners’ share of net income (loss):
General partners	(3,121	)	19,962		3,343		25,435		11,749		(72,404	)	10,228
Partners	(28,089	)	179,655		30,087		228,916		105,739		(651,638	)	92,046
Partners’ net income (loss) per unit of limited partner interest	(3.75	)	23.96		4.01		30.53		14.10		(86.90	)	12.27
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	(56,817	)	224,345		246,460		248,866		81,679		112,557		346,236
Net cash provided by investing activities	—		—		—		—		—		—		—
Net cash used in financing activities	—		(225,154	)	(225,492	)	(249,883	)	(50,125	)	(104,190	)	(358,198	)
Net increase (decrease) in cash and cash equivalents	(56,817	)	(809	)	20,968		(1,017	)	31,554		8,367		(11,962	)
EBITDA	(13,210	)	233,617		125,430		276,351		161,488		(2,762	)	279,274
Cash distributions	—		225,000		225,000		250,000		50,000		104,500		358,000
Partners’ cash distributions per $500 investment	—		13.50		13.50		15.00		3.00		6.27		21.48
Balance Sheet Data:
Cash and cash equivalents	7,473		42,513		64,290		43,322		44,339		12,785		4,418
Oil and gas properties, net at book value	276,638		352,638		294,638		386,638		408,638		452,638		1,173,918
Total assets	322,247		519,678		359,232		545,215		540,747		473,384		1,301,730
Total liabilities	—		34		5,775		188		71		196		—
Partners’ equity	966,215		1,143,872		994,304		1,166,717		1,162,801		1,102,062		1,847,750
General partners’ equity	(643,968	)	(624,228	)	(640,847	)	(621,690	)	(622,125	)	(628,874	)	(546,020	)
Partner’s book value per $50 investment	64.42		76.27		66.30		77.79		77.53		73.48		123.20

10

	Six months ended June 30,			Years ended December 31,
	2002		2001	2001	2000	1999	1998		1997
Production:
Oil production (Bbls)	6,150		9,300	14,900	17,600	22,110	25,000		33,300
Natural gas production (Mcf)	40,300		49,100	94,200	100,600	124,650	141,800		159,600
Equivalent production (Boe)	12,867		17,483	30,600	34,367	42,885	48,633		59,900
Average Sales Price:
Oil price (per/Bbl)	22.54		27.60	24.75	29.18	17.60	12.97		19.51
Natural gas price (per/Mcf)	2.76		5.61	4.23	4.56	2.42	1.95		2.41
Average sales price (per Boe)	19.43		30.43	25.07	28.29	16.11	12.35		17.27
Operating and Overhead Costs (per Boe)
Lease operating expense	15.19		12.21	15.89	15.39	8.82	9.17		10.31
Production taxes	.97		1.67	1.38	1.53	.80	.65		.39
General and Administrative Expense (per Boe)	4.56		3.28	3.77	3.42	2.75	2.60		1.97
Total	20.72		17.16	21.04	20.34	12.37	12.42		12.67
Cash Operating Margin (per Boe)	(1.29	)	13.27	4.03	7.95	3.74	(.07	)	4.60
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.40		1.94	3.01	.64	1.03	14.84		2.95
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	545,000		792,000	364,000	1,218,000	1,180,000	531,000		1,361,000
Oil (Bbls)	78,000		115,000	46,000	163,000	159,000	78,000		212,000
Total (Boe)	169,000		247,000	107,000	366,000	355,000	167,000		439,000

⁽¹⁾ Income Fund V has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	963,000
Merger Value per $500 investment	$	57.79

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

11

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR INCOME FUND V

General

Developmental drilling and workovers may be performed to increase production in the years 2002 and 2003. Income Fund V may have a slight increase in production volumes for the years 2002 and 2003, but thereafter, Income Fund V will likely experience the historical production decline of 11% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.98	$	27.01	(8	%)
Average price per Mcf of gas	$	3.33	$	4.63	(28	%)
Oil production in barrels		2,850		4,600	(38	%)
Gas production in Mcf		19,600		25,700	(24	%)
Income from net profits interests	$	45,540	$	119,795	(62	%)
Income Fund V distributions	$	—	$	100,000	(100	%)
Limited partner distributions	$	—	$	90,000	(100	%)
Per unit distribution to limited partners	$	—	$	12.00	(100	%)
Numbers of limited partner interests		7,499		7,499

Revenues

Income Fund V’s income from net profits interests decreased to $45,540 from $119,795 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 62%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Income Fund V decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 8%, or $2.03 per barrel, resulting in a decrease of approximately $5,800 in income from net profits interests. Oil sales represented 52% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 51% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Income Fund V decreased by 28%, or $1.30 per Mcf, resulting in a decrease of approximately $25,500 in income from net profits interest.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $31,300. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,750 barrels, or 38%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $47,300 in income from net profits interests.

Gas production decreased approximately 6,100 Mcf, or 24%, during the same period, resulting in a decrease of approximately $28,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $75,500. The decrease in production is due to several small wells having a sharp natural decline.

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3.  Lease operating costs and production taxes decreased 32%, or approximately $43,100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in lease operating expense is due to maintenance and repairs on one lease performed during the quarter ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $38,582 from $50,779 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 24%. The decrease is the result of lower depletion expense, partially offset by an increase in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $800, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $9,000 for the quarter ended June 30, 2002, from $22,000 for the same period in 2001. This represents a decrease of 59%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund V’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Income Fund V during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.54	$	27.60	(18	%)
Average price per Mcf of gas	$	2.76	$	5.61	(51	%)
Oil production in barrels		6,150		9,300	(34	%)
Gas production in Mcf		40,300		49,100	(18	%)
Income from net profits interests	$	42,118	$	289,275	(85	%)
Income Fund V distributions	$	—	$	225,000	(100	%)
Limited partner distributions	$	—	$	202,500	(100	%)
Per unit distribution to limited partners	$	—	$	27.00	(100	%)
Numbers of limited partner interests		7,499		7,499

Revenues

Income Fund V’s income from net profits interests decreased to $42,118 from $289,275 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 85%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Income Fund V decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $5.06 per barrel, resulting in a decrease of approximately $31,100 in income from net profits interests. Oil sales represented 55% of total oil and gas sales during the six months ended June 30, 2002 as compared to 48% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Income Fund V decreased during the same period by 51%, or $2.85 per Mcf, resulting in a decrease of approximately $114,900 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $146,000. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

13

2.  Oil production decreased approximately 3,150 barrels, or 34%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $86,900 in income from net profits interests.

Gas production decreased approximately 8,800 Mcf, or 18%, during the same period, resulting in a decrease of approximately $49,400 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $136,300. The decrease in oil production is due primarily to downtime on one lease during the six months ended June 30, 2002. The decrease in gas production is due to several small wells having a sharp natural decline.

3.  Lease operating costs and production taxes decreased 14%, or approximately $34,800, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $76,650 from $91,309 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 16%. The decrease is the result of lower depletion expense, partially offset by an increase in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $1,300, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $18,000 for the six months ended June 30, 2002 from $34,000 for the same period in 2001. This represents a decrease of 47%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund V’s independent petroleum consultants and updated by Southwest’s internal staff of engineers The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Income Fund V during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	24.75	$	29.18	(15	%)
Average price per Mcf of gas	$	4.23	$	4.56	(7	%)
Oil production in barrels		14,900		17,600	(15	%)
Gas production in Mcf		94,200		100,600	(6	%)
Income from net profits interests	$	238,680	$	390,786	(39	%)
Income Fund V distributions	$	225,000	$	250,000	(10	%)
Limited partner distributions	$	202,500	$	225,000	(10	%)
Per unit distribution to limited partners	$	27.00	$	30.00	(10	%)
Number of limited partner interests		7,499		7,499

14

Revenues

Income Fund V’s income from net profits interests decreased to $238,680 from $390,786 for the years ended December 31, 2001 and 2000, respectively, a decrease of 39%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Income Fund V decreased during the years ended December 31, 2001 as compared to the years ended December 31, 2000 by 15%, or $4.43 per barrel, resulting in a decrease of approximately $66,000 in income from net profits interests. Oil sales represented 48% of total oil and gas sales during the years ended December 31, 2001 as compared to 53% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Income Fund V increased during the same period by 7%, or $.33 per Mcf, resulting in a decrease of approximately $31,100 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $97,100. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 2,700 barrels, or 15%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $78,800 in income from net profits interests.

Gas production decreased approximately 6,400 Mcf, or 6%, during the same period, resulting in a decrease of approximately $29,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $108,000.

3.  Lease operating costs and production taxes decreased 9%, or approximately $52,900, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

Costs and Expenses

Total costs and expenses increased to $207,459 from $139,537 for the years ended December 31, 2001 and 2000, respectively, an increase of 49%. The increase is the result of higher depletion expense, partially offset by a decrease in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $2,100, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $92,000 for the year ended December 31, 2001 from $22,000 for the same period in 2000. This represents an increase of 318%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund V’s independent petroleum consultants.

The major factor for the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Income Fund V’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Income Fund V during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production of performance, oil and gas prices and production costs. The impact of the revision would have increased depletion expense approximately $60,000 as of December 31, 2000.

15

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	29.18	$	17.60	66	%
Average price per Mcf of gas	$	4.56	$	2.42	88	%
Oil production in barrels		17,600		22,110	(20	%)
Gas production in Mcf		100,600		124,650	(19	%)
Income from net profits interests	$	390,786	$	278,643	40	%
Income Fund V distributions	$	250,000	$	50,000	400	%
Partner distributions	$	225,000	$	45,000	400	%
Per unit distribution to partners	$	30.00	$	6.00	400	%
Number of limited partner interests		7,499		7,499

Revenues

Income Fund V’s income from net profits interests increased to $390,786 from $278,643 for the years ended December 31, 2000 and 1999, respectively, an increase of 40%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Income Fund V increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 66%, or $11.58 per barrel, resulting in an increase of approximately $203,800 in income from net profits interests. Oil sales represented 53% of total oil and gas sales during the year ended December 31, 2000 as compared to 56% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Income Fund V increased during the same period by 88%, or $2.14 per Mcf, resulting in an increase of approximately $215,300 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $419,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 4,510 barrels, or 20%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $79,400 in income from net profits interests.

Gas production decreased approximately 24,050 Mcf, or 19%, during the same period, resulting in a decrease of approximately $58,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $137,600. The decrease in production is due primarily to one well, which a workover was performed on during the first quarter of 1999, dramatically increasing production during the second quarter of 1999. This same well by year end 1999 had shut down and was no longer a producing well; thus, the decrease for the 12 months ended December 31, 2000.

3.  Lease operating costs and production taxes increased 41%, or approximately $169,000, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as pulling

16

expenses being performed on several leases, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Income Fund V to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

Costs and Expenses

Total costs and expenses decreased to $139,537 from $161,762 for the years ended December 31, 2000 and 1999, respectively, a decrease of 14%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased less than 1%, or approximately $200, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $22,000 for the year ended December 31, 2000 from $44,000 for the same period in 1999. This represents a decrease of 50%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund V’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Income Fund V’s reserves for January 1, 2001 as compared to 2000.

Revenue and Distribution Comparison

Income Fund V net income for the years ended December 31, 2001, 2000 and 1999 was $33,430, $254,351 and $117,488, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $125,430, $276,351 and $161,488, respectively. Correspondingly, Income Fund V distributions for the years ended December 31, 2001, 2000 and 1999 were $225,000, $250,000 and $50,000, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The sources for the 2001 distributions of $225,000 were oil and gas operations of approximately $246,500, resulting in excess cash for contingencies or subsequent distributions. The source for the 2000 distributions of $250,000 were oil and gas operations of approximately $248,900, with the balance from available cash on hand at the beginning of the period. The sources for the 1999 distributions of $50,000 were oil and gas operations of approximately $81,700, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $225,000 of which $202,500 was distributed to the limited partners and $22,500 to the general partners. The per unit distribution to limited partners during the same period was $27.00. Total distributions during the year ended December 31, 2000 were $250,000 of which $225,000 was distributed to the limited partners and $25,000 to the general partners. The per unit distribution to limited partners during the same period was $30.00. Total distributions during the year ended December 31, 1999 were $50,000 of which $45,000 was distributed to the limited partners and $5,000 to the general partners. The per unit distribution to limited partners during the same period was $6.00.

Liquidity and Capital Resources of Income Fund V

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Income Fund V knows of no material change, nor does it anticipate any such change.

Cash flows (used in) provided by operating activities were approximately $(56,800) in the six months ended June 30, 2002 as compared to approximately $224,300 in the six months ended June 30, 2001.

17

There were no cash flows used in financing activities in the six months ended June 30, 2002. Cash flows used in financing activities were approximately $225,200 in the six months ended June 30, 2001.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $225,000 of which $202,500 was distributed to the limited partners and $22,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $27.00.

The sources for the six months ended June 30, 2001 distributions of $225,000 were oil and gas operations of approximately $224,300, with the balance from available cash on hand at the beginning of the period.

Since inception of Income Fund V, cumulative monthly cash distributions of $7,863,543 have been made to the partners. As of June 30, 2002, $7,060,820, or $941.57 per unit of limited partner interest, has been distributed to the limited partners, representing a 94% return of the capital contributed.

As of June 30, 2002, Income Fund V had approximately $45,600 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Income Fund V.

Cash flows provided by operating activities were approximately $246,500 in 2001 compared to $248,900 in 2000 and approximately $81,700 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Income Fund V had no cash flows from investing activities in 2001, 2000 and 1999.

Cash flows used in financing activities were approximately $225,500 in 2001 compared to $249,900 in 2000 and $50,100 in 1999. The only use in financing activities was the distributions to partners.

18

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES, INC. INCOME FUND VI, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties, Inc. Income Fund VI, L.P., which we will call Income Fund VI, and supplements the prospectus/proxy statement dated                     , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Income Fund VI. The purpose of the special meeting is for you to vote upon the merger of Income Fund VI with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Income Fund VI is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                                     .

This document contains the following information concerning Income Fund VI:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Income Fund VI

• Compensation and distributions from Income Fund VI

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Income Fund VI for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Income Fund VI’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Income Fund VI as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Income Fund VI, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Income Fund VI in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Income Fund VI’s assets. The Merger Value of Income Fund VI is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock

2

or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common and special stock to Income Fund VI, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Income Fund VI by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Income Fund VI. We believe, however, that Income Fund VI will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Income Fund VI. Our decision is based on the following factors in order of significance:

• Our method of valuation for Income Fund VI uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Income Fund VI, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Income Fund VI. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INCOME FUND VI

The Merger Value for Income Fund VI was determined by calculating its Net Asset Value and then dividing Income Fund VI’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Income Fund VI’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Income Fund VI’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Income Fund VI. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Income Fund VI is 6.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Income Fund VI
		Net Present Value of Reserves	$	5,798,153.00	July 1, 2002 reserve report

3

					Document(s) from which information was obtained or calculated
	plus	Net Working Capital	$	84,247.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Income Fund VI	$	5,882,400.00	calculated
(2)		Net Asset Value of Income Fund VI	$	5,882,400.00	calculated
	less	GP % owned by Southwest in Income Fund VI (10%)	$	588,240.00	Partnership records
	less	LP % owned by Southwest in Income Fund VI (31.83%)	$	1,872,367.92	Partnership records
	equals	Net Asset Value of Income Fund VI owned by limited partners (excluding Southwest’s ownership %)	$	3,421,792.08	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Income Fund VI (excluding Southwest’s ownership %)	$	3,421,792.08	calculated
	equals	The percentage of ownership of Income Fund VI (other than Southwest) to the total Net Asset Value		4.36%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Income Fund VI (other than Southwest)		4.36%	calculated
	equals	The number of shares of common stock attributable to Income Fund VI (other than to Southwest)		73,594.23	calculated
(7)		The number of shares of common stock attributable to Income Fund VI (other than to Southwest)		73,594	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Income Fund VI		12,927	Partnership records

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				Document(s) from which information was obtained or calculated
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Income Fund VI	6	calculated
(8)		The number of shares of special stock attributable to Income Fund VI (other than to Southwest)	14,719	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Income Fund VI	12,927	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Income Fund VI	1.14	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Income Fund VI for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	144,000	$	144,000	$	144,000	$	72,000
Administrative Overhead per Operating Agreements	$	105,044	$	103,340	$	105,399	$	49,356
Cash Distributions Paid to General Partners as General Partners(1)	$	112,500	$	117,500	$	47,500	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	285,537	$	258,669	$	87,171	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as additional general partner.

Set forth below is a table showing the cash distributions to Income Fund VI’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	1,014,895	$	1,057,500	$	427,500	$	398,261	$	836,100	$	—

Return of Capital: 100%; Return on Capital: 57%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR INCOME FUND VI

Aggregate Initial Investment by the Limited Partners:	$	10,000	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	15,724	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	5,294	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	264.71	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		18.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	113.43	(2)(4)
—as of December 31, 2001:	$	118.57	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	156.18	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	170.79	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	242.58	(2)(7)

⁽¹⁾ Stated in thousands

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

6

⁽³⁾ The Merger Value for Income Fund VI is equal to (1) the sum of (A) the present value of estimated future net revenues from Income Fund VI’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Income Fund VI is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Income Fund VI is based upon (1) the sum of (A) the estimated net cash flow from the sale of Income Fund VI’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Income Fund VI’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Income Fund VI is based upon (1) the sum of (A) the sale of Income Fund VI’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Income Fund VI’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Income Fund VI and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Income Fund VI is based upon (1) the sum of (A) Income Fund VI’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Income Fund VI.

INCOME FUND VI

Set forth below is basic information about Income Fund VI and its business and operations. It does not contain all the information about Income Fund VI that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Income Fund VI

General

Income Fund VI was organized as a Tennessee limited partnership on December 4, 1986. The offering of limited partner interests began August 25, 1986, reached minimum capital requirements on October 3, 1986 and concluded January 29, 1987, with total partner contributions of $10 million.

Principal Products, Marketing and Distribution

Income Fund VI has acquired and holds royalty interests and net profit interests in oil and gas properties located in Texas, Illinois, Colorado and Oklahoma.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	32%	68%
2000	39%	61%
1999	44%	56%

As the table indicates, Income Fund VI’s revenue is greater from gas than oil production.

7

Customer Dependence

No material portion of Income Fund VI’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Income Fund VI. Two purchasers accounted for 68% of Income Fund VI’s total oil and gas production during 2001: Duke Energy Field Services for 55% and Plains All American Pipeline, L.P. for 13%. Two purchasers accounted for 59% of Income Fund VI’s total oil and gas production during 2000: Phillips 66 Natural Gas Co. for 48% and Plain All American Pipeline, L.P. for 11%. Three purchasers accounted for 64% of Income Fund VI’s total oil and gas production during 1999: Phillips 66 Natural Gas Co. for 42%, Scurlock Permian LLC for 11% and Genesis Crude Oil for 11%. All purchasers of Income Fund VI’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Income Fund VI’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Income Fund VI’s sales of oil and gas production.

Properties

As of December 31, 2001, Income Fund VI possessed an interest in oil and gas properties located in Jackson and Weld Counties, Colorado; Clinton, Lawrence and Marion Counties, Illinois; Alfalfa, Beaver, Ellis, Garvin, Haskell, Latimer, Leflore, Logan, McClain, Noble, Pottawatomie, Roger Mills, Seminole and Woods Counties, Oklahoma; and Brazos, Burleson, Coke, Eastland, Ector, Fayette, Gaines, Jim Wells, Lee, Lipscomb, Mitchell, Nolan, Pecos, Reeves, Runnels, Sterling, Upton, Ward and Winkler Counties, Texas. These properties consist of various interests in approximately 158 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999 other than ordinary production declines and reserve depletion.

There were no leases sold during 2001. During 2000, five leases were sold for approximately $2,500. There were no leases sold during 1999.

Significant Properties

The following table reflects the significant properties in which Income Fund VI has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Mobil Amacker Tippet Upton County, Texas	7/87 at 23% to 100% net profits interests	10	17,000	4,747,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Income Fund VI’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.50 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.14 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INCOME FUND VI” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

8

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, lower return for Income Fund VI. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Income Fund VI has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Income Fund VI’s present reserves.

Because Income Fund VI does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farmout arrangements with the managing general partner or unrelated third parties. Generally, Income Fund VI retains a carried interest under the terms of a farm-out or receives cash.

Income Fund VI, or the owners of properties in which Income Fund VI owns an interest, can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves, which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INCOME FUND VI” in this prospectus supplement.

Market for Income Fund VI’s Limited Partnership Interests and Related Matters

Market Information

After completion of Income Fund VI’s first full fiscal year of operations and each year thereafter, the managing general partner has offered and will continue to offer to purchase each limited partner’s interest in Income Fund VI, at a price based on tangible assets of Income Fund VI, plus the net present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented at the sole discretion of the managing general partner. However, the managing general partner’s obligation to purchase limited partner interests is limited to an expenditure of an amount not in excess of 10% of the total limited partner interest initially subscribed for by limited partners. In 2001, 2,009.5 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $562.21 per unit. In 2000, 953 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $160.04 per unit. In 1999, 117 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $92.83 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001 there were 669 holders of limited partner interest in Income Fund VI.

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Distributions

Pursuant to Article IV, Section 4.01 of Income Fund VI’s Certificate and Agreement of Limited Partnership Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Income Fund VI’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Income Fund VI,] as determined at the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $1,127,395, with $1,014,895 distributed to the limited partners and $112,500 to the general partners. For the year ended December 31, 2001, distributions of $50.74 per unit of limited partner interest were made, based upon 20,000 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $1,175,000, with $1,057,500 distributed to the limited partners and $117,500 to the general partners. For the year ended December 31, 2000, distributions of $52.88 per unit of limited partner interest were made, based upon 20,000 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $475,000, with $427,500 distributed to the limited partners and $47,500 to the general partners. For the year ended December 31, 1999, distributions of $21.38 per unit of limited partner interest were made, based upon 20,000 units of limited partner interest outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR INCOME FUND VI

The following tables present summary selected financial information and operating data for Income Fund VI for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INCOME FUND VI” found elsewhere in this prospectus supplement and the financial statements and related notes for Income Fund VI included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	674,152		1,390,402		2,137,970		2,439,181		1,685,592		1,358,342		2,092,784
Net income (loss)	(114,201	)	696,827		571,669		1,215,573		523,863		(49,492	)	526,063
Partners’ share of net income (loss):
General partners	(11,420	)	69,683		57,167		121,557		52,386		(4,949	)	52,607
Partners	(102,781	)	627,144		514,502		1,094,016		471,477		(44,543	)	473,456
Partners’ net income (loss) per unit of limited partner interest	(5.14	)	31.36		25.73		54.70		23.57		(2.23	)	23.67
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	(15,134	)	769,997		1,094,672		1,154,873		616,556		339,246		893,515
Net cash provided by investing activities	—		—		—		2,500		—		98,437		10,833
Net cash used in financing activities	(7	)	(802,034	)	(1,126,152	)	(1,174,723	)	(473,983	)	(439,863	)	(929,067	)
Net increase (decrease) in cash and cash equivalents	(15,141	)	(32,037	)	(31,480	)	(17,350	)	142,573		(2,180	)	(24,719	)
EBITDA	(63,201	)	796,827		811,669		1,282,573		679,863		197,508		807,063
Cash distributions	—		802,395		1,127,395		1,175,000		475,000		439,961		929,000

11

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Partners’ cash distributions per $500 investment	—		36.12		50.74		52.88		21.38		19.91		41.81
Balance Sheet Data:
Cash and cash equivalents	117,141		131,725		132,282		163,762		181,112		38,539		40,719
Oil and gas properties, net at book value	1,487,134		1,678,134		1,538,134		1,778,134		1,847,634		2,003,634		2,329,071
Total assets	1,604,275		2,137,695		1,688,419		2,242,902		2,202,052		2,152,173		2,641,528
Total liabilities	32,894		1,955		2,837		1,594		1,317		301		203
Partners’ equity	2,268,573		2,776,496		2,371,354		2,871,747		2,835,231		2,791,254		3,234,058
General partners’ equity	(697,192	)	(640,756	)	(685,772	)	(630,439	)	(634,496	)	(639,382	)	(592,733	)
Partner’s book value per $500 investment	113.43		138.83		118.57		143.59		141.76		139.56		161.70
Production:
Oil production (Bbls)	13,100		15,300		29,000		33,200		43,840		40,600		50,100
Natural gas production (Mcf)	147,200		180,700		367,900		352,300		406,660		453,300		471,100
Equivalent production (Boe)	37,633		45,417		90,317		91,917		111,617		116,150		128,617
Average Sales Price:
Oil price (per/Bbl)	22.02		26.71		23.37		28.81		16.98		12.38		18.81
Natural gas price (per/Mcf)	2.62		5.43		3.97		4.21		2.31		1.89		2.44
Average sales price (per Boe)	17.91		30.61		23.67		26.54		15.10		11.69		16.27
Operating and Overhead Costs (per Boe)
Lease operating expense	16.58		9.62		11.64		9.45		6.86		7.89		8.17
Production taxes	1.06		1.90		1.46		1.60		.87		.68		.68
General and Administrative Expense (per Boe)	2.00		1.68		1.69		1.67		1.35		1.47		1.22
Total	19.64		13.20		14.79		12.72		9.08		10.04		10.07
Cash Operating Margin (per Boe)	(1.73	)	17.41		8.88		13.82		6.02		1.65		6.20

12

	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.36	2.20	2.66	.73	1.39	2.13	2.18
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	4,948,000	5,453,000	5,368,000	5,622,000	5,754,000	5,083,000	3,852,000
Oil (Bbls)	185,000	335,000	138,000	388,000	427,000	256,000	510,000
Total (Boe)	1,010,000	1,244,000	1,033,000	1,325,000	1,386,000	1,103,000	1,152,000

⁽¹⁾ Income Fund VI has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	5,882,000
Merger Value per $500 investment	$	264.71

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

13

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND RESULTS OF OPERATIONS FOR INCOME FUND VI

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Additional workovers may be performed in 2003. Income Fund VI may have an increase in production volumes for the year 2003, but thereafter, Income Fund VI will likely experience the historical production decline of approximately 10% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,					Percentage Increase (Decrease)
	2002			2001
Average price per barrel of oil	$	24.28		$	26.21	(7	%)
Average price per Mcf of gas	$	3.06		$	4.45	(31	%)
Oil production in barrels		6,800			7,600	(11	%)
Gas production in Mcf		74,600			93,400	(20	%)
Income from net profits interests	$	(7,172	)	$	328,398	(102	%)
Income Fund VI distributions	$	—		$	400,000	(100	%)
Limited partner distributions	$	—		$	360,000	(100	%)
Per unit distribution to limited partners	$	—		$	18.00	(100	%)
Number of limited partner units		20,000			20,000

Revenues

Income Fund VI’s income from net profits interests decreased to $(7,172) from $328,398 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 102%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Income Fund VI decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 7%, or $1.93 per barrel, resulting in a decrease of approximately $13,100 in income from net profits interests. Oil sales represented 42% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 32% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Income Fund VI decreased during the same period by 31%, or $1.39 per Mcf, resulting in a decrease of approximately $103,700 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $116,800. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 800 barrels, or 11%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $21,000 in income from net profits interests.

Gas production decreased approximately 18,800 Mcf, or 20%, during the same period, resulting in a decrease of approximately $83,700 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $104,700. The decrease in gas production is primarily due to downtime on one lease during the quarter ended June 30, 2002.

14

3.  Lease operating costs and production taxes increased 64%, or approximately $156,900, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The increase in lease operating expense is due to a workover and maintenance being performed on one lease during the quarter ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $67,966 from $98,963 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 31%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 5%, or approximately $2,000, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $31,000 for the quarter ended June 30, 2002, from $60,000, for the same period in 2001. This represents a decrease of 48%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund VI’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Income Fund VI during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.02	$	26.71	(18	%)
Average price per Mcf of gas	$	2.62	$	5.43	(52	%)
Oil production in barrels		13,100		15,300	(14	%)
Gas production in Mcf		147,200		180,700	(19	%)
Income from net profits interests	$	10,615	$	867,248	(99	%)
Income Fund VI distributions	$	—	$	802,395	(100	%)
Limited partner distributions	$	—	$	722,395	(100	%)
Per unit distribution to limited partners	$	—	$	36.12	(100	%)
Number of limited partner units		20,000		20,000

Revenues

Income Fund VI’s income from net profits interests decreased to $10,615 from $867,248 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 99%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Income Fund VI decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.69 per barrel, resulting in a decrease of approximately $61,400 in income from net profits interests. Oil sales represented 43% of total oil and gas sales during the six months ended June 30, 2002 as compared to 29% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Income Fund VI decreased during the same period by 52%, or $2.81 per Mcf, resulting in a decrease of approximately $413,600 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $475,000. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

15

2.  Oil production decreased approximately 2,200 barrels, or 14%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $58,800 in income from net profits interests.

Gas production decreased approximately 33,500 Mcf, or 19%, during the same period, resulting in a decrease of approximately $181,900 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $240,700. The decrease in gas production is primarily due to downtime on one lease during the six months ended June 30, 2002.

3.  Lease operating costs and production taxes increased 27%, or approximately $140,400, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001. The increase in lease operating expense is due to a workover and maintenance being performed on one lease during the six months ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $126,092 from $176,321 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 28%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $1,200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $51,000 for the six months ended June 30, 2002 from $100,000 for the same period in 2001. This represents a decrease of 49%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund VI’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Income Fund VI during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	23.37	$	28.81	(19	%)
Average price per Mcf of gas	$	3.97	$	4.21	(6	%)
Oil production in barrels		29,000		33,200	(13	%)
Gas production in Mcf		367,900		352,300	4	%
Income from net profits interests	$	955,342	$	1,423,101	(33	%)
Income Fund VI distributions	$	1,127,395	$	1,175,000	(4	%)
Limited partner distributions	$	1,014,985	$	1,057,500	(4	%)
Per unit distributions to limited partners	$	50.74	$	52.88	(4	%)
Number of limited partner units		20,000		20,000

Revenues

Income Fund VI’s income from net profits interests decreased to $955,342 from $1,423,101 for the years ended December 31, 2001 and 2000, respectively, a decrease of 33%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

16

1.  The average price for a barrel of oil received by Income Fund VI decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 19%, or $5.44 per barrel, resulting in a decrease of approximately $157,800 in income from net profits interests. Oil sales represented 32% of total oil and gas sales during the year ended December 31, 2001 as compared to 39% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Income Fund VI decreased during the same period by 6%, or $.24 per Mcf, resulting in a decrease of approximately $88,300 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $246,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 4,200 barrels, or 13%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $121,000 in income from net profits interests.

Gas production increased approximately 15,600 Mcf, or 4%, during the same period, resulting in an increase of approximately $65,700 in income from net profits interests.

The total net decrease in income from net profits interests due to the change in production is approximately $55,300.

3.  Lease operating costs and production taxes increased 16%, or approximately $167,000, during the year ended December 31, 2001 as compared to the year ended December 31, 2000. The increase in lease operating expense is primarily due to pulling expense and maintenance on two leases being performed in 2001.

Costs and Expenses

Total costs and expenses increased to $392,483 from $220,091 for the years ended December 31, 2001 and 2000, respectively, an increase of 78%. The increase is primarily the result of higher depletion expense, partially offset by a decrease in general and administrative costs.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased less than 1%, or approximately $600, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $240,000 for the year ended December 31, 2001, from $67,000 for the same period in 2000. This represents an increase of 258%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund VI’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Income Fund VI’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Income Fund VI during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $80,000 as of December 31, 2000.

17

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.81	$	16.98	70	%
Average price per Mcf of gas	$	4.21	$	2.31	82	%
Oil production in barrels		33,200		43,840	(24	%)
Gas production in Mcf		352,300		406,660	(13	%)
Income from net profits interests	$	1,423,101	$	823,002	73	%
Income Fund VI distributions	$	1,175,000	$	475,000	147	%
Limited partner distributions	$	1,057,500	$	427,500	147	%
Per unit distribution to partners	$	52.88	$	21.38	147	%
Number of limited partner units		20,000		20,000

Revenues

Income Fund VI’s income from net profits interests increased to $1,423,101 from $823,002 for the years ended December 31, 2000 and 1999, respectively, an increase of 73%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Income Fund VI increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 70%, or $11.83 per barrel, resulting in an increase of approximately $392,800 in income from net profits interests. Oil sales represented 39% of total oil and gas sales during the year ended December 31, 2000 as compared to 44% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Income Fund VI increased during the same period by 82%, or $1.90 per Mcf, resulting in an increase of approximately $669,400 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $1,062,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 10,640 barrels, or 24%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $180,700 in income from net profits interests.

Gas production decreased approximately 54,360 Mcf, or 13%, during the same period, resulting in a decrease of approximately $125,600 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $306,300. The decrease in production is due primarily to one well, which a workover was performed on during the first quarter of 1999, dramatically increasing production during the second quarter of 1999. This same well by year end 1999 had shut down and was no longer a producing well; thus, the decrease for the 12 months ended December 31, 2000.

3.  Lease operating costs and production taxes increased 18%, or approximately $153,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance and in part to  

18

the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Income Fund VI to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

Costs and Expenses

Total costs and expenses decreased to $220,091 from $306,589 for the years ended December 31, 2000 and 1999, respectively, a decrease of 28%. The decrease is primarily the result of lower depletion expense, partially offset by an increase in general and administrative costs.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $2,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $67,000 for the year ended December 31, 2000 from $156,000 for the same period in 1999. This represents a decrease of 57%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Income Fund VI’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Income Fund VI’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $14,000 as of December 31, 1999.

Revenue and Distribution Comparison

Income Fund VI net income for the years ended December 31, 2001, 2000 and 1999 was $571,669, $1,215,573 and $523,863, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $811,669, $1,282,573 and $679,863, respectively. Correspondingly, Income Fund VI distributions for the years ended December 31, 2001, 2000 and 1999 were $1,127,395, $1,175,000 and $475,000, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The sources for the 2001 distributions of $1,127,395 were oil and gas operations of approximately $1,095,000, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $1,175,000 were oil and gas operations of approximately $1,154,900 and the change in oil and gas properties of approximately $2,500, with the balance from available cash on hand at the beginning of the period. The sources for the 1999 distributions of $475,000 were oil and gas operations of approximately $616,600, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $1,127,395 of which $1,014,895 was distributed to the limited partners and $112,500 to the general partners. The per unit distribution to limited partners during the same period was $50.74. Total distributions during the year ended December 31, 2000 were $1,175,000 of which $1,057,500 was distributed to the limited partners and $117,500 to the general partners. The per unit distribution to limited partners during the same period was $52.88. Total distributions during the year ended December 31, 1999 were $475,000 of which $427,500 was distributed to the limited partners and $47,500 to the general partners. The per unit distribution to limited partners during the same period was $21.38.

19

Liquidity and Capital Resources of Income Fund VI

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Income Fund VI knows of no material change, nor does it anticipate any such change.

Cash flows (used in) provided by operating activities were approximately $(15,100) in the six months ended June 30, 2002 as compared to approximately $770,000 in the six months ended June 30, 2001. The primary use of the 2002 cash flow from operating activities was operations.

There were no cash flows used in financing activities in the six months ended June 30, 2002 as compared to approximately $802,000 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

There were no material cash flows used in financing activities during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $802,395 of which $722,395 was distributed to the limited partners and $80,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $36.12.

The sources for the six months ended June 30, 2001 distributions of $802,395 were oil and gas operations of approximately $770,000, with the balance from available cash on hand at the beginning of the period.

Since inception of Income Fund VI, cumulative monthly cash distributions of $17,453,854 have been made to the partners. As of June 30, 2002, $15,724,177 or $786.21 per unit of limited partner interest has been distributed to the limited partners, representing a 157% return of the capital contributed.

As of June 30, 2002, Income Fund VI had approximately $84,200 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Income Fund VI.

Cash flows provided by operating activities were approximately $1,095,000 in 2001 compared to $1,154,900 in 2000 and approximately $616,600 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

There were no cash flows provided by investing activities during 2001. Cash flows provided by investing activities were approximately $2,500 in 2000. Income Fund VI had no cash flows from investing activities in 1999.

Cash flows used in financing activities were approximately $1,126,000 in 2001 compared to $1,175,000 in 2000 and approximately $474,000 in 1999. The only use in financing activities was the distributions to partners.

Liquidity—MD&A

Income Fund VI accrued an oil and gas revenue receivable (included in the payable to the managing general partner) of $152,138 at June 30, 2002, and recognized a net loss in the second quarter of 2002 on an accrual basis for its net profits interest in oil and gas properties. Cash distributions of the net profits interest are based on actual cash received from the underlying oil and gas properties, net of expenses incurred during that quarterly period. Accordingly, if the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter no net cash is due to Income Fund VI’s net profits interest until the deficit is recovered from future net profits. Future cash distributions to Income Fund VI are dependent on a positive quarterly net profits calculation on the underlying properties, which differs from the calculation on an accrual basis.

Income Fund VI’s wells have been depleting over its life and production has experienced declines from year to year, while costs have not always decreased proportionately. This economic decline, coupled with the fluctuation of prices, has caused Income Fund VI to experience periodic net losses. Because Income Fund VI has net profit interests, this situation can cause Income Fund VI to generate a payable to the managing general partner. If Income Fund VI should continue to experience this economic decline thereby creating net losses and increasing the payable, the managing general partner may have to consider dissolution and termination steps according to the Partnership Agreement.

20

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST OIL & GAS INCOME FUND VII-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Oil & Gas Income Fund VII-A, L.P., which we call Oil and Gas Income Fund VII-A, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Oil & Gas Income Fund VII-A. The purpose of the special meeting is for you to vote upon the merger of Oil & Gas Income Fund VII-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Oil & Gas Income Fund VII-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                             .

This document contains the following information concerning Oil & Gas Income Fund VII-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Oil & Gas Income Fund VII-A

• Compensation and distributions from Oil & Gas Income Fund VII-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including  Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months  ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Oil & Gas Income Fund VII-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Oil & Gas Income Fund VII-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Oil & Gas Income Fund VII-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Oil & Gas Income Fund VII-A; however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Oil & Gas Income Fund VII-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Oil & Gas Income Fund VII-A’s assets. The Merger Value of Oil & Gas Income Fund VII-A is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Oil & Gas Income Fund VII-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Oil & Gas Income Fund VII-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Oil & Gas Income Fund VII-A. We believe, however, that Oil & Gas Income Fund VII-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Oil & Gas Income Fund VII-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Oil & Gas Income Fund VII-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Oil & Gas Income Fund VII-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Oil & Gas Income Fund VII-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR OIL & GAS INCOME FUND VII-A

The Merger Value for Oil & Gas Income Fund VII-A was determined by calculating its Net Asset Value and then dividing Oil & Gas Income Fund VII-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Oil & Gas Income Fund VII-A’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Oil & Gas Income Fund VII-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Oil & Gas Income Fund VII-A. As indicated below, the number of shares of common stock issuable per each unit of Oil & Gas Income Fund VII-A is 3.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Oil & Gas Income Fund VII-A
		Net Present Value of Reserves	$	2,247,374.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	125,549.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Oil & Gas Income Fund VII-A	$	2,372,923.00	calculated

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						Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Oil & Gas Income Fund VII-A	$	2,372,923.00		calculated
	less	GP% owned by Southwest in Oil & Gas Income Fund VII-A (10%)	$	237,292.30		Partnership records
	less	LP% owned by Southwest in Oil & Gas Income Fund VII-A (28.13%)	$	667,503.24		Partnership records
	equals	Net Asset Value of Oil & Gas Income Fund VII-A owned by limited partners (excluding Southwest’s ownership %)	$	1,468,127.46		calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00		July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58		calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58		calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58		calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42		calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00		calculated
	divided into	The Net Asset Value owned by limited partners of Oil & Gas Income Fund VII-A (excluding Southwest’s ownership %)	$	1,468,127.46		calculated
	equals	The percentage of ownership of Oil & Gas Income Fund VII-A (other than Southwest) to the total Net Asset Value		1.87	%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000		June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23	%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347		calculated
(6)		Total number of shares of common stock for combined entity		1,688,347		calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Oil & Gas Income Fund VII-A (other than Southwest)		1.87	%	calculated
	equals	The number of shares of common stock attributable to Oil & Gas Income Fund VII-A (other than to Southwest)		31,575.77		calculated
(7)		The number of shares of common stock attributable to Oil & Gas Income Fund VII-A (other than to Southwest)		31,576		calculated

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				Document(s) from which information was obtained or calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Oil & Gas Income Fund VII-A	10,312	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund VII-A	3	calculated
(8)		The number of shares of special stock attributable to Oil & Gas Income Fund VII-A (other than to Southwest)	6,315	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Oil & Gas Income Fund VII-A	10,312	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Oil & Gas Income Fund VII-A	.61	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Oil & Gas Income Fund VII-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	108,000	$	108,000	$	108,000	$	54,000
Administrative Overhead per Operating Agreements	$	36,077	$	34,165	$	33,848	$	18,101
Cash Distributions Paid to General Partners as General Partners(1)	$	42,558	$	43,500	$	18,500	$	13,400
Cash Distributions Paid to General Partner as Limited Partner	$	98,100	$	81,026	$	22,026	$	37,687

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

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Set forth below is a table showing the cash distributions to Oil & Gas Income Fund VII-A’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	383,024	$	391,500	$	166,500	$	184,698	$	261,900	$	120,600
Return of Capital: 100%; Return on Capital: 32%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR OIL & GAS INCOME FUND VII-A

Aggregate Initial Investment by the Limited Partners:	$	7,500	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	9,863	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	2,136	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	142.38	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 Months ended June 30, 2002:		8.3	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	74.56	(2)(4)
—as of December 31, 2001:	$	73.76	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	61.38	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	77.03	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	116.76	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Oil & Gas Income Fund VII-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Oil & Gas Income Fund VII-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Oil & Gas Income Fund VII-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Oil & Gas Income Fund VII-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Oil & Gas Income Fund VII-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Oil & Gas Income Fund VII-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

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⁽⁶⁾ The liquidation value for Oil & Gas Income Fund VII-A is based upon (1) the sum of (A) the sale of Oil & Gas Income Fund VII-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Oil & Gas Income Fund VII-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Oil & Gas Income Fund VII-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Oil & Gas Income Fund VII-A is based upon (1) the sum of (A) Oil & Gas Income Fund VII-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Oil & Gas Income Fund VII-A.

OIL & GAS INCOME FUND VII-A

Set forth below is basic information about Oil & Gas Income Fund VII-A and its business and operations. It does not contain all the information about Oil & Gas Income Fund VII-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Oil & Gas Income Fund VII-A

General

Oil & Gas Income Fund VII-A was organized as a Delaware limited partnership on January 30, 1987. The offering of limited partner interests began March 4, 1987, reached minimum capital requirements on April 28, 1987 and concluded September 21, 1987 with total limited partner contributions of $7.5 million.

Principal Products, Marketing and Distribution

Oil & Gas Income Fund VII-A has acquired and holds working interests in oil and gas properties located in Texas, New Mexico, Oklahoma and Louisiana.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	59%	41%
2000	63%	37%
1999	64%	36%

As the table indicates, Oil & Gas Income Fund VII-A’s revenue is almost evenly divided between its oil and gas production.

Customer Dependence

No material portion of Oil & Gas Income Fund VII-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Oil & Gas Income Fund VII-A Four purchasers accounted for 63% of Oil & Gas Income Fund VII-A’s total oil and gas production during 2001: Duke Energy Field Services for 25%, Sid Richardson Energy Services for 14%, Plains All American Pipeline, L.P. for 12% and BP Amoco for 12%. Four purchasers accounted for 70% of Oil & Gas Income Fund VII-A’s total oil and gas production during 2000: Phillips 66 Natural Gas Co. for 32%, Plains All American

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Pipeline, L.P. for 14%, Amoco Production for 13% and Sun Refining and Marketing Co. for 11%. Four purchasers accounted for 68% of Oil & Gas Income Fund VII-A’s total oil and gas production during 1999: Phillips 66 Natural Gas Co. for 29%, Sun Refining and Marketing Co. for 15%, Scurlock Permian LLC for 12% and Amoco Production for 12%. All purchasers of Oil & Gas Income Fund VII-A’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Oil & Gas Income Fund VII-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Oil & Gas Income Fund VII-A’s sales of oil and gas production.

Properties

As of December 31, 2001, Oil & Gas Income Fund VII-A possessed an interest in oil and gas properties located in Cameron Parish, Louisiana; Eddy, Chaves and Lea Counties, New Mexico; Pottawatomie County, Oklahoma; and Dawson, Howard, Leon, Pecos, Stephens, Upton, Ward and Winkler Counties, Texas. These properties consist of various interests in approximately 84 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

During 2001, three leases were sold for approximately $60. There were no property sales during 2000 and 1999.

Significant Properties

The following table reflects the significant properties in which Oil & Gas Income Fund VII-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
BHP—Hendricks Winkler County, Texas	10/98 at 10% to 17% working interest	5	68,000	19,000
Mobil Acquisition Pecos and Upton Counties, Texas	10/88 at 2% to 16% working interest	9	4,000	477,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Oil & Gas Income Fund VII-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.13 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.36 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VII-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

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The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Oil & Gas Income Fund VII-A. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Oil & Gas Income Fund VII-A has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Oil & Gas Income Fund VII-A’s present reserves.

Because Oil & Gas Income Fund VII-A does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Oil & Gas Income Fund VII-A retains a carried interest under the terms of a farm-out, or receives cash.

Oil & Gas Income Fund VII-A or the owners of properties in which Oil & Gas Income Fund VII-A owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF OIL & GAS INCOME FUND VII-A” in this prospectus supplement.

Market for Oil & Gas Income Fund VII-A’s Limited Partnership Interests and Related Matters

Market Information

After completion of Oil & Gas Income Fund VII-A’s first full fiscal year of operations and each year thereafter, the managing general partner has offered and will continue to offer to purchase each limited partner’s interest in Oil & Gas Income Fund VII-A, at a price based on tangible assets of Oil & Gas Income Fund VII-A, plus the net present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the managing general partner. However, the managing general partner’s obligation to purchase limited partner interests is limited to an expenditure of an amount not in excess of 10% of the total limited partner interest initially subscribed for by limited partners. In 2001, 1,299 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $210.69 per unit. In 2000, 1,373 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $80.48 per unit. In 1999, 122 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $36.76 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 566 holders of limited partner interest in Oil & Gas Income Fund VII-A.

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Distributions

Pursuant to Article IV, Section 4.01 of Oil & Gas Income Fund VII-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Oil & Gas Income Fund VII-A’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Oil & Gas Income Fund VII-A], as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $425,582, with $383,024 distributed to the limited partners and $42,558 to the general partners. For the year ended December 31, 2001, distributions of $25.53 per unit of limited partner interest were made, based upon 15,000 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $435,000, with $391,500 distributed to the limited partners and $43,500 to the general partners. For the year ended December 31, 2000, distributions of $26.10 per unit of limited partner interest were made, based upon 15,000 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $185,000, with $166,500 distributed to the limited partners and $18,500 to the general partners. For the year ended December 31, 1999, distributions of $11.10 per unit of limited partner interest were made, based upon 15,000 units of limited partner interest outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

OIL & GAS INCOME FUND VII-A

The following tables present summary selected financial information and operating data for Oil & Gas Income Fund VII-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VII-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Oil & Gas Income Fund VII-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	370,273		460,225		745,318		930,919		606,979		540,545		955,737
Net income (loss)	147,340		225,020		255,471		469,763		187,448		(330,630	)	192,559
Partners’ share of net income (loss):
General partners	14,734		22,502		25,547		46,976		18,745		(33,063	)	19,256
Partners	132,606		202,518		229,924		422,787		168,703		(297,567	)	173,303
Partners’ net income (loss) per unit of limited partner interest	8.84		13.50		15.33		28.19		11.25		(19.84	)	11.56
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	113,047		264,124		411,348		450,467		156,417		135,606		322,308
Net cash provided by investing activities	(1,057	)	(1,739	)	(1,425	)	(7,448	)	(4,052	)	127,937		(10,531	)
Net cash used in financing activities	(134,128	)	(276,622	)	(425,915	)	(433,823	)	(185,068	)	(200,585	)	(286,807	)
Net increase (decrease) in cash and cash equivalents	(22,138	)	(14,237	)	(15,992	)	9,196		(32,703	)	62,958		24,970
EBITDA	169,340		252,020		321,471		498,763		238,448		55,324		398,559
Cash distributions	134,000		275,010		425,582		435,000		185,000		197,198		291,000
Partners’ cash distributions per $500 investment	8.04		16.50		25.53		26.10		11.10		12.31		17.46
Balance Sheet Data:
Cash and cash equivalents	30,531		54,424		52,669		68,661		59,465		92,168		29,210
Oil and gas properties, net at book value	412,097		472,354		433,040		497,615		519,167		566,115		1,080,005
Total assets	538,878		644,508		525,666		696,110		660,170		658,283		1,189,349
Total liabilities	1,232		81		1,360		1,693		516		1,077		4,315

11

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Partners’ equity	1,118,336		1,214,439		1,106,330		1,259,430		1,228,143		1,225,940		1,708,205
General partners’ equity	(580,690	)	(570,012	)	(582,024	)	(565,013	)	(568,489	)	(568,734	)	(523,171	)
Partner’s book value per $500 investment	74.56		80.96		73.76		83.96		81.88		81.73		113.88
Production:
Oil production (Bbls)	10,400		9,800		19,500		20,900		23,000		27,600		34,900
Natural gas production (Mcf)	56,200		38,500		75,800		81,700		93,700		103,000		121,900
Equivalent production (Boe)	19,767		16,217		32,133		34,517		38,617		44,767		55,217
Average Sales Price:
Oil price (per/Bbl)	21.61		25.89		22.67		28.23		16.94		12.22		18.83
Natural gas price (per/Mcf)	2.59		5.36		4.00		4.17		2.32		1.97		2.45
Average sales price (per Boe)	18.73		28.38		23.19		26.97		15.72		12.07		17.31
Operating and Overhead Costs (per Boe)
Lease operating expense	6.09		7.28		7.89		7.18		5.49		7.02		6.71
Production taxes	1.40		2.13		1.82		2.06		1.16		.95		1.30
General and Administrative Expense (per Boe)	2.94		3.59		3.59		3.41		2.96		2.90		2.16
Total	10.43		13.00		13.30		12.65		9.61		10.87		10.17
Cash Operating Margin (per Boe)	8.30		15.38		9.89		14.32		6.11		1.20		7.14
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.11		1.66		2.05		.84		1.32		8.63		3.73
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	801,000		1,038,000		795,000		1,063,000		943,000		635,000		894,000
Oil (Bbls)	196,000		205,000		153,000		208,000		178,000		88,000		188,000
Total (Boe)	330,000		378,000		286,000		385,000		335,000		194,000		337,000

(1) Oil & Gas Income Fund VII-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	2,373,000
Merger Value per $500 investment	$	142.38

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information, assuming (1) all partnerships participate in the merger and (2) participation in the merger of those partnerships that on a combined basis have the lowest combined net cash provided by operating activities for the last fiscal year of such partnerships.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VII-A

General

Based on current conditions, management anticipates performing workovers during 2002 to enhance production. Oil & Gas Income Fund VII-A may have an increase in production volumes for the year 2002, otherwise, Oil & Gas Income Fund VII-A will likely experience the historical production decline of approximately 10% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.20	$	24.96	(3%)
Average price per Mcf of gas	$	3.07	$	4.43	(31%)
Oil production in barrels		5,400		5,100	6%
Gas production in Mcf		31,000		17,600	76%
Gross oil and gas revenue	$	225,894	$	225,236	—
Net oil and gas revenue	$	143,957	$	146,366	(2%)
Oil & Gas Income Fund VII-A distributions	$	90,000	$	125,000	(28%)
Limited partner distributions	$	81,000	$	112,500	(28%)
Per unit distribution to limited partners	$	5.40	$	7.50	(28%)
Number of limited partner interests		15,000		15,000

Revenues

Oil & Gas Income Fund VII-A’s oil and gas revenues increased to $225,894 from $225,236 for the quarters ended June 30, 2002 and 2001, respectively, an increase of less than 1%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VII-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 3%, or $.76 per barrel, resulting in a decrease of approximately $4,100 in revenues. Oil sales represented 58% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 62% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund VII-A decreased during the same period by 31%, or $1.36 per Mcf, resulting in a decrease of approximately $42,200 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $46,300. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 300 barrels, or 6%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in an increase of approximately $7,500 in revenues.

Gas production increased approximately 13,400 Mcf, or 76%, during the same period, resulting in an increase of approximately $59,400 in revenues.

The total increase in revenues due to the change in production is approximately $66,900. The increase in gas production is due to an adjustment of gas balancing for a non-operated lease.

13

Costs and Expenses

Total costs and expenses decreased to $123,273 from $124,409 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 1%. The decrease is the result of lower depletion expense and general and administrative expense, partially offset by an increase in lease operating costs.

1.  Lease operating costs and production taxes were 4% higher, or approximately $3,100 more, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 4% or approximately $1,200 during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $13,000 for the quarter ended June 30, 2002, from $16,000 for the same period in 2001. This represents a decrease of 19%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VII-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.61	$	25.89	(17	%)
Average price per Mcf of gas	$	2.59	$	5.36	(52	%)
Oil production in barrels		10,400		9,800	6	%
Gas production in Mcf		56,200		38,500	46	%
Gross oil and gas revenue	$	370,273	$	460,225	(20	%)
Net oil and gas revenue	$	222,058	$	307,728	(28	%)
Oil & Gas Income Fund VII-A distributions	$	134,000	$	275,010	(51	%)
Limited partner distributions	$	120,600	$	247,509	(51	%)
Per unit distribution to limited partners	$	8.04	$	16.50	(51	%)
Number of limited partner interests		15,000		15,000

Revenues

Oil & Gas Income Fund VII-A’s oil and gas revenues decreased to $370,273 from $460,225 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 20%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VII-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 17%, or $4.28 per barrel, resulting in a decrease of approximately $44,500 in revenues. Oil sales represented 61% of total oil and gas sales during the six months ended June 30, 2002 as compared to 55% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund VII-A decreased during the same period by 52%, or $2.77 per Mcf, resulting in a decrease of approximately $155,700 in revenues.

14

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $200,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 600 barrels, or 6%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in an increase of approximately $15,500 in revenues.

Gas production increased approximately 17,700 Mcf, or 46%, during the same period, resulting in an increase of approximately $94,900 in revenues.

The total increase in revenues due to the change in production is approximately $110,400. The increase in gas production is due to an adjustment of gas balancing for a non-operated lease.

Costs and Expenses

Total costs and expenses decreased to $228,369 from $237,714 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 4%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative expense.

1.  Lease operating costs and production taxes were 3% lower, or approximately $4,300 less, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased less than 1% or approximately $60 during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $22,000 for the six months ended June 30, 2002 from $27,000 for the same period in 2001. This represents a decrease of 19%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VII-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	22.67	$	28.23	(20	%)
Average price per Mcf of gas	$	4.00	$	4.17	(4	%)
Oil production in barrels		19,500		20,900	(7	%)
Gas production in Mcf		75,800		81,700	(7	%)
Gross oil and gas revenue	$	745,318	$	930,919	(20	%)
Net oil and gas revenue	$	433,255	$	612,009	(29	%)
Oil & Gas Income Fund VII-A distributions	$	425,582	$	435,000	(2	%)
Limited partner distributions	$	383,024	$	391,500	(2	%)
Per unit distribution to limited partners	$	25.53	$	26.10	(2	%)
Number of limited partner interests		15,000		15,000

15

Revenues

Oil & Gas Income Fund VII-A’s oil and gas revenues decreased to $745,318 from $930,919 for the years ended December 31, 2001 and 2000, respectively, a decrease of 20%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VII-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 20%, or $5.56 per barrel, resulting in a decrease of approximately $108,400 in revenues. Oil sales represented 59% of total oil and gas sales during the year ended December 31, 2001 as compared to 63% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Oil & Gas Income Fund VII-A decreased during the same period by 4%, or $.17 per Mcf, resulting in a decrease of approximately $12,900 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $121,300. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,400 barrels, or 7%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $39,500 in revenues.

Gas production decreased approximately 5,900 Mcf, or 7%, during the same period, resulting in a decrease of approximately $24,600 in revenues.

The total decrease in revenues due to the change in production is approximately $64,100.

Costs and Expenses

Total costs and expenses increased to $493,479 from $465,771 for the years ended December 31, 2001 and 2000, respectively, an increase of 6%. The increase is the result of higher depletion expense, partially offset by a decrease in general and administrative expense and lease operating costs.

1.  Lease operating costs and production taxes decreased 2%, or approximately $6,800, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $2,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $66,000 for the year ended December 31, 2001 from $29,000 for the same period in 2000. This represents an increase of 128%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VII-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Oil & Gas Income Fund VII-A’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Oil & Gas Income Fund VII-A during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $23,000 as of December 31, 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage (Increase) (Decrease)
	2000		1999
Average price per barrel of oil	$	28.23	$	16.94	67	%
Average price per Mcf of gas	$	4.17	$	2.32	80	%
Oil production in barrels		20,900		23,000	(9	%)
Gas production in Mcf		81,700		93,700	(13	%)
Gross oil and gas revenue	$	930,919	$	606,979	53	%
Net oil and gas revenue	$	612,009	$	350,089	75	%
Oil & Gas Income Fund VII-A distributions	$	435,000	$	185,000	135	%
Partner distributions	$	391,500	$	166,500	135	%
Per unit distribution to partners	$	26.10	$	11.10	135	%
Number of limited partner interests		15,000		15,000

Revenues

Oil & Gas Income Fund VII-A’s oil and gas revenues increased to $930,919 from $606,979 for the years ended December 31, 2000 and 1999, respectively, an increase of 53%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VII-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 67%, or $11.29 per barrel, resulting in an increase of approximately $236,000 in revenues. Oil sales represented 63% of total oil and gas sales during the year ended December 31, 2000 as compared to 64% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Oil & Gas Income Fund VII-A increased during the same period by 80%, or $1.85 per Mcf, resulting in an increase of approximately $151,100 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $387,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 2,100 barrels, or 9%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $35,600 in revenues.

Gas production decreased approximately 12,000 Mcf, or 13%, during the same period, resulting in a decrease of approximately $27,800 in revenues.

The total decrease in revenues due to the change in production is approximately $63,400.

Costs and Expenses

Total costs and expenses increased to $465,771 from $422,259 for the years ended December 31, 2000 and 1999, respectively, an increase of 10%. The increase is the result of higher general and administrative expense, lease operating costs and partially offset by a decrease in depletion expense.

1.  Lease operating costs and production taxes increased 24%, or approximately $62,000, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance and in part to the rise in

17

production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Oil & Gas Income Fund VII-A to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $3,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $29,000 for the year ended December 31, 2000 from $51,000 for the same period in 1999. This represents a decrease of 43%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VII-A’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Oil & Gas Income Fund VII-A’s reserves for January 1, 2001 as compared to 2000. Another contributing factor was due to the impact of revisions of previous estimates on reserves. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have decreased depletion expense approximately $2,000 as of December 31, 1999.

Revenue and Distribution Comparison

Oil & Gas Income Fund VII-A net income for the years ended December 31, 2001, 2000 and 1999 was $255,471, $469,763 and $187,448, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $321,471, $498,763 and $238,448, respectively. Correspondingly, Oil & Gas Income Fund VII-A distributions for the years ended December 31, 2001, 2000 and 1999 were $425,582, $435,000 and $185,000, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The sources for the 2001 distributions of $425,582 were oil and gas operations of approximately $411,300 and the change in oil and gas properties of approximately $(1,400), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $435,000 were oil and gas operations of approximately $450,500 and the change in oil and gas properties of approximately $(7,400), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $185,000 were oil and gas operations of approximately $156,400, partially offset by a change in oil and gas properties of approximately $4,100, with the balance from available cash on hand at the beginning of the period.

Total distributions during the year ended December 31, 2001 were $425,582 of which $383,024 was distributed to the limited partners and $42,558 to the general partners. The per unit distribution to limited partners during the same period was $25.53. Total distributions during the year ended December 31, 2000 were $435,000 of which $391,500 was distributed to the limited partners and $43,500 to the general partners. The per unit distribution to limited partners during the same period was $26.10. Total distributions during the year ended December 31, 1999 were $185,000 of which $166,500 was distributed to the limited partners and $18,500 to the general partners. The per unit distribution to limited partners during the same period was $11.10.

Liquidity and Capital Resources of Oil & Gas Income Fund VII-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Oil & Gas Income Fund VII-A knows of no material change, nor does it anticipate any such change.

18

Cash flows provided by operating activities were approximately $113,000 in the six months ended June 30, 2002 as compared to approximately $264,100 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $1,100 in the six months ended June 30, 2002 as compared to approximately $1,700 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was the additions to oil and gas properties.

Cash flows used in financing activities were approximately $134,100 in the six months ended June 30, 2002 as compared to approximately $276,600 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $134,000 of which $120,600 was distributed to the limited partners and $13,400 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2002 was $8.04. Total distributions during the six months ended June 30, 2001 were $275,010 of which $247,509 was distributed to the limited partners and $27,501 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $16.50.

The sources for the 2002 distributions of $134,000 were oil and gas operations of approximately $113,000, the change in oil and gas properties of approximately $(1,100), with the balance from available cash on hand at the beginning of the period. The source for the 2001 distributions of $275,010 was oil and gas operations of approximately $264,100, with the balance from available cash on hand at the beginning of the period.

Since inception of Oil & Gas Income Fund VII-A, cumulative monthly cash distributions of $10,938,312 have been made to the partners. As of June 30, 2002, $9,862,695 or $657.51 per unit of limited partner interest has been distributed to the limited partners, representing a 132% return of the capital contributed.

As of June 30, 2002, Oil & Gas Income Fund VII-A had approximately $125,500 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Oil & Gas Income Fund VII-A.

Cash flows provided by operating activities were approximately $411,300 in 2001 compared to $450,500 in 2000 and approximately $156,400 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $1,400 in 2001 compared to $7,400 in 2000 and approximately $4,100 in 1999. The principal use of the 2001 cash flows from investing activities was addition to oil and gas properties.

Cash flows used in financing activities were approximately $425,900 in 2001 compared to $433,800 in 2000 and approximately $185,100 in 1999. The only use in financing activities is the distributions to partners.

19

SOUTHWEST ROYALTIES, INC

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VII-B, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties Institutional Income Fund VII-B, L.P., which we call Institutional Income Fund VII-B, and supplements the prospectus/proxy statement dated             , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Institutional Income Fund VII-B. The purpose of the special meeting is for you to vote upon the merger of Institutional Income Fund VII-B with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Institutional Income Fund VII-B is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on             .

This document contains the following information concerning Institutional Income Fund VII-B:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Institutional Income Fund VII-B

• Compensation and distributions from Institutional Income Fund VII-B

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

— the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Institutional Income Fund VII-B for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Institutional Income Fund VII-B’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Institutional Income Fund VII-B as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Institutional Income Fund VII-B, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Institutional Income Fund VII-B in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Income Fund VII-B’s assets. The Merger Value of Institutional Income Fund VII-B is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Institutional Income Fund VII-B, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Institutional Income Fund VII-B by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Institutional Income Fund VII-B. We believe, however, that Institutional Income Fund VII-B will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Institutional Income Fund VII-B. Our decision is based on the following factors in order of significance:

• Our method of valuation for Institutional Income Fund VII-B uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Institutional Income Fund VII-B, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Institutional Income Fund VII-B. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INSTITUTIONAL INCOME FUND VII-B

The Merger Value for Institutional Income Fund VII-B was determined by calculating its Net Asset Value and then dividing Institutional Income Fund VII-B’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Institutional Income Fund VII-B’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Institutional Income Fund VII-B’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Institutional Income Fund VII-B. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund VII-B is 5.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Institutional Income Fund VII-B
		Net Present Value of Reserves	$	3,805,167.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	175,534.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Institutional Income Fund VII-B	$	3,980,701.00	calculated

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					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Institutional Income Fund VII-B	$	3,980,701.00	calculated
	less	GP% owned by Southwest in Institutional Income Fund VII-B (10%)	$	398,070.10	Partnership records
	less	LP% owned by Southwest in Institutional Income Fund VII-B (26.21%)	$	1,043,341.73	Partnership records
	equals	Net Asset Value of Institutional Income Fund VII-B owned by limited partners (excluding Southwest’s ownership %)	$	2,539,289.17	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,378.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Institutional Income Fund VII-B (excluding Southwest’s ownership %)	$	2,539,289.17	calculated
	equals	The percentage of ownership of Institutional Income Fund VII-B (other than Southwest) to the total Net Asset Value		3.23%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Institutional Income Fund VII-B (other than Southwest)		3.23%	calculated
	equals	The number of shares of common stock attributable to Institutional Income Fund VII-B (other than to Southwest)		54,613.79	calculated
(7)		The number of shares of common stock attributable to Institutional Income Fund VII-B (other than to Southwest)		54,614	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund VII-B		10,633	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund VII-B		5	calculated
(8)		The number of shares of special stock attributable to Institutional Income Fund VII-B (other than to Southwest)		10,923	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) of Institutional Income Fund VII-B		10,633	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Institutional Income Fund VII-B		1.03	calculated

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As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Institutional Income Fund VII-B for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	108,000	$	108,000	$	108,000	$	54,000
Administrative Overhead per Operating Agreements	$	19,802	$	19,390	$	19,394	$	10,007
Cash Distributions Paid to General Partners as General Partners(1)	$	72,673	$	58,718	$	33,000	$	30,000
Cash Distributions Paid to General Partner as Limited Partner	$	151,704	$	99,299	$	39,523	$	78,625

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is the table showing the cash distributions to Institutional Income Fund VII-B’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	654,056	$	528,465	$	311,786	$	296,953	$	501,300	$	270,000

Return of Capital: 100%; Return on Capital: 33%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

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SUPPLEMENTAL INFORMATION TABLE FOR INSTITUTIONAL INCOME FUND VII-B

Aggregate Initial Investment by the Limited Partners:	$	7,500	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	10,000	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	3,583	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	238.84	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		7.2	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	93.86	(2)(4)
—as of December 31, 2001:	$	96.34	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	152.10	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	112.27	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002: $200.71(2)(7)	$	200.71	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Institutional Income Fund VII-B is equal to (1) the sum of (A) the present value of estimated future net revenues from Institutional Income Fund VII-B’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Institutional Income Fund VII-B is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Institutional Income Fund VII-B is based upon (1) the sum of (A) the estimated net cash flow from the sale of Institutional Income Fund VII-B’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Institutional Income Fund VII-B’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Institutional Income Fund VII-B is based upon (1) the sum of (A) the sale of Institutional Income Fund VII-B’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Institutional Income Fund VII-B’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Institutional Income Fund VII-B and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Institutional Income Fund VII-B is based upon (1) the sum of (A) Institutional Income Fund VII-B’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Institutional Income Fund VII-B.

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INSTITUTIONAL INCOME FUND VII-B

Set forth below is basic information about Institutional Income Fund VII-B and its business and operations. It does not contain all the information about Institutional Income Fund VII-B that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Institutional Income Fund VII-B

General

Institutional Income Fund VII-B was organized as a Delaware limited partnership on January 28, 1987. The offering of limited partner interests began March 23, 1987, reached minimum capital requirements May 20, 1987, and concluded December 1, 1987, with a total partner contribution of $7.5 million.

Principal Products, Marketing and Distribution

Institutional Income Fund VII-B has acquired and holds royalty, overriding royalty and net profit interests in oil and gas properties located in Texas, New Mexico, Oklahoma and Louisiana.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	72%	28%
2000	73%	27%
1999	74%	26%

As the table indicates, the majority of Institutional Income Fund VII-B’s revenue is from its oil production.

Customer Dependence

No material portion of Institutional Income Fund VII-B’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Institutional Income Fund VII-B. Four purchasers accounted for 66% of Institutional Income Fund VII-B’s total oil and gas production during 2001: Equiva Trading Company for 23%, Duke Energy Field Services for 21%, BP Amoco for 11% and Plains All American Pipeline, L.P. for 11%. Four purchasers accounted for 77% of Institutional Income Fund VII-B’s total oil and gas production during 2000: Phillips 66 Natural Gas Co. for 28%, Equiva Trading Company for 19%, BP Amoco for 17% and Plains All American Pipeline, L.P. for 13%. Four purchasers accounted for 74% of Institutional Income Fund VII-B’s total oil and gas production during 1999: Phillips 66 Natural Gas Co. for 27%, Equiva Trading Company for 19%, Amoco Production for 17% and Scurlock Permian LLC. for 11%. All purchasers of Institutional Income Fund VII-B’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Institutional Income Fund VII-B’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Institutional Income Fund VII-B’s sales of oil and gas production.

Properties

As of December 31, 2001, Institutional Income Fund VII-B possessed an interest in oil and gas properties located in Cameron Parish, Louisiana; Eddy and Lea Counties, New Mexico; Caddo, Garvin, Leflore, McClain and Pottawatomie Counties, Oklahoma; and Andrews, Dawson, Ector, Fisher, Gaines, Garza, Hale, Hockley, Howard, Lamb, Leon, Loving, Martin, Midland, Pecos, Rusk, Scurry, Stonewall, Tom Green, Upton, Ward and Winkler Counties, Texas. These properties consist of various interests in approximately 2,650 wells and units.

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There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

Significant Properties

The following table reflects the significant properties in which Institutional Income Fund VII-B has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
El Mar Delaware Unit Acquisition Loving County, Texas	12/88 at 13% to 100% net profits interest	63	147,000	—
Mobil Acquisition Pecos and Upton Counties, Texas	10/88 at 2% to 16% net profits interest	9	4,000	477,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Institutional Income Fund VII-B’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.99 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.21 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VII-B” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Institutional Income Fund VII-B Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Institutional Income Fund VII-B has reserves, which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate Institutional Income Fund VII-B’s present reserves.

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Because Institutional Income Fund VII-B does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Institutional Income Fund VII-B retains a carried interest under the terms of a farm-out or receives cash.

Institutional Income Fund VII-B or the owners of properties in which Institutional Income Fund VII-B owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VII-B” in this prospectus supplement.

Market for Institutional Income Fund VII-B’s Limited Partnership Interests and Related Matters

Market Information

After completion of Institutional Income Fund VII-B’s first full fiscal year of operations and each year thereafter, the managing general partner has offered and will continue to offer to purchase each limited partner’s interest in Institutional Income Fund VII-B, at a price based on tangible assets of Institutional Income Fund VII-B, plus the net present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the managing general partner. However, the managing general partner’s obligation to purchase limited partner interests is limited to an expenditure of an amount not in excess of 10% of the total limited partner interest initially subscribed for by limited partners. In 2001, 1,361 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $223.82 per unit. In 2000, 1,063 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $121.97 per unit. In 1999, 203 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $63.70 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 718 holders of limited partner interest in Institutional Income Fund VII-B.

Distributions

Pursuant to Article IV, Section 4.01 of Institutional Income Fund VII-B’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Institutional Income Fund VII-B’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Institutional Income Fund VII-B], as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $726,729, with $654,056 distributed to the limited partners and $72,673 to the general partners. For the year ended December 31, 2001, distributions of $43.60 per unit of limited partner interest were made, based upon 15,000 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $587,183, with $528,465 distributed to the limited partners and $58,718 to the general partners. For the year ended December 31, 2000, distributions of $35.23 per unit of limited partner interest were made, based upon 15,000 units of limited partner interest outstanding. During 1999, distributions were made totaling $344,786, with $311,786 distributed to the limited partners and $33,000 to the general partners. For the year ended December 31, 1999, distributions of $20.79 per unit of limited partner interest were made, based upon 15,000 units of limited partner interest outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA  FOR INSTITUTIONAL INCOME FUND VII-B

The following tables present summary selected financial information and operating data for Institutional Income Fund VII-B for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VII-B” found elsewhere in this prospectus supplement and the financial statements and related notes for Institutional Income Fund VII-B included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	452,586		540,016		929,791		1,124,532		708,827		617,201		974,830
Net income (loss)	258,621		313,510		473,239		696,586		316,929		(31,771	)	329,872
Partners’ share of net income (loss):
General partners	25,862		31,351		47,324		69,659		31,693		(3,177	)	32,987
Partners	232,759		282,159		425,915		626,927		285,236		(28,594	)	296,885
Partners’ net income (loss) per unit of limited partner interest	15.52		18.81		28.39		41.80		19.02		(1.91	)	19.79
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	234,729		418,920		689,042		680,921		306,020		284,200		569,833
Net cash provided by investing activities	—		100		60		—		14,933		101,801		556
Net cash used in financing activities	(300,690	)	(474,763	)	(726,896	)	(586,961	)	(345,307	)	(323,960	)	(556,614	)
Net increase (decrease) in cash and cash equivalents	(65,961	)	(55,743	)	(37,794	)	93,960		(24,354	)	62,041		13,775
EBITDA	286,621		357,510		570,239		758,586		399,929		205,229		540,872
Cash distributions	300,000		475,000		726,729		587,183		344,786		323,953		557,000
Partners’ cash distributions per $500 investment	18.00		28.50		43.60		35.23		20.79		19.80		33.42
Balance Sheet Data:
Cash and cash equivalents	52,046		100,058		118,007		155,801		61,841		86,195		24,154
Oil and gas properties, net at book value	679,965		760,925		707,965		805,025		867,025		964,958		1,303,759

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	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Total assets	855,499		989,816		897,412		1,151,069		1,041,444		1,069,822		1,425,553
Total liabilities	—		938		534		701		479		1,000		1,007
Partners’ equity	1,407,844		1,527,885		1,445,085		1,673,226		1,574,764		1,601,314		1,926,861
General partners’ equity	(552,345	)	(539,007	)	(548,207	)	(522,858	)	(533,799	)	(532,492	)	(502,315	)
Partner’s book value per $500 investment	93.86		101.86		96.34		111.55		104.98		106.75		128.46
Production:
Oil production (Bbls)	14,400		13,800		28,400		28,700		29,920		35,800		38,400
Natural gas production (Mcf)	52,600		33,600		65,800		73,600		81,520		83,200		93,800
Equivalent production (Boe)	23,167		19,400		39,367		40,967		43,507		49,667		54,033
Average Sales Price:
Oil price (per/Bbl)	22.04		26.56		23.72		28.69		17.53		12.70		19.47
Natural gas price (per/Mcf)	2.57		5.16		3.89		4.09		2.26		1.95		2.42
Average sales price (per Boe)	19.54		27.84		23.62		27.45		16.29		12.43		18.04
Operating and Overhead Costs (per Boe)
Lease operating expense	3.81		4.94		4.90		4.58		3.61		5.02		4.85
Production taxes	1.21		1.68		1.45		1.69		.97		.73		1.07
General and Administrative Expense (per Boe)	2.45		2.97		2.93		2.86		2.60		2.64		2.21
Total	7.47		9.59		9.28		9.13		7.18		8.39		8.13
Cash Operating Margin (per Boe)	12.07		18.25		14.34		18.32		9.11		4.04		9.91
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.21		2.27		2.46		1.51		1.91		4.78		3.91
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	723,000		937,000		712,000		926,000		862,000		672,000		655,000
Oil (Bbls)	367,000		275,000		313,000		217,000		237,000		148,000		284,000
Total (Boe)	488,000		431,000		432,000		371,000		381,000		260,000		393,000

⁽¹⁾ Institutional Income Fund VII-B has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value		$3,981,000
Merger Value per $500 investment	$	238.84

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

11

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VII-B, L.P.

General

Based on current conditions, management anticipates performing workovers during 2002 to enhance production. Institutional Income Fund VII-B may have an increase in production volumes for the year 2002, otherwise, Institutional Income Fund VII-B will likely experience the historical production decline of approximately 8% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.61	$	25.85	(5	%)
Average price per Mcf of gas	$	3.02	$	4.23	(29	%)
Oil production in barrels		7,000		6,900	1	%
Gas production in Mcf		29,800		14,800	101	%
Income from net profits interests	$	199,085	$	193,208	3	%
Institutional Income Fund VII-B distributions	$	150,000	$	225,000	(33	%)
Limited partner distributions	$	135,000	$	202,500	(33	%)
Per unit distribution to limited partners	$	9.00	$	13.50	(33	%)
Number of limited partner interests		15,000		15,000

Revenues

Institutional Income Fund VII-B’s income from net profits interests increased to $199,085 from $193,208 for the quarters ended June 30, 2002 and 2001, respectively, an increase of 3%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund VII-B decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 5%, or $1.24 per barrel, resulting in a decrease of approximately $8,700 in income from net profits interests. Oil sales represented 66% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 74% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund VII-B decreased during the same period by 29%, or $1.21 per Mcf, resulting in a decrease of approximately $36,100 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $44,800. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 100 barrels, or 1%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in an increase of approximately $2,600 in income from net profits interests.

Gas production increased approximately 15,000 Mcf, or 101%, during the same period, resulting in an increase of approximately $63,500 in income from net profits interests.

12

The total increase in income from net profits interests due to the change in production is approximately $66,100. The increase in gas production is due to an adjustment of gas balancing for a non-operated lease.

3.  Lease operating costs and production taxes increased 3%, or approximately $1,900, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $44,005 from $50,162 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 12%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 4%, or approximately $1,200, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $16,000 for the quarter ended June 30, 2002 from $21,000 for the same period in 2001. This represents a decrease of 24%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VII-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund VII-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.04	$	26.56	(17	%)
Average price per Mcf of gas	$	2.57	$	5.16	(50	%)
Oil production in barrels		14,400		13,800	4	%
Gas production in Mcf		52,600		33,600	57	%
Income from net profits interests	$	336,502	$	411,536	(18	%)
Institutional Income Fund VII-B distributions	$	300,000	$	475,000	(37	%)
Limited partner distributions	$	270,000	$	427,500	(37	%)
Per unit distribution to limited partners	$	18.00	$	28.50	(37	%)
Number of limited partner interests		15,000		15,000

Revenues

Institutional Income Fund VII-B’s income from net profits interests decreased to $336,502 from $411,536 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 18%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund VII-B decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 17%, or $4.52 per barrel, resulting in a decrease of approximately $65,100 in income from net profits interests. Oil sales represented 70% of total oil and gas sales during the six months ended June 30, 2002 as compared to 68% during the six months ended June 30, 2001.

13

The average price for an Mcf of gas received by Institutional Income Fund VII-B decreased during the same period by 50%, or $2.59 per Mcf, resulting in a decrease of approximately $136,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $201,300. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 600 barrels, or 4%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in an increase of approximately $15,900 in income from net profits interests.

Gas production increased approximately 19,000 Mcf, or 57%, during the same period, resulting in an increase of approximately $98,000 in income from net profits interests.

The total increase in income from net profits interests due to the change in production is approximately $113,900. The increase in gas production is due to an adjustment of gas balancing for a non-operated lease.

3.  Lease operating costs and production taxes decreased 10%, or approximately $12,400, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $84,648 from $101,610 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 17%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $1,000, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $28,000 for the six months ended June 30, 2002 from $44,000 for the same period in 2001. This represents a decrease of 36%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VII-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund VII-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	23.72	$	28.69	(17	%)
Average price per Mcf of gas	$	3.89	$	4.09	(5	%)
Oil production in barrels		28,400		28,700	(1	%)
Gas production in Mcf		65,800		73,600	(11	%)
Income from net profits interests	$	679,787	$	867,334	(22	%)
Institutional Income Fund VII-B distributions	$	726,729	$	587,183	24	%
Limited partner distributions	$	654,056	$	528,465	24	%
Per unit distribution to limited partners	$	43.60	$	35.23	24	%
Number of limited partner interests		15,000	$	15,000

14

Revenues

Institutional Income Fund VII-B’s income from net profits interests decreased to $679,787 from $867,334 for the years ended December 31, 2001 and 2000, respectively, a decrease of 22%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by the Partnership decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 17%, or $4.97 per barrel, resulting in a decrease of approximately $141,100 in income from net profits interests. Oil sales represented 72% of total oil and gas sales during the year ended December 31, 2001 as compared to 73% during the year ended December 31, 2000.

The average price for an Mcf of gas received by the Partnership decreased during the same period by 5%, or $.20 per Mcf, resulting in a decrease of approximately $13,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $154,300. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 300 barrels, or 1%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $8,600 in income from net profits interests.

Gas production decreased approximately 7,800 Mcf, or 11%, during the same period, resulting in a decrease of approximately $31,900 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $40,500.

3.  Lease operating costs and production taxes decreased 3%, or approximately $7,200, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

Costs and Expenses

Total costs and expenses increased to $212,165 from $179,165 for the years ended December 31, 2001 and 2000, respectively, an increase of 18%. The increase is the result of higher depletion expense, partially offset by a decrease in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $2,000, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $97,000 for the year ended December 31, 2001 from $62,000 for the same period in 2000. This represents an increase of 56%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VII-B’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Institutional Income Fund VII-B’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Institutional Income Fund VII-B during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $7,000 as of December 31, 2000.

15

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.69	$	17.53	64	%
Average price per Mcf of gas	$	4.09	$	2.26	81	%
Oil production in barrels		28,700		29,920	(4	%)
Gas production in Mcf		73,600		81,520	(10	%)
Income from net profits interests	$	867,334	$	509,251	70	%
Institutional Income Fund VII-B distributions	$	587,183	$	344,786	70	%
Partner distributions	$	528,465	$	311,786	70	%
Per unit distribution to partners	$	35.23	$	19.80	78	%
Number of partner interests		15,000		15,000

Revenues

Institutional Income Fund VII-B’s income from net profits interests increased to $867,334 from $509,251 for the years ended December 31, 2000 and 1999, respectively, an increase of 70%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund VII-B increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 64%, or $11.16 per barrel, resulting in an increase of approximately $320,300 in income from net profits interests. Oil sales represented 73% of total oil and gas sales during the year ended December 31, 2000 as compared to 74% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Institutional Income Fund VII-B increased during the same period by 81%, or $1.83 per Mcf, resulting in an increase of approximately $134,700 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $455,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,220 barrels, or 4%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $21,400 in income from net profits interests.

Gas production decreased approximately 7,920 Mcf, or 10%, during the same period, resulting in a decrease of approximately $17,900 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $39,300.

3.  Lease operating costs and production taxes increased 29%, or approximately $57,600, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to one lease having major repairs and maintenance such as downhole well repairs, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Institutional Income Fund VII-B to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

16

Costs and Expenses

Total costs and expenses decreased to $179,165 from $196,122 for the years ended December 31, 2000 and 1999, respectively, a decrease of 9%. The decrease is the result of higher general and administrative expense, partially offset by a decrease in depletion expense.

1.  General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 4%, or approximately $4,000, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $62,000 for the year ended December 31, 2000 from $83,000 for the same period in 1999. This represents a decrease of 25%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VII-B’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Institutional Income Fund VII-B’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $9,000 as of December 31, 1999.

Revenue and Distribution Comparison

Institutional Income Fund VII-B net income for the years ended December 31, 2001, 2000 and 1999 was $473,239, $696,586 and $316,929, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $570,239, $758,586 and $399,929, respectively. Correspondingly, Institutional Income Fund VII-B distributions for the years ended December 31, 2001, 2000 and 1999 were $726,729, $587,183 and $344,786, respectively. These differences are indicative of the changes in oil and gas prices, production and property during 2001, 2000 and 1999.

The sources of the 2001 distributions of $726,729 were oil and gas operations of approximately $689,000 and the change in oil and gas properties of approximately $100, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $587,200 were oil and gas operations of approximately $680,921, resulting in excess cash for contingencies or subsequent distributions. The source for the 1999 distributions of $344,786 was oil and gas operations of approximately $306,020 and the change in oil and gas properties of approximately $14,900, with the balance from available cash on hand at the beginning of the period.

Total distributions during the year ended December 31, 2001 were $726,729 of which $654,056 was distributed to the limited partners and $72,673 to the general partners. The per unit distribution to limited partners during the same period was $43.60. Total distributions during the year ended December 31, 2000 were $587,183 of which $528,465 was distributed to the limited partners and $58,718 to the general partners. The per unit distribution to limited partners during the same period was $35.23. Total distributions during the year ended December 31, 1999 were $344,786 of which $311,786 was distributed to the limited partners and $33,000 to the general partners. The per unit distribution to limited partners during the same period was $20.79.

Liquidity and Capital Resources of Institutional Income Fund VII-B

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Institutional Income Fund VII-B knows of no material change, nor does it anticipate any such change.

17

Cash flows provided by operating activities were approximately $234,700 in the six months ended June 30, 2002 as compared to approximately $418,900 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

There were no cash flows provided by investing activities in the six months ended June 30, 2002. Cash flows provided by investing activities were approximately $100 in the six months ended June 30, 2001.

Cash flows used in financing activities were approximately $300,700 in the six months ended June 30, 2002 as compared to approximately $474,800 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $300,000 of which $270,000 was distributed to the limited partners and $30,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2002 was $18.00. Total distributions during the six months ended June 30, 2001 were $475,000 of which $427,500 was distributed to the limited partners and $47,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $28.50.

The source for the 2002 distributions of $300,000 was oil and gas operations of approximately $234,700, with the balance from available cash on hand at the beginning of the period. The source for the 2001 distributions of $475,000 was oil and gas operations of approximately $418,900 and the change in oil and gas properties of approximately $100, with the balance from available cash on hand at the beginning of the period.

Since inception of Institutional Income Fund VII-B, cumulative monthly cash distributions of $11,094,295 have been made to the partners. As of June 30, 2002, $9,999,776 or $666.65 per limited partner unit has been distributed to the limited partners, representing a 133% return of the capital contributed.

As of June 30, 2002, Institutional Income Fund VII-B had approximately $175,500 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Institutional Income Fund VII-B.

Cash flows provided by operating activities were approximately $689,000 in 2001 compared to $680,900 in 2000 and approximately $306,000 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows provided by investing activities were approximately $100 in 2001. Institutional Income Fund VII-B had no cash flows from investing activities in 2000. Cash flows provided by investing activities were approximately $14,900 in 1999.

Cash flows used in financing activities were approximately $726,900 in 2001 compared $587,000 in 2000 and approximately $345,300 in 1999. The only use in financing activities was the distributions to partners.

18

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST OIL & GAS INCOME FUND VIII-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Oil & Gas Income Fund VIII-A, L.P., which we call Oil & Gas Income Fund VIII-A, and supplements the prospectus/proxy statement dated                     , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Oil & Gas Income Fund VIII-A. The purpose of the special meeting is for you to vote upon the merger of Oil & Gas Income  Fund VIII-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Oil & Gas Income Fund VIII-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                     .

This document contains the following information concerning Oil & Gas Income Fund VIII-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Oil & Gas Income Fund VIII-A

• Compensation and distributions from Oil & Gas Income Fund VIII-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Oil & Gas Income Fund VIII-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Oil & Gas Income Fund VIII-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Oil & Gas Income Fund VIII-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Oil & Gas Income Fund VIII-A, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Oil & Gas Income Fund VIII-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Oil & Gas Income Fund VIII-A’s assets. The Merger Value of Oil & Gas Income Fund VIII-A is based upon a formula to allocate shares of common stock and does not constitute a market value of our stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Oil & Gas Income Fund VIII-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Oil & Gas Income Fund VIII-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Oil & Gas Income Fund VIII-A. We believe, however, that Oil & Gas Income Fund VIII-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Oil & Gas Income Fund VIII-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Oil & Gas Income Fund VIII-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Oil & Gas Income Fund VIII-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Oil & Gas Income Fund VIII-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger in the prospectus/proxy statement.”

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR OIL & GAS INCOME FUND VIII-A

The Merger Value for Oil & Gas Income Fund VIII-A was determined by calculating its Net Asset Value and then dividing Oil & Gas Income Fund VIII-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Oil & Gas Income Fund VIII-A’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Oil & Gas Income Fund VIII-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Oil & Gas Income Fund VIII-A. As indicated below, the number of shares of common stock issuable per each unit of Oil & Gas Income Fund VIII-A is 3.

3

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Oil & Gas Income Fund VIII-A
		Net Present Value of Reserves	$	2,064,463.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	142,448.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Oil & Gas Income Fund VIII-A	$	2,206,911.00	calculated
(2)		Net Asset Value of Oil & Gas Income Fund VIII-A	$	2,206,911.00	calculated
	less	GP% owned by Southwest in Oil & Gas Income Fund VIII-A (10%)	$	220,691.10	Partnership records
	less	LP% owned by Southwest in Oil & Gas Income Fund VIII-A (21.81%)	$	481,327.29	Partnership records
	equals	Net Asset Value of Oil & Gas Income Fund VIII-A owned by limited partners (excluding Southwest’s ownership %)	$	1,504,892.61	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,378.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,378.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Oil & Gas Income Fund VIII-A (excluding Southwest’s ownership %)	$	1,504,892.61	calculated
	equals	The percentage of ownership of Oil & Gas Income Fund VIII-A (other than Southwest) to the total Net Asset Value		1.92%	calculated

4

				Document(s) from which information was obtained or calculated
(5)		Total Southwest shares of Class A common stock and common stock issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Oil & Gas Income Fund VIII-A (other than Southwest)	1.92%	calculated
	equals	The number of shares of common stock attributable to Oil & Gas Income Fund VIII-A	32,366.49	calculated
(7)		The number of shares of common stock attributable to Oil & Gas Income Fund VIII-A (other than to Southwest)	32,366	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Oil & Gas Income Fund VIII-A	10,302	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund VIII-A	3	calculated
(8)		The number of shares of special stock attributable to Oil & Gas Income Fund VIII-A (other than to Southwest)	6,473	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Oil & Gas Income Fund VIII-A	10,302	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Oil & Gas Income Fund VIII-A	.63	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Oil & Gas Income Fund VIII-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	98,400	$	98,400	$	98,400	$	49,200
Administrative Overhead per Operating Agreements	$	139,057	$	135,107	$	131,416	$	68,019
Cash Distributions Paid to General Partners as General Partners(1)	$	62,006	$	61,544	$	12,000	$	3,200
Cash Distributions Paid to General Partner as Limited Partner	$	107,949	$	88,332	$	15,470	$	6,980

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is the table showing the cash distributions to Oil & Gas Income Fund VIII-A’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	558,057	$	553,896	$	146,801	$	152,519	$	581,400	$	28,880

Return of Capital: 100%; Return on Capital: 13%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR OIL & GAS INCOME FUND VIII-A

Aggregate Initial Investment by the Limited Partners:	$	6,798	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	7,651	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest	$	1,986	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002	$	146.09	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002		9.7	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	34.39	(2)(4)
—as of December 31, 2001:	$	30.06	(2)(4)
Going Concern Value per $500 Limited Partner Investment of June 30, 2002	$	9.98	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002	$	113.62	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	120.67	(2)(7)

⁽¹⁾ Stated in thousands.

6

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Oil & Gas Income Fund VIII-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Oil & Gas Income Fund VIII-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Oil & Gas Income Fund VIII-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interests sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Oil & Gas Income Fund VIII-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Oil & Gas Income Fund VIII-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Oil & Gas Income Fund VIII-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Oil & Gas Income Fund VIII-A is based upon (1) the sum of (A) the sale of Oil & Gas Income Fund VIII-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Oil & Gas Income Fund VIII-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Oil & Gas Income Fund VIII-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Oil & Gas Income Fund VIII-A is based upon (1) the sum of (A) Oil & Gas Income Fund VIII-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Oil & Gas Income Fund VIII-A.

OIL & GAS INCOME FUND VIII-A

Set forth below is basic information about Oil & Gas Income Fund VIII-A and its business and operations. It does not contain all the information about Oil & Gas Income Fund VIII-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Oil & Gas Income Fund VIII-A

General

Oil & Gas Income Fund VIII-A was organized as a Delaware limited partnership on November 30, 1987. The offering of limited partner interests began March 31, 1988, minimum capital requirements were met July 6, 1988 and the offering concluded March 31, 1989, with total limited partner contributions of $6.798 million.

7

Principal Products, Marketing and Distribution

Oil & Gas Income Fund VIII-A has acquired and holds working interests in oil and gas properties located in New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	80%	20%
2000	83%	17%
1999	82%	18%

As the table indicates, the majority of Oil & Gas Income Fund VIII-A’s revenue is from its oil production.

Customer Dependence

No material portion of Oil & Gas Income Fund VIII-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Oil & Gas Income  Fund VIII-A Three purchasers accounted for 78% of Oil & Gas Income Fund VIII-A’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 58%, ExxonMobil for 10% and Duke Energy Field Services for 10%. Two purchasers accounted for 81% of Oil & Gas Income Fund VIII-A’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 60% and ExxonMobil for 21%. Two purchasers accounted for 75% of Oil & Gas Income Fund VIII-A’s total oil and gas production during 1999: Scurlock Permian LLC for 54% and ExxonMobil for 21%. All purchasers of Oil & Gas Income Fund VIII-A’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Oil & Gas Income Fund VIII-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Oil & Gas Income Fund VIII-A’s sales of oil and gas production.

Properties

As of December 31, 2001, Oil & Gas Income Fund VIII-A possessed an interest in oil and gas properties located in Eddy County, New Mexico and Glasscock, Leon, Martin, Pecos, Reagan, Reeves, Stonewall, Terry, Ward, Winkler and Yoakum Counties, Texas. These properties consist of various interests in approximately 102 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999 other than ordinary production declines and reserve depletion.

During 2001, three leases were sold for approximately $200. There were no leases sold during 2000. During 1999, one lease was sold for approximately $27,750.

8

Significant Properties

The following table reflects the significant properties in which Oil & Gas Income Fund VIII-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Mobil Acquisition Ward and Reeves Counties, Texas	4/89 at 5% to 50% working interest	19	65,000	128,000
North American Royalties Yoakum County, Texas	3/89 at 50% working interest	3	146,000	—
Ramsey-Sell Acquisition Winkler County, TX	3/89 at 11% to 52% working interest	5	74,000	21,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Oil & Gas Income Fund VIII-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.92 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.58 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VIII-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Oil & Gas Income Fund VIII-A. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Oil & Gas Income Fund VIII-A has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Oil & Gas Income Fund VIII-A’s present reserves.

9

Because Oil & Gas Income Fund VIII-A does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Oil & Gas Income Fund VIII-A retains a carried interest under the terms of a farm-out, or receives cash.

Oil & Gas Income Fund VIII-A or the owners of properties in which Oil & Gas Income Fund VIII-A owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VIII-A” in this prospectus supplement.

Market for Oil & Gas Income Fund VIII-A’s Limited Partnership Interests and Related Matters

Market Information

After completion of Oil & Gas Income Fund VIII-A’s first full fiscal year of operations and each year thereafter, the managing general partner has offered and will continue to offer to purchase each limited partner’s interest in Oil & Gas Income Fund VIII-A, at a price based on tangible assets of Oil & Gas Income Fund VIII-A, plus the net present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the managing general partner. However, the managing general partner’s obligation to purchase limited partner interests is limited to an expenditure of an amount not in excess of 10% of the total limited partner interests initially subscribed for by limited partners. In 2001, 957 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $256.07 per unit. In 2000, 900.25 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $128.82 per unit. In 1999, 64 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $24.98 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 518 holders of limited partner interest in Oil & Gas Income  Fund VIII-A.

Distributions

Pursuant to Article IV, Section 4.01 of Oil & Gas Income Fund VIII-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Oil & Gas Income Fund VIII-A’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Oil & Gas Income Fund VIII-A], as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $620,063, with $558,057 distributed to the limited partners and $62,006 to the general partners. For the year ended December 31, 2001, distributions of $41.05 per unit of limited partner interest were made, based upon 13,596 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $615,440, with $553,896 distributed to the limited partners and $61,544 to the general partners. For the year ended December 31, 2000, distributions of $40.74 per unit of limited partner interest were made, based upon 13,596 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $158,801, with $146,801 distributed to the limited partners and $12,000 to the general partners. For the year ended December 31, 1999, distributions of $10.80 per unit of limited partner interest were made, based upon 13,596 units of limited partner interest outstanding.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

OIL & GAS INCOME FUND VIII-A

The following tables present summary selected financial information and operating data for Oil & Gas Income Fund VIII-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VIII-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Oil & Gas Income Fund VIII-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	486,875		743,238		1,290,533		1,537,038		952,972		887,710		1,466,069
Net income (loss)	98,880		355,327		421,668		713,495		246,697		(715,201	)	273,412
Partners’ share of net income (loss):
General partners	11,188		37,333		46,667		73,549		26,969		(1,184	)	50,541
Partners	87,692		317,994		375,001		639,946		219,728		(714,017	)	222,871
Partners’ net income (loss) per unit of limited partner interest	6.45		23.39		27.58		47.07		16.16		(52.52	)	16.39
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	70,337		384,703		582,809		692,527		161,355		105,534		590,938
Net cash provided by investing activities	(34,220	)	(34,198	)	(37,440	)	(8,370	)	19,442		81,497		1,472
Net cash used in financing activities	(32,094	)	(425,060	)	(619,921	)	(615,511	)	(158,740	)	(168,466	)	(645,585	)
Net increase (decrease) in cash and cash equivalents	4,023		(74,555	)	(74,552	)	68,646		22,057		18,565		(53,175	)
EBITDA	111,880		373,327		466,668		735,495		269,697		(11,844	)	505,412
Cash distributions	32,000		425,000		620,063		615,440		158,801		167,969		646,000
Partners’ cash distributions per $500 investment	2.12		28.13		41.05		40.74		10.80		11.22		42.76

11

	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998		1997
Balance Sheet Data:
Cash and cash equivalents	41,408	37,382	37,385	111,937	43,291	21,234		2,669
Oil and gas properties, net at book value	338,479	341,017	317,259	324,819	338,449	380,891		1,125,506
Total assets	481,154	542,888	414,368	612,621	514,637	426,680		1,310,347
Total liabilities	227	119	321	179	250	189		686
Partners’ equity	467,533	527,191	408,641	591,697	505,647	432,720		1,299,256
General partners’ equity	13,394	15,578	5,406	20,745	8,740	(6,229	)	10,405
Partner’s book value per $500 investment	34.39	38.78	30.06	43.52	37.19	31.83		95.56
Production:
Oil production (Bbls)	19,300	21,700	43,100	44,600	45,990	57,100		64,807
Natural gas production (Mcf)	23,500	29,400	59,600	58,900	67,990	79,500		91,776
Equivalent production (Boe)	23,217	26,600	53,033	54,417	57,322	70,350		80,103
Average Sales Price:
Oil price (per/Bbl)	21.79	26.50	24.02	28.70	17.07	12.68		19.01
Natural gas price (per/Mcf)	2.82	5.72	4.28	4.36	2.47	2.06		2.55
Average sales price (per Boe)	20.97	27.94	24.33	28.25	16.62	12.61		18.30
Operating and Overhead Costs (per Boe)
Lease operating expense	12.96	10.57	12.39	11.50	9.37	10.48		9.79
Production taxes	1.00	1.46	1.23	1.46	.76	.64		.89
General and Administrative Expense (per Boe)	2.22	1.98	1.99	1.95	1.81	1.69		1.36
Total	16.18	14.01	15.61	14.91	11.94	12.81		12.04
Cash Operating Margin (per Boe)	4.79	13.93	8.72	13.34	4.68	(.20	)	6.26
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.56	.68	.85	.40	.40	10.00		2.90
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	331,000	537,000	368,000	912,000	1,122,000	189,000		509,000
Oil (Bbls)	434,000	493,000	341,000	535,000	475,000	156,000		369,000
Total (Boe)	489,000	583,000	402,000	687,000	662,000	188,000		454,000

⁽¹⁾ Oil & Gas Income Fund VIII-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	2,207,000
Merger Value per $500 investment	$	146.09

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND VIII-A

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Workovers may be performed in the year 2004. Oil & Gas Income Fund VIII-A will likely experience the historical production decline of approximately 9% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.94	$	26.03	(8	%)
Average price per Mcf of gas	$	3.25	$	4.65	(30	%)
Oil production in barrels		9,000		10,700	(16	%)
Gas production in Mcf		12,300		13,900	(12	%)
Gross oil and gas revenue	$	255,475	$	349,457	(27	%)
Net oil and gas revenue	$	86,121	$	166,496	(48	%)
Oil & Gas Income Fund VIII-A distributions	$	—	$	150,000	(100	%)
Limited partner distributions	$	—	$	135,000	(100	%)
Per unit distribution to limited partners	$	—	$	9.93	(100	%)
Number of limited partner interests		13,596		13,596

Revenues

Oil & Gas Income Fund VIII-A’s oil and gas revenues decreased to $255,475 from $349,457 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 27%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VIII-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 8%, or $2.09 per barrel, resulting in a decrease of approximately $18,800 in revenues. Oil sales represented 84% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 81% during the quarter ended June 30, 2001.

The average price for a Mcf of gas received by Oil & Gas Income Fund VIII-A decreased during the same period by 30%, or $1.40 per Mcf, resulting in a decrease of approximately $17,200 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $36,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,700 barrels, or 16%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $44,300 in revenues.

Gas production decreased approximately 1,600 Mcf, or 12%, during the same period, resulting in a decrease of approximately $7,400 in revenues.

The total decrease in revenues due to the change in production is approximately $51,700. The decrease in oil production is due primarily to downtime on one lease during the quarter ended June 30, 2002.

13

Costs and Expenses

Total costs and expenses decreased to $201,882 from $219,778 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 8%. The decrease is the result of lower depletion expense, lease operating costs and general and administrative expense.

1.  Lease operating costs and production taxes decreased 7%, or approximately $13,600, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 5%, or approximately $1,300, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $7,000 for the quarter ended June 30, 2002 from $10,000 for the same period in 2001. This represents a decrease of 30%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VIII-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund VIII-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.79	$	26.50	(18	%)
Average price per Mcf of gas	$	2.82	$	5.72	(51	%)
Oil production in barrels		19,300		21,700	(11	%)
Gas production in Mcf		23,500		29,400	(20	%)
Gross oil and gas revenue	$	486,875	$	743,238	(34	%)
Net oil and gas revenue	$	162,977	$	423,163	(61	%)
Oil & Gas Income Fund VIII-A distributions	$	32,000	$	425,000	(92	%)
Limited partner distributions	$	28,800	$	382,500	(92	%)
Per unit distribution to limited partners	$	2.12	$	28.13	(92	%)
Number of limited partner interests		13,596		13,596

Revenues

Oil & Gas Income Fund VIII-A’s oil and gas revenues decreased to $486,875 from $743,238 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 34%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VIII-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.71 per barrel, resulting in a decrease of approximately $90,900 in revenues. Oil sales represented 86% of total oil and gas sales during the six months ended June 30, 2002 as compared to 77% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund VIII-A decreased during the same period by 51%, or $2.90 per Mcf, resulting in a decrease of approximately $68,200 in revenues.

14

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $159,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 2,400 barrels, or 11%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $63,600 in revenues.

Gas production decreased approximately 5,900 Mcf, or 20%, during the same period, resulting in a decrease of approximately $33,700 in revenues.

The total decrease in revenues due to the change in production is approximately $97,300. The decrease in gas production is due primarily to downtime on one lease during the six months ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $388,521 from $390,803 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 1%. The decrease is the result of lower depletion expense and general and administrative expense, partially offset by an increase in lease operating costs.

1.  Lease operating costs and production taxes increased 1%, or approximately $3,800, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $1,100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $13,000 for the six months ended June 30, 2002 from $18,000 for the same period in 2001. This represents a decrease of 28%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VIII-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund VIII-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	24.02	$	28.70	(16	%)
Average price per Mcf of gas	$	4.28	$	4.36	(2	%)
Oil production in barrels		43,100		44,600	(3	%)
Gas production in Mcf		59,600		58,900	1	%
Gross oil and gas revenue	$	1,290,533	$	1,537,038	(16	%)
Net oil and gas revenue	$	568,229	$	831,291	(32	%)
Oil & Gas Income Fund VIII-A distributions	$	620,063	$	615,440	1	%
Limited partner distributions	$	558,057	$	553,896	1	%
Per unit distribution to limited partner	$	41.05	$	40.74	1	%
Number of limited partner interests		13,596		13,596

15

Revenues

Oil & Gas Income Fund VIII-A’s oil and gas revenues decreased to $1,290,533 from $1,537,038 for the years ended December 31, 2001 and 2000, respectively, a decrease of 16%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VIII-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 16%, or $4.68 per barrel, resulting in a decrease of approximately $201,700 in revenues. Oil sales represented 80% of total oil and gas sales during the year ended December 31, 2001 as compared to 83% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Oil & Gas Income Fund VIII-A decreased during the same period by 2%, or $.08 per Mcf, resulting in a decrease of approximately $4,800 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $206,500. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,500 barrels, or 3%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $43,100 in revenues.

Gas production increased approximately 700 Mcf, or 1%, during the same period, resulting in an increase of approximately $3,100 in revenues.

The net total decrease in revenues due to the change in production is approximately $40,000.

Costs and Expenses

Total costs and expenses increased to $872,940 from $834,052 for the years ended December 31, 2001 and 2000, respectively, an increase of 5%. The increase is the result of higher depletion expense and lease operating costs, partially offset by a decrease in general and administrative expense.

1.  Lease operating costs and production taxes increased 2%, or approximately $16,600, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $700, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $45,000 for the year ended December 31, 2001 from $22,000 for the same period in 2000. This represents an increase of 105%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VIII-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Oil & Gas Income Fund VIII-A’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Oil & Gas Income Fund VIII-A during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $15,000 as of December 31, 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.70	$	17.07	68	%
Average price per Mcf of gas	$	4.36	$	2.47	77	%
Oil production in barrels		44,600		45,990	(3	%)
Gas production in Mcf		58,900		67,990	(13	%)
Gross oil and gas revenue	$	1,537,038	$	952,972	61	%
Net oil and gas revenue	$	831,291	$	372,079	123	%
Oil & Gas Income Fund VIII-A distributions	$	615,440	$	158,801	288	%
Limited partner distributions	$	553,896	$	146,801	277	%
Per unit distribution to limited partners	$	40.74	$	10.80	277	%
Number of limited partner interests		13,596		13,596

Revenues

Oil & Gas Income Fund VIII-A’s oil and gas revenues increased to $1,537,038 from $952,972 for the years ended December 31, 2000 and 1999, respectively, an increase of 61%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund VIII-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 68%, or $11.63 per barrel, resulting in an increase of approximately $518,700 in revenues. Oil sales represented 83% of total oil and gas sales during the year ended December 31, 2000 as compared to 82% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Oil & Gas Income Fund VIII-A increased during the same period by 77%, or $1.89 per Mcf, resulting in an increase of approximately $111,300 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $630,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,390 barrels, or 3%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $23,700 in revenues.

Gas production decreased approximately 9,090 Mcf, or 13%, during the same period, resulting in a decrease of approximately $22,500 in revenues.

The total decrease in revenues due to the change in production is approximately $46,200.

Costs and Expenses

Total costs and expenses increased to $834,052 from $707,814 for the years ended December 31, 2000 and 1999, respectively, an increase of 18%. The increase is the result of higher general and administrative expense and lease operating costs, partially offset by a decrease in depletion expense.

1.  Lease operating costs and production taxes were 21% higher, or approximately $124,900 more, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as one

17

well shut-in in 1998 and brought back up in 2000, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Oil & Gas Income Fund VIII-A to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $2,400, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $22,000 for the year ended December 31, 2000 from $23,000 for the same period in 1999. This represents a decrease of 4%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund VIII-A’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Oil & Gas Income Fund VIII-A’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $3,000 as of December 31, 1999.

Revenue and Distribution Comparison

Oil & Gas Income Fund VIII-A net income for the years ended December 31, 2001, 2000 and 1999 was $421,668, $713,495 and $246,697. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $466,668, $735,495 and $269,697, respectively. Correspondingly, Oil & Gas Income Fund VIII-A distributions for the years ended December 31, 2001, 2000 and 1999 were $620,063, $615,440 and $158,801, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The sources for the 2001 distributions of $620,063 were oil and gas operations of approximately $582,800 and the change in oil and gas properties of approximately $(37,400), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $615,440 were oil and gas operations of approximately $692,500 and the change in oil and gas properties of approximately $(8,400), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $158,801 were oil and gas operations of approximately $161,400 and the change in oil and gas properties of approximately $19,400, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $620,063 of which $558,057 was distributed to the limited partners and $62,006 to the general partners. The per unit distribution to limited partners during the same period was $41.05. Total distributions during the year ended December 31, 2000 were $615,440 of which $553,896 was distributed to the limited partners and $61,544 to the general partners. The per unit distribution to limited partners during the same period was $40.74. Total distributions during the year ended December 31, 1999 were $158,801 of which $146,801 was distributed to the limited partners and $12,000 to the general partners. The per unit distribution to limited partners during the same period was $10.80.

Liquidity and Capital Resources of Oil & Gas Income Fund VIII-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Oil & Gas Income Fund VIII-A knows of no material change, nor does it anticipate any such change.

18

Cash flows provided by operating activities were approximately $70,300 in the six months ended June 30, 2002 as compared to approximately $384,700 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $34,200 in the six months ended June 30, 2002 as compared to approximately $34,200 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was the addition of oil and gas properties.

Cash flows used in financing activities were approximately $32,100 in the six months ended June 30, 2002 as compared to approximately $425,100 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $32,000 of which $28,800 was distributed to the limited partners and $3,200 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2002 was $2.12. Total distributions during the six months ended June 30, 2001 were $425,000 of which $382,500 was distributed to the limited partners and $42,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $28.13.

The sources for the 2002 distributions of $32,000 were oil and gas operations of approximately $70,300 and the change in oil and gas properties of approximately $(34,200), resulting in excess cash for contingencies or subsequent distributions. The sources for the 2001 distributions of $425,000 were oil and gas operations of approximately $384,700 and the net change in oil and gas properties of approximately $(34,200), with the balance from available cash on hand at the beginning of the period.

Since inception of Oil & Gas Income Fund VIII-A, cumulative monthly cash distributions of $8,450,924 have been made to the partners. As of June 30, 2002, $7,650,703, or $562.72 per unit of limited partner interest, has been distributed to the limited partners, representing a 113% return of the capital contributed.

As of June 30, 2002, Oil & Gas Income Fund VIII-A had approximately $142,400 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Oil & Gas Income Fund VIII-A.

Cash flows provided by operating activities were approximately $582,800 in 2001 compared to $692,500 in 2000 and approximately $161,400 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows (used in) provided by investing activities were approximately $(37,400) in 2001 compared to $(8,400) in 2000 and approximately $19,400 in 1999. The principal use of the 2001 cash flow from investing activities was the addition of oil and gas properties.

Cash flows used in financing activities were approximately $619,900 in 2001 compared to $615,500 in 2000 and approximately $158,700 in 1999. The only use in financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND VIII-B, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties Institutional Income Fund VIII-B, L.P., which we call Institutional Income Fund VIII-B, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Institutional Income Fund VIII-B. The purpose of the special meeting is for you to vote upon the merger of Institutional Income Fund VIII-B with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Institutional Income Fund VIII-B is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on             .

This document contains the following information concerning Institutional Income Fund VIII-B:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Institutional Income Fund VIII-B

• Compensation and distributions from Institutional Income Fund VIII-B

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Institutional Income Fund VIII-B for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Institutional Income Fund VIII-B’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Institutional Income Fund VIII-B as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Institutional Income Fund VIII-B, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Institutional Income Fund VIII-B in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK AND SPECIAL STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on the Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Institutional Income Fund VIII-B’s assets. The Merger Value of

2

Institutional Income Fund VIII-B is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Institutional Income Fund VIII-B, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Institutional Income Fund VIII-B by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Institutional Income Fund VIII-B. We believe, however, that Institutional Income Fund VIII-B will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Institutional Income Fund VIII-B. Our decision is based on the following factors in order of significance:

• Our method of valuation for Institutional Income Fund VIII-B uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Institutional Income Fund VIII-B, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Institutional Income Fund VIII-B. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

3

MERGER VALUE FOR INSTITUTIONAL INCOME FUND VIII-B

The Merger Value for Income Fund VIII-B was determined by calculating its Net Asset Value and then dividing Income Fund VIII-B’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Income Fund VIII-B’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Income Fund VIII-B’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Institutional Income Fund VIII-B. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund VIII-B is 5.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Institutional Income Fund VIII-B
		Net Present Value of Reserves	$	2,242,377.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	121,361.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Institutional Income Fund VIII-B	$	2,363,738.00	calculated
(2)		Net Asset Value of Institutional Income Fund VIII-B	$	2,363,738.00	calculated
	less	GP% owned by Southwest in Institutional Income Fund VIII-B (10%)	$	236,373.80	Partnership records
	less	LP% owned by Southwest in Institutional Income Fund VIII-B (18.83%)	$	445,091.87	Partnership records
	equals	Net Asset Value of Institutional Income Fund VIII-B owned by limited partners (excluding Southwest’s ownership %)	$	1,682,272.33	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Institutional Income Fund VIII-B (excluding Southwest’s ownership %)	$	1,682,272.33	calculated
	equals	The percentage of ownership of Institutional Income Fund VIII-B (other than Southwest) to the total Net Asset Value		2.14%	calculated

4

				Document(s) from which information was obtained or calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Institutional Income Fund VIII-B (other than Southwest)	2.14%	calculated
	equals	The number of shares of common stock attributable to Institutional Income Fund VIII-B (other than to Southwest)	36,181.49	calculated
(7)		The number of shares of common stock attributable to Institutional Income Fund VIII-B (other than to Southwest)	36,181	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund VIII-B	8,025	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund VIII-B	5	calculated
(8)		The number of shares of special stock attributable to Institutional Income Fund VIII-B (other than to Southwest)	7,236	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Institutional Income Fund VIII-B	8,025	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Institutional Income Fund VIII-B	.90	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners became entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger.” The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Institutional Income Fund VIII-B for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	72,000	$	72,000	$	72,000	$	36,000
Administrative Overhead per Operating Agreements	$	108,929	$	104,108	$	101,641	$	54,697
Cash Distributions Paid to General Partners as General Partners(1)	$	62,026	$	65,024	$	18,000	$	10,500
Cash Distributions Paid to General Partner as Limited Partner	$	104,102	$	93,861	$	17,213	$	19,793

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Institutional Income Fund VIII-B’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	558,238	$	585,212	$	162,000	$	218,472	$	522,900	$	94,500
Return of Capital: 100%; Return on Capital: 27%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR INSTITUTIONAL INCOME FUND VIII-B
Aggregate Initial Investment by the Limited Partners:	$	5,074	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	6,444	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	2,127	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	209.65	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		6.8	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	50.00	(2)(4)
—as of December 31, 2001:	$	51.62	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	68.76	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	150.86	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	172.58	(2)(7)

6

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Institutional Income Fund VIII-B is equal to (1) the sum of (A) the present value of estimated future net revenues from Institutional Income Fund VIII-B’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Institutional Income Fund VIII-B is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interests sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Institutional Income Fund VIII-B is based upon (1) the sum of (A) the estimated net cash flow from the sale of Institutional Income Fund VIII-B’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Institutional Income Fund VIII-B’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Institutional Income Fund VIII-B is based upon (1) the sum of (A) the sale of Institutional Income Fund VIII-B’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Institutional Income Fund VIII-B’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Institutional Income Fund VIII-B and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Institutional Income Fund VIII-B is based upon (1) the sum of (A) Institutional Income Fund VIII-B’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Institutional Income Fund VIII-B.

INSTITUTIONAL INCOME FUND VIII-B

Set forth below is basic information about Institutional Income Fund VIII-B and its business and operations. It does not contain all the information about Institutional Income Fund VIII-B that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Institutional Income Fund VIII-B

General

Institutional Income Fund VIII-B was organized as a Delaware limited partnership on November 30, 1987. The offering of limited partner interests began March 31, 1988, reached minimum capital requirements on July 11, 1988 and concluded on March 31, 1989, with limited partner contributions of $5.1 million.

7

Principal Products, Marketing and Distribution

Institutional Income Fund VIII-B has acquired and holds royalty interests and net profit interests in oil and gas properties located in New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	84%	16%
2000	86%	14%
1999	85%	15%

As the table indicates, the majority of Institutional Income Fund VIII-B’s revenue is from its oil production.

Customer Dependence

No material portion of Institutional Income Fund VIII-B’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Institutional Income Fund VIII-B. Three purchasers accounted for 79% of Institutional Income Fund VIII-B’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 57%, Mobil Corporation for 11% and Exxon Company USA for 11%. Two purchasers accounted for 80% of Institutional Income Fund VIII-B’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 57% and Mobil Corporation for 23%. Two purchasers accounted for 76% of Institutional Income Fund VIII-B’s total oil and gas production during 1999: Scurlock Permian LLC for 52% and Mobil Corporation for 24%. All purchasers of Institutional Income Fund VIII-B’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Institutional Income Fund VIII-B’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Institutional Income Fund VIII-B’s sales of oil and gas production.

Properties

As of December 31, 2001, Institutional Income Fund VIII-B possessed an interest in oil and gas properties located in Eddy and Lea Counties, New Mexico and Andrews, Cochran, Crockett, Dawson, Dimmitt, Gaines, Garza, Glasscock, Hockley, Martin, Nolan, Pecos, Reagan, Reeves, Scurry, Sterling, Stonewall, Terry, Winkler, Ward, Yoakum and Zavala Counties, Texas. Institutional Income Fund VIII-B owns royalty interests and net profit interests in the wells; however, a substantial majority of the interests are net profit interests. These properties consist of various interests in approximately 2,464 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

There were no property sales during 2001, 2000 and 1999.

Significant Properties

The following table reflects the significant properties in which Institutional Income Fund VIII-B has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Mobil Ward and Reeves Counties, Texas	4/89 at 5% to 50% net profits interest	19	65,000	128,000
North American Royalties Yoakum County, Texas	3/89 at 50% to 100% net profits interest	3	157,000	—
Rasmussen Winkler County, Texas	6/89 at 1.5% to 19% royalty and net profits interest	21	67,000	106,000

8

* Ryder Scott Company, L.P. audited the reserve and present value data for Institutional Income Fund VIII-B’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.94 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.52 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VIII-B” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Institutional Income Fund VIII-B. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Institutional Income Fund VIII-B has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Institutional Income Fund VIII-B’s present reserves.

Because Institutional Income Fund VIII-B does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Institutional Income Fund VIII-B retains a carried interest under the terms of a farm-out or receives cash.

Institutional Income Fund VIII-B or the owners of properties in which Institutional Income Fund VIII-B owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VIII-B” in this prospectus supplement.

9

Market for Institutional Income Fund VIII-B’s Limited Partnership Interests and Related Matters

Market Information

After completion of Institutional Income Fund VIII-B’s first full fiscal year of operations and each year thereafter, the managing general partner has offered and will continue to offer to purchase each limited partner’s interest in Institutional Income Fund VIII-B, at a price based on tangible assets of Institutional Income Fund VIII-B, plus the net present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the managing general partner. However, the managing general partner’s obligation to purchase limited partner interests is limited to an expenditure of an amount not in excess of 10% of the total limited partner interests initially subscribed for by limited partners. In 2001, 379 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $314.39 per unit. In 2000, 650.0 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $178.93 per unit. In 1999, 191 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $59.26 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 520 holders of limited partner interests in Institutional Income Fund VIII-B.

Distributions

Pursuant to Article IV, Section 4.01 of Institutional Income Fund VIII-B’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Institutional Income Fund VIII-B’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Institutional Income Fund VIII-B], as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $620,264, with $558,238 distributed to the limited partners and $62,026 to the general partners. For the year ended December 31, 2001, distributions of $55.02 per unit of limited partner interest were made, based upon 10,147 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $650,236, with $585,212 distributed to the limited partners and $65,024 to the general partners. For the year ended December 31, 2000, distributions of $57.67 per unit of limited partner interest were made, based upon 10,147 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $180,000, with $162,000 distributed to the limited partners and $18,000 to the general partners. For the year ended December 31, 1999, distributions of $15.97 per unit of limited partner interest were made, based upon 10,147 units of limited partner interest outstanding.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

INSTITUTIONAL INCOME FUND VIII-B

The following tables present summary selected financial information and operating data for Institutional Income Fund VIII-B for the periods indicated. It should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition Results of Operations for Institutional Income Fund VIII-B” found elsewhere in this prospectus supplement and the financial statements and related notes for Institutional Income Fund VIII-B included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	432,347		643,847		1,150,821		1,371,825		854,653		728,499		1,105,361
Net income (loss)	88,421		289,160		411,583		713,329		275,872		(398,635	)	319,497
Partners’ share of net income (loss):
General partners	10,342		31,116		46,458		74,533		30,887		10,699		49,450
Partners	78,079		258,044		365,125		638,796		244,985		(409,334	)	270,047
Partners’ net income (loss) per unit	7.69		25.43		35.98		62.95		24.14		(40.34	)	26.61
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	75,872		355,116		581,354		687,229		211,486		208,044		554,059
Net cash provided by investing activities	—		—		—		—		—		62,224		1,030
Net cash used in financing activities	(104,673	)	(380,083	)	(619,939	)	(650,560	)	(180,009	)	(240,053	)	(581,059	)
Net increase (decrease) in cash and cash equivalents	(28,801	)	(24,967	)	(38,585	)	36,669		31,477		30,215		(25,970	)
EBITDA	103,421		311,160		464,583		745,329		308,872		106,989		494,497
Cash distributions	105,000		380,000		620,264		650,236		180,000		240,472		581,000
Partners’ cash distributions per $500 investment	9.31		33.70		55.02		57.67		15.97		21.53		51.53
Balance Sheet Data:
Cash and cash equivalents	34,322		76,741		63,123		101,708		65,039		33,562		3,347
Oil and gas properties, net at book value	392,438		438,438		407,438		460,438		492,438		525,438		1,045,456
Total assets	514,650		648,335		530,902		739,258		676,489		580,626		1,219,313
Total liabilities	850		115		523		199		523		532		112
Partners’ equity	507,337		632,916		523,759		716,871		663,287		580,302		1,208,108
General partners’ equity	6,462		15,304		6,620		22,188		12,679		(208	)	11,093
Partner’s book value per $500 investment	50.00		62.37		51.62		70.65		65.37		57.19		119.06

11

	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Production:
Oil production (Bbls)	17,700	19,800	40,100	41,000	42,140	48,700	49,200
Natural gas production (Mcf)	17,500	21,600	43,700	43,600	51,370	52,300	56,400
Equivalent production (Boe)	20,617	23,400	47,383	48,267	50,702	57,417	58,600
Average Sales Price:
Oil price (per/Bbl)	21.61	26.55	24.21	28.73	17.27	12.86	19.51
Natural gas price (per/Mcf)	2.85	5.47	4.12	4.45	2.47	1.96	2.58
Average sales price (per Boe)	20.97	27.51	24.29	28.42	16.86	12.69	18.86
Operating and Overhead Costs (per Boe)
Lease operating expense	13.23	11.27	11.72	10.10	8.51	8.66	8.35
Production taxes	.98	1.41	1.20	1.45	.76	.63	.91
General and Administrative Expense (per Boe)	1.87	1.66	1.65	1.65	1.53	1.58	1.38
Total	16.08	14.34	14.57	13.20	10.80	10.87	10.64
Cash Operating Margin (per Boe)	4.89	13.17	9.72	15.22	6.06	1.82	8.22
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.73	.94	1.12	.66	.65	8.81	2.99
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	293,000	443,000	327,000	736,000	990,000	147,000	355,000
Oil (Bbls)	436,000	459,000	354,000	486,000	448,000	199,000	362,000
Total (Boe)	485,000	532,000	409,000	609,000	613,000	224,000	421,000

⁽¹⁾ Institutional Income Fund VIII-B has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	2,364,000
Merger Value per $500 investment	$	209.65

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND VIII-B

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Institutional Income Fund VIII-B will likely experience the historical production decline of approximately 9% per year from the prior year’s production.

Results of Operations—General Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.54	$	26.00	(6	%)
Average price per Mcf of gas	$	3.24	$	4.49	(28	%)
Oil production in barrels		8,000		9,700	(18	%)
Gas production in Mcf		9,300		10,500	(11	%)
Income from net profits interests	$	65,188	$	117,517	(45	%)
Institutional Income Fund VIII-B distributions	$	35,000	$	130,000	(73	%)
Limited partner distributions	$	31,500	$	117,000	(73	%)
Per unit distribution to limited partners	$	3.10	$	11.53	(73	%)
Number of limited partner interests		10,147		10,147

Revenues

Institutional Income Fund VIII-B’s income from net profits interests decreased to $65,188 from $117,517 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 45%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund VIII-B decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 6%, or $1.46 per barrel, resulting in a decrease of approximately $11,700 in income from net profits interests. Oil sales represented 87% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 84% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund VIII-B decreased during the same period by 28%, or $1.25 per Mcf, resulting in a decrease of approximately $11,600 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $23,300. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,700 barrels, or 18%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $44,200 in income from net profits interests.

Gas production decreased approximately 1,200 Mcf, or 11%, during the same period, resulting in a decrease of approximately $5,400 in income from net profits interests.

13

The total decrease in income from net profits interests due to the change in production is approximately $49,600. The decrease in oil production is due primarily to downtime on one lease during the quarter ended June 30, 2002.

3.  Lease operating costs and production taxes decreased 13%, or approximately $23,100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $27,207 from $30,779 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 12%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 3%, or approximately $600, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $8,000 for the quarter ended June 30, 2002, from $11,000 for the same period in 2001. This represents a decrease of 27%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VIII-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund VIII-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.61	$	26.55	(19	%)
Average price per Mcf of gas	$	2.85	$	5.47	(48	%)
Oil production in barrels		17,700		19,800	(11	%)
Gas production in Mcf		17,500		21,600	(19	%)
Income from the profits interests	$	139,277	$	347,149	(60	%)
Institutional Income Fund VIII-B distributions	$	105,000	$	380,000	(72	%)
Limited partner distributions	$	94,500	$	342,000	(72	%)
Per unit distribution to limited partners	$	9.31	$	33.70	(72	%)
Number of limited partner interest		10,147		10,147

Revenues

Institutional Income Fund VIII-B’s income from net profits interests decreased to $139,277 from $347,149 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 60%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund VIII-B decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 19%, or $4.94 per barrel, resulting in a decrease of approximately $87,400 in income from net profits interests. Oil sales represented 88%

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of total oil and gas sales during the six months ended June 30, 2002 as compared to 82% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund VIII-B decreased during the same period by 48%, or $2.62 per Mcf, resulting in a decrease of approximately $45,900 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $133,300. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 2,100 barrels, or 11%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $55,800 in income from net profits interests.

Gas production decreased approximately 4,100 Mcf, or 19%, during the same period, resulting in a decrease of approximately $22,400 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $78,200. The decrease in gas production is due primarily to downtime on one lease during the six months ended June 30, 2002.

3.  Lease operating costs and production taxes decreased 1%, or approximately $3,600, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $53,509 from $60,943 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 12%. The decrease is the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $400, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $15,000 for the six months ended June 30, 2002 from $22,000 for the same period in 2001. This represents a decrease of 32%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VIII-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund VIII-B during 2002 as compared to 2001.

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Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	24.21	$	28.73	(16%	)
Average price per Mcf of gas	$	4.12	$	4.45	(7%	)
Oil production in barrels		40,100		41,000	(2%	)
Gas production in Mcf		43,700		43,600	—
Income from net profits interests	$	538,441	$	813,940	(34%	)
Institutional Income Fund VIII-B distributions	$	620,264	$	650,236	(5%	)
Limited partner distributions	$	558,238	$	585,212	(5%	)
Per unit distribution to limited partners	$	55.02	$	57.67	(5%	)
Number of limited partner interests		10,147		10,147

Revenues

Institutional Income Fund VIII-B’s income from net profits interests decreased to $538,441 from $813,940 for the years ended December 31, 2001 and 2000, respectively, a decrease of 34%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund VIII-B decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 16%, or $4.52 per barrel, resulting in a decrease of approximately $181,300 in income from net profits interests. Oil sales represented 84% of total oil and gas sales during the year ended December 31, 2001 as compared to 86% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Institutional Income Fund VIII-B decreased during the same period by 7%, or $.33 per Mcf, resulting in a decrease of approximately $14,400 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $195,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 900 barrels, or 2%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $25,900 in income from net profits interests.

Gas production increased approximately 100 Mcf, or less than 1%, during the same period, resulting in an increase of approximately $400 in income from net profits interests.

The net total decrease in income from net profits interests due to the change in production is approximately $25,500.

3.  Lease operating costs and production taxes increased 10%, or approximately $54,500, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

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Costs and Expenses

Total costs and expenses increased to $131,407 from $111,549 for the years ended December 31, 2001 and 2000, respectively, an increase of 18%. The increase is the result of higher depletion expense, partially offset by a decrease in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $1,100, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $53,000 for the year ended December 31, 2001 from $32,000 for the same period in 2000. This represents an increase of 66%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VIII-B’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Institutional Income Fund VIII-B’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Institutional Income Fund VIII-B during 2001 as compared to 2000, and the decrease in oil and gas revenues received by Institutional Income Fund VIII-B during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $15,000 as of December 31, 2000.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.73	$	17.27	66	%
Average price per Mcf of gas	$	4.45	$	2.47	80	%
Oil production in barrels		41,000		42,140	(3	%)
Gas production in Mcf		43,600		51,370	(15	%)
Income from net profits interests	$	813,940	$	384,532	112	%
Institutional Income Fund VIII-B distributions	$	650,236	$	180,000	261	%
Partner distributions	$	585,212	$	162,000	261	%
Per unit distribution to partners	$	57.67	$	15.97	261	%
Number of limited partner interests		10,147		10,147

Revenues

Institutional Income Fund VIII-B’s income from net profits interests increased to $813,940 from $384,352 for the years ended December 31, 2000 and 1999, respectively, an increase of 112%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.   The average price for a barrel of oil received by Institutional Income Fund VIII-B increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 66%, or $11.46 per barrel, resulting in an increase of approximately $469,900 in income from net profits interests. Oil sales represented 86% of total oil and gas sales during the year ended December 31, 2000 as compared to 85% during the year ended December 31, 1999.

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The average price for an Mcf of gas received by Institutional Income Fund VIII-B increased during the same period by 80%, or $1.98 per Mcf, resulting in an increase of approximately $86,300 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $556,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,140 barrels, or 3%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $19,700 in income from net profits interests.

Gas production decreased approximately 7,770 Mcf, or 15%, during the same period, resulting in a decrease of approximately $19,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $38,900. The decrease in gas production is due primarily to one well, which experienced a gas leak in the main line.

3.  Lease operating costs and production taxes increased 19%, or approximately $87,600, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Institutional Income Fund VIII-B to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

Costs and Expenses

Total costs and expenses increased to $111,549 from $110,506 for the years ended December 31, 2000 and 1999, respectively, an increase of 1%. The increase is the result of lower depletion expense, partially offset by an increase in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $2,000, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $32,000 for the year ended December 31, 2000 from $33,000 for the same period in 1999. This represents a decrease of 3%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund VIII-B’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Institutional Income Fund VIII-B’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $5,000 as of December 31, 1999.

Revenue and Distribution Comparison

Institutional Income Fund VIII-B net income for the years ended December 31, 2001, 2000 and 1999 was $411,583, $713,329 and $275,872, respectively. Excluding the effects of depreciation, depletion, and

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amortization net income for the years ended December 31, 2001, 2000 and 1999 would have been $464,583, $745,329 and $308,872, respectively. Correspondingly, Institutional Income Fund VIII-B distributions for the years ended December 31, 2001, 2000 and 1999 were $620,264, $650,236 and $180,000, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The sources for the 2001 distributions of $620,264 were oil and gas operations of approximately $581,400, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $650,236 were oil and gas operations of approximately $687,000, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $180,000 were oil and gas operations of approximately $211,500, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $620,264 of which $558,238 was distributed to the limited partners and $62,026 to the general partners. The per unit distribution to limited partners during the same period was $55.02. Total distributions during the year ended December 31, 2000 were $650,236 of which $585,212 was distributed to the limited partners and $65,024 to the general partners. The per unit distribution to limited partners during the same period was $57.67. Total distributions during the year ended December 31, 1999 were $180,000 of which $162,000 was distributed to the limited partners and $18,000 to the general partners. The per unit distribution to limited partners during the same period was $15.97.

Liquidity and Capital Resources of Institutional Income Fund VIII-B

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Institutional Income Fund VIII-B knows of no material change, nor does it anticipate any such change.

Cash flows provided by operating activities were approximately $75,900 in the six months ended June 30, 2002 as compared to approximately $355,100 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in financing activities were approximately $104,700 in the six months ended June 30, 2002 as compared to approximately $380,100 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $105,000 of which $94,500 was distributed to the limited partners and $10,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $9.31. Total distributions during the six months ended June 30, 2001 were $380,000 of which $342,000 was distributed to the limited partners and $38,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $33.70.

The source for the 2002 distributions of $105,000 was oil and gas operations of approximately $75,900, with the balance from available cash on hand at the beginning of the period. The sources for the 2001 distributions of $380,000 were oil and gas operations of approximately $355,100, with the balance from available cash on hand at the beginning of the period.

Since inception of Institutional Income Fund VIII-B, cumulative monthly cash distributions of $7,137,087 have been made to the partners. As of June 30, 2002, $6,443,863 or $635.05 per unit of limited partner interest has been distributed to the limited partners, representing a 127% return of the capital contributed.

As of June 30, 2002, Institutional Income Fund VIII-B had approximately $121,400 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Institutional Income Fund VIII-B.

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Cash flows provided by operating activities were approximately $581,400 in 2001 compared to $687,000 in 2000 and approximately $211,500 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Institutional Income Fund VIII-B had no cash flows from investing activities in 2001, 2000 and 1999. Cash flows used in financing activities were approximately $619,900 in 2001 compared to $650,600 in 2000 and approximately $180,000 in 1999. The only use in financing activities was the distributions to partners.

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SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST OIL & GAS INCOME FUND IX-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Oil & Gas Income Fund IX-A, L.P., which we call Oil & Gas Income Fund IX-A, and supplements the prospectus/proxy statement dated             , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Oil & Gas Income Fund IX-A. The purpose of the special meeting is for you to vote upon the merger of Oil & Gas Income Fund  IX-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Oil & Gas Income Fund IX-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on             .

This document contains the following information concerning Oil & Gas Income Fund IX-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Oil & Gas Income Fund IX-A

• Compensation and distributions from Oil & Gas Income Fund IX-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Oil & Gas Income Fund IX-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Oil & Gas Income Fund IX-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Oil & Gas Income Fund IX-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Oil & Gas Income Fund IX-A, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Oil & Gas Income Fund IX-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Oil & Gas Income Fund IX-A’s assets. The Merger Value of Oil & Gas Income Fund IX-A is based upon a formula to allocate shares of common stock and does not constitute a market

2

value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Oil & Gas Income Fund IX-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Oil & Gas Income Fund IX-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Oil & Gas Income Fund IX-A. We believe, however, that Oil & Gas Income Fund IX-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Oil & Gas Income Fund IX-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Oil & Gas Income Fund IX-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Oil & Gas Income Fund IX-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Oil & Gas Income Fund IX-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger.”

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

3

MERGER VALUE FOR OIL & GAS INCOME FUND IX-A

The Merger Value for Oil & Gas Income Fund IX-A was determined by calculating its Net Asset Value and then dividing Oil & Gas Income Fund IX-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Oil & Gas Income Fund IX-A’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Oil & Gas Income Fund IX-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Oil & Gas Income Fund IX-A. As indicated below, the number of shares of common stock issuable per each unit of Oil and Gas Income Fund IX-A is 5.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Oil & Gas Income Fund IX-A
		Net Present Value of Reserves	$	2,390,657.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	108,177.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Oil & Gas Income Fund IX-A	$	2,498,834.00	calculated
(2)		Net Asset Value of Oil & Gas Income Fund IX-A	$	2,498,834.00	calculated
	less	GP% owned by Southwest in Oil & Gas Income Fund IX-A (10.0%)	$	249,883.40	Partnership records
	less	LP% owned by Southwest in Oil & Gas Income Fund IX-A (3.9%)	$	97,454.53	Partnership records
	equals	Net Asset Value of Oil & Gas Income Fund IX-A owned by limited partners (excluding Southwest’s ownership %)	$	2,151,496.07	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Oil & Gas Income Fund IX-A (excluding Southwest’s ownership %)	$	2,151,496.07	calculated
	equals	The percentage of ownership of Oil & Gas Income Fund IX-A (other than Southwest) to the total Net Asset Value		2.74%	calculated

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				Document(s) from which information was obtained or calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Oil & Gas Income Fund IX-A (other than Southwest)	2.74%	calculated
	equals	The number of shares of common stock attributable to Oil & Gas Income Fund IX-A (other than to Southwest)	46,273.32	calculated
(7)		The number of shares of common stock attributable to Oil & Gas Income Fund IX-A (other than to Southwest)	46,273	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Oil & Gas Income Fund IX-A	10,001	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund IX-A	5	calculated
(8)		The number of shares of special stock attributable to Oil & Gas Income Fund IX-A (other than to Southwest)	9,255	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Oil & Gas Income Fund IX-A	10,001	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Oil & Gas Income Fund IX-A	.93	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK - Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Oil & Gas Income Fund  

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IX-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	73,200	$	73,200	$	73,200	$	36,600
Administrative Overhead per Operating Agreements	$	80,424	$	76,254	$	77,864	$	40,816
Cash Distributions Paid to General Partners as General Partners(1)	$	64,617	$	51,292	$	24,000	$	10,000
Cash Distributions Paid to General Partner as Limited Partner	$	23,268	$	20,768	$	6,609	$	3,903

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Oil & Gas Income Fund IX-A’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	581,552	$	564,502	$	238,173	$	244,923	$	397,800	$	90,000
Return of Capital: 100%; Return on Capital: 31%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR OIL & GAS INCOME FUND IX-A

Aggregate Initial Investment by the Limited Partners:	$	5,227	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	6,856	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	2,249	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	215.15	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		8.0	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	42.72	(2)(4)
—as of December 31, 2001:	$	47.04	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	95.54	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	141.71	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	182.98	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

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⁽³⁾ The Merger Value for Oil & Gas Income Fund IX-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Oil & Gas Income Fund IX-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Oil & Gas Income Fund IX-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interests sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Oil & Gas Income Fund IX-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Oil & Gas Income Fund IX-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Oil & Gas Income Fund IX-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Oil & Gas Income Fund IX-A is based upon (1) the sum of (A) the sale of Oil & Gas Income Fund IX-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Oil & Gas Income Fund IX-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Oil & Gas Income Fund IX-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Oil & Gas Income Fund IX-A is based upon (1) the sum of (A) Oil & Gas Income Fund IX-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Oil & Gas Income Fund IX-A.

OIL & GAS INCOME FUND IX-A

Set forth below is basic information about Oil & Gas Income Fund IX-A and its business and operations. It does not contain all the information about Oil & Gas Income Fund IX-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Oil & Gas Income Fund IX-A

General

Oil & Gas Income Fund IX-A was organized as a Delaware limited partnership on March 9, 1989. The offering of limited partner interests began May 11, 1989, reached minimum capital requirements on October 25, 1989 and concluded March 31, 1990, with total limited partner contributions of $5.2 million.

Principal Products, Marketing and Distribution

Oil & Gas Income Fund IX-A has acquired and holds working interests in oil and gas properties located in Texas and New Mexico.

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Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	59%	41%
2000	60%	40%
1999	61%	39%

As the table indicates, Oil & Gas Income Fund IX-A’s revenue is almost evenly divided between its oil and gas production.

Customer Dependence

No material portion of Oil & Gas Income Fund IX-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Oil & Gas Income Fund IX-A. Three purchasers accounted for 71% of Oil & Gas Income Fund IX-A’s total oil and gas production during 2001: Phillips 66 Company for 45%, Duke Energy Field Services for 14% and Plains All American Pipeline, L.P. for 12%. Two purchasers accounted for 77% of Oil & Gas Income Fund IX-A’s total oil and gas production during 2000: Phillips 66 Company for 64%, and Plains All American Pipeline, L.P. for 13%. Two purchasers accounted for 72% of Oil & Gas Income Fund IX-A’s total oil and gas production during 1999: Phillips 66 Company for 60% and Scurlock Permian LLC for 12%. All purchasers of Oil & Gas Income Fund IX-A’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Oil & Gas Income Fund IX-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Oil & Gas Income Fund IX-A’s sales of oil and gas production.

Properties

As of December 31, 2001, Oil & Gas Income Fund IX-A possessed an interest in oil and gas properties located in Eddy and Lea Counties, New Mexico; Andrews, Crane, Ector, Garza, Howard, Martin, Pecos, Stonewall, Ward and Winkler Counties, Texas. These properties consist of various interests in approximately 159 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

There were no property sales during 2001 and 2000. During 1999, four leases were sold for approximately $200,950.

Significant Properties

The following table reflects the significant properties in which Oil & Gas Income Fund IX-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells		Proved Developed Producing Reserves*
				Oil (Bbls)		Gas (Mcf)
Phillips/Odessa Properties, 12 counties in Texas, 2 counties in New Mexico	working interest 1/90 at 13% to 52%		45		189,000		636,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Oil & Gas Income Fund IX-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

8

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.34 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.26 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND IX-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus a lower return for Oil & Gas Income Fund IX-A. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation.

In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Oil & Gas Income Fund IX-A has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Oil & Gas Income Fund IX-A’s present reserves.

Because Oil & Gas Income Fund IX-A does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Oil & Gas Income Fund IX-A retains a carried interest under the terms of a farm-out, or receives cash.

Oil & Gas Income Fund IX-A or the owners of properties in which Oil & Gas Income Fund IX-A owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND IX-A” in this prospectus supplement.

Market for Oil & Gas Income Fund IX-A’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Oil & Gas Income Fund IX-A should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by

9

NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 40 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $161.10 per unit. In 2000, 120.5 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $74.58 per unit. In 1999, 30 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $63.19 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 562 holders of limited partner interests in Oil & Gas Income  Fund IX-A.

Distributions

Pursuant to Article IV, Section 4.01 of Oil & Gas Income Fund IX-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Oil & Gas Income Fund IX-A’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Oil & Gas Income Fund IX-A], as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $646,169, with $581,552 distributed to the limited partners and $64,617 to the general partners. For the year ended December 31, 2001, distributions of $55.63 per unit of limited partner interest were made, based upon 10,453 units of limited partner interest outstanding. During 2000,

quarterly distributions were made totaling $615,794, with $564,502 distributed to the limited partners and $51,292 to the general partners. For the year ended December 31, 2000, distributions of $54.00 per unit of limited partner interests were made, based upon 10,453 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $262,173, with $238,173 distributed to the limited partners and $24,000 to the general partners. For the year ended December 31, 1999, distributions of $22.79 per unit of limited partner interest were made, based upon 10,453 units of limited partner interest outstanding.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

OIL & GAS INCOME FUND IX-A

The following tables present summary selected financial information and operating data for Oil & Gas Income Fund IX-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND IX-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Oil & Gas Income Fund IX-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,						Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	372,964		607,737		1,009,784		1,208,575		729,841		704,238		1,082,153
Net income (loss)	109,188		322,619		401,609		658,754		237,535		6,584		251,561
Partners’ share of net income (loss):
General partners	12,119		34,762		45,461		67,876		26,553		12,559		37,256
Partners	97,069		287,857		356,148		590,878		210,982		(5,975	)	214,305
Partners’ net income (loss) per unit of limited partner interest	9.29		27.54		34.07		56.53		20.18		(.57	)	20.50
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	82,919		331,426		523,280		659,301		201,279		173,236		470,614
Net cash provided by investing activities	(360	)	(4,991	)	(5,624	)	(31,032	)	195,762		91,006		(16,269	)
Net cash used in financing activities	(100,022	)	(434,586	)	(645,432	)	(615,920	)	(262,692	)	(268,288	)	(441,881	)
Net increase (decrease) in cash and cash equivalents	(17,463	)	(108,151	)	(127,776	)	12,349		134,349		(4,046	)	12,464
EBITDA	121,188		347,619		454,609		678,754		265,535		125,584		372,561
Cash distributions	100,000		435,000		646,169		615,794		262,173		268,773		442,000
Partners’ cash distributions per $500 investment	8.61		37.45		55.63		54.00		22.79		23.43		38.06

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	Six months ended June 30,						Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Balance Sheet Data:
Cash and cash equivalents	20,690		57,778		38,153		165,929		153,580		19,231		23,277
Oil and gas properties, net at book value	327,687		366,694		339,327		386,703		375,671		599,433		809,439
Total assets	436,578		559,268		427,412		671,236		628,402		653,559		915,263
Total liabilities	714		413		736		—		126		645		160
Partners’ equity	498,826		613,518		491,757		717,161		690,785		717,976		968,874
General partners’ equity	(62,962	)	(54,663	)	(65,081	)	(45,925	)	(62,509	)	(65,062	)	(53,771	)
Partner’s book value per $500 investment	47.72		58.69		47.04		68.61		66.08		68.69		92.69
Production:
Oil production (Bbls)	11,300		12,700		25,400		25,000		26,560		35,100		35,800
Natural gas production (Mcf)	55,500		60,900		121,600		138,800		143,200		173,100		205,200
Equivalent production (Boe)	20,550		22,850		45,667		48,133		50,427		63,950		70,000
Average Sales Price:
Oil price (per/Bbl)	21.80		26.43		23.54		29.05		16.87		12.41		18.52
Natural gas price (per/Mcf)	2.28		4.47		3.39		3.47		1.97		1.55		2.04
Average sales price (per Boe)	18.15		26.60		22.11		25.11		14.48		11.01		15.50
Operating and Overhead Costs (per Boe)
Lease operating expense	9.59		8.05		9.05		7.88		6.81		6.92		8.00
Production taxes	1.20		1.72		1.46		1.69		.93		.72		.98
General and Administrative Expense (per Boe)	1.91		1.76		1.75		1.62		1.57		1.46		1.18
Total	12.70		11.53		12.26		11.19		9.31		9.10		10.16
Cash Operating Margin (per Boe)	5.45		15.07		9.85		13.92		5.17		1.91		5.34
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.58		1.09		1.16		.42		.56		1.86		1.73
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	1,037,000		1,066,000		839,000		1,604,000		1,225,000		1,049,000		1,254,000
Oil (Bbls)	257,000		256,000		209,000		323,000		321,000		186,000		290,000
Total (Boe)	430,000		434,000		349,000		590,000		525,000		361,000		499,000

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⁽¹⁾ Oil & Gas Income Fund IX-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	2,499,000
Merger Value per $500 investment	$	215.15

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

13

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND IX-A

General

Based on current conditions, management anticipates performing workovers during 2002 to enhance production. Oil & Gas Income Fund IX-A may have an increase in production volumes for the year 2002, otherwise, Oil & Gas Income Fund IX-A will likely experience the historical production decline of approximately 8% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.25	$	25.88	(6	%)
Average price per Mcf of gas	$	2.83	$	3.63	(22	%)
Oil production in barrels		5,400		6,300	(14	%)
Gas production in Mcf		28,300		31,000	(9	%)
Gross oil and gas revenue	$	211,173	$	285,647	(26	%)
Net oil and gas revenue	$	89,205	$	156,319	(43	%)
Oil & Gas Income Fund IX-A distributions	$	50,000	$	200,000	(75	%)
Limited partner distributions	$	45,000	$	180,000	(75	%)
Per unit distribution to limited partners	$	4.30	$	17.22	(75	%)
Number of limited partner interests		10,453		10,453

Revenues

Oil & Gas Income Fund IX-A’s oil and gas revenues decreased to $211,173 from $285,647 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 26%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund IX-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 6%, or $1.63 per barrel, resulting in a decrease of approximately $8,800 in revenues. Oil sales represented 62% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 59% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund IX-A decreased during the same period by 22%, or $.80 per Mcf, resulting in a decrease of approximately $22,600 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $31,400. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 900 barrels, or 14%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $23,300 in revenues.

Gas production decreased approximately 2,700 Mcf, or 9%, during the same period, resulting in a decrease of approximately $9,800 in revenues.

14

The total decrease in revenues due to the change in production is approximately $33,100.

Costs and Expenses

Total costs and expenses decreased to $148,517 from $165,840 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 10%. The decrease is the result of lower lease operating costs, general and administrative expense and depletion expense.

1.  Lease operating costs and production taxes decreased 6%, or approximately $7,400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 5%, or approximately $1,000, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $7,000 for the quarter ended June 30, 2002, from $16,000 for the same period in 2001. This represents a decrease of 56%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund IX-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund IX-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.80	$	26.43	(18	%)
Average price per Mcf of gas	$	2.28	$	4.47	(49	%)
Oil production in barrels		11,300		12,700	(11	%)
Gas production in Mcf		55,500		60,900	(9	%)
Gross oil and gas revenue	$	372,964	$	607,737	(39	%)
Net oil and gas revenue	$	151,068	$	384,396	(61	%)
Oil & Gas Income Fund IX-A distributions	$	100,000	$	435,000	(77	%)
Limited partner distributions	$	90,000	$	391,500	(77	%)
Per unit distribution to limited partners	$	8.61	$	37.45	(77	%)
Number of limited partner interests		10,453		10,453

Revenues

Oil & Gas Income Fund IX-A’s oil and gas revenues decreased to $372,964 from $607,737 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 39%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund IX-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.63 per barrel, resulting in a decrease of approximately $52,300 in revenues. Oil sales represented 66% of total oil and gas sales during the six months ended June 30, 2002 as compared to 55% during the six months ended June 30, 2001.

15

The average price for an Mcf of gas received by Oil & Gas Income Fund IX-A decreased during the same period by 49%, or $2.19 per Mcf, resulting in a decrease of approximately $121,500 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $173,800. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,400 barrels, or 11%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $37,000 in revenues.

Gas production decreased approximately 5,400 Mcf, or 9%, during the same period, resulting in a decrease of approximately $24,100 in revenues.

The total decrease in revenues due to the change in production is approximately $61,100.

Costs and Expenses

Total costs and expenses decreased to $273,206 from $288,448 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 5%. The decrease is the result of lower lease operating costs, general and administrative expense and depletion expense.

1.  Lease operating costs and production taxes decreased 1%, or approximately $1,400, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $800, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $12,000 for the six months ended June 30, 2002 from $25,000 for the same period in 2001. This represents a decrease of 52%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund IX-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund IX-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	23.54	$	29.05	(19	%)
Average price per Mcf of gas	$	3.39	$	3.47	(2	%)
Oil production in barrels		25,400		25,000	2	%
Gas production in Mcf		121,600		138,800	(12	%)
Gross oil and gas revenue	$	1,009,784	$	1,208,575	(16	%)
Net oil and gas revenue	$	529,801	$	747,853	(29	%)
Oil & Gas Income Fund IX-A distributions	$	646,169	$	615,794	5	%
Limited partner distributions	$	581,552	$	564,502	3	%
Per unit distribution to limited partners	$	55.63	$	54.00	3	%
Number of limited partner interests		10,453		10,453

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Revenues

Oil & Gas Income Fund IX-A’s oil and gas revenues decreased to $1,009,784 from $1,208,575 for the years ended December 31, 2001 and 2000, respectively, a decrease of 16%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund IX-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 19%, or $5.51 per barrel, resulting in a decrease of approximately $140,000 in revenues. Oil sales represented 59% of total oil and gas sales during the year ended December 31, 2001 as compared to 60% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Oil & Gas Income Fund IX-A decreased during the same period by 2%, or $.08 per Mcf, resulting in a decrease of approximately $9,700 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $149,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 400 barrels, or 2%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in an increase of approximately $11,600 in revenues.

Gas production decreased approximately 17,200 Mcf, or 12%, during the same period, resulting in a decrease of approximately $59,700 in revenues.

The net total decrease in revenues due to the change in production is approximately $48,100.

Costs and Expenses

Total costs and expenses increased to $612,747 from $558,619 for the years ended December 31, 2001 and 2000, respectively, an increase of 10%. The increase is the result of higher lease operating costs, depletion expense and general and administrative costs.

1.  Lease operating costs and production taxes increased 4%, or approximately $19,300, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs increased 2%, or approximately $1,900, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $53,000 for the year ended December 31, 2001 from $20,000 for the same period in 2000. This represents an increase of 165%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund IX-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Oil & Gas Income Fund IX-A’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by the Oil & Gas Income Fund IX-A during 2001 as compared to 2000, and the decrease in oil and gas revenues received by Oil & Gas Income Fund IX-A during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $23,000 as of December 31, 2000.

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Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	29.05	$	16.87	72	%
Average price per Mcf of gas	$	3.47	$	1.97	76	%
Oil production in barrels		25,000		26,560	(6	%)
Gas production in Mcf		138,800		143,200	(3	%)
Income from net profits interests	$	1,208,575	$	729,841	66	%
Oil & Gas Income Fund IX-A distributions	$	615,794	$	262,173	120	%
Limited partner distributions	$	564,502	$	238,173	135	%
Per unit distribution to limited partners	$	54.00	$	22.79	137	%
Number of limited partner interests		10,453		10,453

Revenues

Oil & Gas Income Fund IX-A’s oil and gas revenues increased to $1,208,575 from $729,841 for the years ended December 31, 2000 and 1999, respectively, an increase of 66%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund IX-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 72%, or $12.18 per barrel, resulting in an increase of approximately $304,500 in revenues. Oil sales represented 60% of total oil and gas sales during the year ended December 31, 2000 as compared to 61% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Oil & Gas Income Fund IX-A increased during the same period by 76%, or $1.50 per Mcf, resulting in an increase of approximately $208,200 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $512,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,560 barrels, or 6%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $26,300 in revenues.

Gas production decreased approximately 4,400 Mcf, or 3%, during the same period, resulting in a decrease of approximately $8,700 in revenues.

The total decrease in revenues due to the change in production is approximately $35,000.

Costs and Expenses

Total costs and expenses increased to $558,619 from $497,166 for the years ended December 31, 2000 and 1999, respectively, an increase of 12%. The increase is the result of higher lease operating costs, partially offset by a decrease in depletion expense and general and administrative costs.

1.  Lease operating costs and production taxes were 18% higher, or approximately $70,400 more, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. Production taxes were associated with 9% of the increase in lease operating cost and production taxes. The rise in production taxes is directly associated with the rise in oil and gas prices for 2000.

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2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $1,000, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $20,000 for the year ended December 31, 2000 from $28,000 for the same period in 1999. This represents a decrease of 29%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund IX-A’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Oil & Gas Income Fund IX-A’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $1,000 as of December 31, 1999.

Revenue and Distribution Comparison

Oil & Gas Income Fund IX-A net income for the years ended December 31, 2001, 2000 and 1999 was $401,609, $658,754 and $237,535, respectively. Excluding the effects of depreciation, depletion and amortization, net income would have been $454,609 in 2001, $678,754 in 2000 and $265,535 in 1999. Correspondingly, Oil & Gas Income Fund IX-A distributions for the years ended December 31, 2001, 2000 and 1999 were $646,169, $615,794 and $262,173, respectively. These changes are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The sources for the 2001 distributions of $646,169 were oil and gas operations of approximately $523,300 and the change in oil and gas properties of approximately $(5,600), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $615,794 were oil and gas operations of approximately $659,300 and the change in oil and gas properties of approximately $(31,000), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $262,173 were oil and gas operations of approximately $201,300 and the change in oil and gas properties $195,800, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $646,169 of which $581,552 was distributed to the limited partners and $64,617 to the general partners. The per unit distribution to limited partners during the same period was $55.63. Total distributions during the year ended December 31, 2000 were $615,794 of which $564,502 was distributed to the limited partners and $51,292 to the general partners. The per unit distribution to limited partners during the same period was $54.00. Total distributions during the year ended December 31, 1999 were $262,173 of which $238,173 was distributed to the limited partners and $24,000 to the general partners. The per unit distribution to limited partners during the same period was $22.79.

Liquidity and Capital Resources of Oil & Gas Income Fund IX-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Oil & Gas Income Fund IX-A knows of no material change, nor does it anticipate any such change.

Cash flows provided by operating activities were approximately $82,900 in the six months ended June 30, 2002 as compared to approximately $331,400 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $360 in the six months ended June 30, 2002 as compared to approximately $5,000 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was the additions to oil and gas properties.

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Cash flows used in financing activities were approximately $100,000 in the six months ended June 30, 2002 as compared to approximately $434,600 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $100,000 of which $90,000 was distributed to the limited partners and $10,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2002 was $8.61. Total distributions during the six months ended June 30, 2001 were $435,000 of which $391,500 was distributed to the limited partners and $43,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $37.45.

The sources for the 2002 distributions of $100,000 were oil and gas operations of approximately $82,900 and the change in oil and gas properties of approximately $(360), with the balance from available cash on hand at the beginning of the period. The source for the 2001 distributions of $435,000 was oil and gas operations of approximately $331,400, and the net change in oil and gas properties of approximately $(5,000), with the balance from available cash on hand at the beginning of the period.

Since inception of Oil & Gas Income Fund IX-A, cumulative monthly cash distributions of $7,540,927 have been made to the partners. As of June 30, 2002, $6,855,700 or $655.86 per unit of limited partner interest has been distributed to the limited partners, representing a 131% return of the capital contributed.

As of June 30, 2002, Oil & Gas Income Fund IX-A had approximately $108,200 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Oil & Gas Income Fund IX-A.

Cash flows provided by operating activities were approximately $523,300 in 2001 compared to $659,300 in 2000 and approximately $201,300 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows (used in) provided by investing activities were approximately, $(5,600) in 2001 compared to $(31,000) in 2000 and approximately $195,800 in 1999. The principal use of the 2001 cash flow from investing activities was the addition of oil and gas properties.

Cash flows used in financing activities were approximately $645,400 in 2001 compared to $615,900 in 2000 and approximately $262,700 in 1999. The only use in financing activities was the distributions to partners.

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SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND IX-B, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties Institutional Income Fund IX-B, L.P., which we call Institutional Income Fund IX-B, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Institutional Income Fund IX-B. The purpose of the special meeting is for you to vote upon the merger of Institutional Income Fund IX-B with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Institutional Income Fund IX-B is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Institutional Income Fund IX-B:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Institutional Income Fund IX-B

• Compensation and distributions from Institutional Income Fund IX-B

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Institutional Income Fund IX-B for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Institutional Income Fund IX-B’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.     Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Institutional Income Fund IX-B as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Institutional Income Fund IX-B, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Institutional Income Fund IX-B in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Institutional Income Fund IX-B’s assets. The Merger Value of Institutional Income Fund IX-B is based upon a formula to allocate shares of common stock and special stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Institutional Income Fund IX-B, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Institutional Income Fund IX-B by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Institutional Income Fund IX-B. We believe, however, that Institutional Income Fund IX-B will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Institutional Income Fund IX-B. Our decision is based on the following factors in order of significance:

• Our method of valuation for Institutional Income Fund IX-B uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Institutional Income Fund IX-B, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Institutional Income Fund IX-B. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INSTITUTIONAL INCOME FUND IX-B

The Merger Value for Institutional Income Fund IX-B was determined by calculating its Net Asset Value and then dividing Institutional Income Fund IX-B’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Institutional Income Fund IX-B’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Institutional Income Fund IX-B’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Institutional Income Fund IX-B. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund IX-B is 5.

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					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Institutional Income Fund IX-B
		Net Present Value of Reserves	$	2,246,849.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	95,332.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Institutional Income Fund IX-B	$	2,342,181.00	calculated
(2)		Net Asset Value of Institutional Income Fund IX-B	$	2,342,181.00	calculated
	less	GP% owned by Southwest in Institutional Income Fund IX-B (10.0%)	$	234,218.10	Partnership records
	less	LP% owned by Southwest in Institutional Income Fund IX-B (2.93%)	$	68,625.90	Partnership records
	equals	Net Asset Value of Institutional Income Fund IX-B owned by limited partners (excluding Southwest’s ownership %)	$	2,039,337.00	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Institutional Income Fund IX-B (excluding Southwest’s ownership %)	$	2,039,337.00	calculated
	equals	The percentage of ownership of Institutional Income Fund IX-B (other than Southwest) to the total Net Asset Value		2.60%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated

4

				Document(s) from which information was obtained or calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Institutional Income Fund IX-B (other than Southwest)	2.60%	calculated
	equals	The number of shares of common stock attributable to Institutional Income Fund IX-B (other than to Southwest)	43,861.06	calculated
(7)		The number of shares of common stock attributable to Institutional Income Fund IX-B (other than Southwest)	43,861	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund IX-B	9,464	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund IX-B	5	calculated
(8)		The number of shares of special stock attributable to Institutional Income Fund IX-B (other than to Southwest)	8,772	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Institutional Income Fund IX-B	9,464	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Institutional Income Fund IX-B	.93	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPTAL STOCK—Series B Special Stock to be issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Institutional Income Fund IX-B for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	68,400	$	68,400	$	68,400	$	34,200
Administrative Overhead per Operating Agreements	$	69,298	$	65,453	$	68,274	$	35,166
Cash Distributions Paid to General Partners as general partners(1)	$	54,245	$	48,257	$	23,000	$	9,500
Cash Distributions Paid to General Partner as Limited Partner	$	14,581	$	13,990	$	5,393	$	2,784

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Institutional Income Fund IX-B’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	488,202	$	540,523	$	251,382	$	271,583	$	374,850	$	85,500
Return of Capital: 100%; Return on Capital: 32%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR INSTITUTIONAL INCOME FUND IX-B

Aggregate Initial Investment by the Limited Partners:	$	4,891	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	6,437	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	2,108	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	215.49	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		8.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	45.01	(2)(4)
—as of December 31, 2001:	$	44.84	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	100.56	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	138.09	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	181.35	(2)(7)

⁽¹⁾ Stated in thousands.

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⁽²⁾   Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Institutional Income Fund IX-B is equal to (1) the sum of (A) the present value of estimated future net revenues from Institutional Income Fund IX-B’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾       The book value for Institutional Income Fund IX-B is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Institutional Income Fund IX-B is based upon (1) the sum of (A) the estimated net cash flow from the sale of Institutional Income Fund IX-B’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Institutional Income Fund IX-B’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Institutional Income Fund IX-B is based upon (1) the sum of (A) the sale of Institutional Income Fund IX-B’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Institutional Income Fund IX-B’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Institutional Income  Fund IX-B and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾   The final presentment value for Institutional Income Fund IX-B is based upon (1) the sum of (A) Institutional Income Fund IX-B’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Institutional Income Fund IX-B.

INSTITUTIONAL INCOME FUND IX-B

Set forth below is basic information about Institutional Income Fund IX-B and its business and operations. It does not contain all the information about Institutional Income Fund IX-B that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Institutional Income Fund IX-B

General

Institutional Income Fund IX-B was organized as a Delaware limited partnership on March 9, 1989. The offering of limited partner interests began May 11, 1989, reached the minimum capital requirements on September 26, 1989 and concluded March 31, 1990, with total partner contributions of $4.9 million.

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Principal Products, Marketing and Distribution

Institutional Income Fund IX-B has acquired and holds royalty, overriding royalty and net profits interests in oil and gas properties located in Texas and New Mexico.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil		Gas
2001	56	%	44	%
2000	56	%	44	%
1999	58	%	42	%

As the table indicates, Institutional Income Fund IX-B’s revenue is almost evenly divided between its oil and gas production.

Customer Dependence

No material portion of Institutional Income Fund IX-B’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have material adverse impact on Institutional Income  Fund IX-B. Two purchasers accounted for 63% of Institutional Income Fund IX-B’s total oil and gas production during 2001: Phillips 66 Company for 48% and Duke Energy Field Services for 15%. One purchaser accounted for 69% of Institutional Income Fund IX-B’s total oil and gas production during 2000: Phillips 66 Company 69%. One purchaser accounted for 62% of Institutional Income Fund IX-B’s total oil and gas production during 1999: Phillips 66 Company for 62%. All purchasers of Institutional Income Fund IX-B’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Institutional Income Fund IX-B’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Institutional Income Fund IX-B’s sales of oil and gas production.

Properties

As of December 31, 2001, Institutional Income Fund IX-B possessed an interest in oil and gas properties located in Eddy and Lea Counties, New Mexico; and Andrews, Cochran, Crane, Ector, Gaines, Garza, Howard, Midland, Pecos, Reagan, Terry, Ward, Winkler and Yoakum Counties, Texas. These properties consist of various interests in approximately 309 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

There were no property sales during 2001 and 2000. During 1999, four leases were sold for approximately $210,000.

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Significant Properties

The following table reflects the significant properties in which Institutional Income Fund IX-B has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Phillips/Odessa Properties, 14 counties in Texas, 2 counties in New Mexico	1/90 at 6% to 48% net profits interests	45	174,000	586,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Institutional Income Fund IX-B’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.29 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.26 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND IX-B” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Institutional Income Fund IX-B. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Institutional Income Fund IX-B has reserves, which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Institutional Income Fund IX-B’s present reserves.

Because Institutional Income Fund IX-B does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or

9

unrelated third parties. Generally, Institutional Income Fund IX-B retains a carried interest under the terms of a farm-out or receives cash.

Institutional Income Fund IX-B, or the owners of properties in which Institutional Income Fund IX-B owns an interest, can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND IX-B” in this prospectus supplement.

Market for Institutional Income Fund IX-B’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partnership interests in Institutional Income Fund IX-B should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 40 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $153.43 per unit. In 2000, 68 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $102.44 per unit. In 1999, 76 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $69.49 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 610 holders of limited partner interest in Institutional Income  Fund IX-B.

Distributions

Pursuant to Article IV, Section 4.01 of Institutional Income Fund IX-B’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Institutional Income Fund IX-B’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Institutional Income Fund IX-B], as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $542,447, with $488,202 distributed to the limited partners and $54,245 to the general partners. For the year ended December 31, 2001, distributions of $49.91 per unit of limited partner interest were made, based upon 9,782 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $588,780, with $540,523 distributed to the limited partners and $48,257 to the general partners. For the year ended December 31, 2000, distributions of $55.26 per unit of limited partner interest were made, based upon 9,782 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $274,382, with $251,382 distributed to the limited partners and $23,000 to the general partners. For the year ended December 31, 1999, distributions of $25.70 per unit of limited partner interest were made, based upon 9,782 units of limited partner interest outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

INSTITUTIONAL INCOME FUND IX-B

The following tables present summary selected financial information and operating data for Institutional Income Fund IX-B for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND IX-B” found elsewhere in this prospectus supplement and the financial statements and related notes for Institutional Income Fund IX-B included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	321,845		531,016		879,699		1,026,803		636,772		608,715		931,476
Net income (loss)	97,967		284,438		369,679		547,498		228,523		3,941		249,950
Partners’ share of net income (loss):
General partners	10,797		30,344		41,368		56,250		25,352		11,294		36,795
Partners	87,170		254,094		328,311		491,248		203,171		(7,353	)	213,155
Partners’ net income (loss) per unit	8.91		25.98		33.56		50.22		20.77		(.75	)	21.79
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	85,321		316,421		488,697		525,719		192,219		164,799		433,100
Net cash provided by investing activities	—		720		720		—		213,097		117,253		—
Net cash used in financing activities	(95,106	)	(349,904	)	(542,197	)	(588,734	)	(274,960	)	(298,546	)	(416,633	)
Net increase (decrease) in cash and cash equivalents	(9,785	)	(32,763	)	(52,780	)	(63,015	)	130,356		(16,494	)	16,467
EBITDA	107,967		303,438		413,679		562,498		253,523		112,941		367,950
Cash distributions	95,000		350,000		542,447		588,780		274,382		298,833		416,500
Partners’ cash distributions per $500 investment	8.74		32.20		49.91		55.26		25.70		27.76		38.32

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	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Balance Sheet Data:
Cash and cash equivalents	18,238		48,040		28,023		80,803		143,818		13,462		29,956
Oil and gas properties, net at book value	278,644		313,644		288,644		333,364		348,364		586,461		812,714
Total assets	374,122		478,313		371,261		543,778		585,060		631,451		926,056
Total liabilities	145		97		251		—		—		532		245
Partners’ equity	440,302		537,617		438,632		598,523		647,798		696,009		974,945
General partners’ equity	(66,325	)	(59,401	)	(67,622	)	(54,745	)	(62,738	)	(65,090	)	(49,134	)
Partner’s book value per $500 investment	45.01		54.96		44.84		61.19		66.22		71.15		99.67
Production:
Oil production (Bbls)	9,300		10,300		20,900		20,000		21,770		29,100		30,000
Natural gas production (Mcf)	53,400		58,100		115,000		129,900		135,640		160,600		186,900
Equivalent production (Boe)	18,200		19,983		40,067		41,650		44,377		55,867		61,150
Average Sales Price:
Oil price (per/Bbl)	21.45		26.26		23.40		28.76		16.98		12.35		18.40
Natural gas price (per/Mcf)	2.29		4.48		3.40		3.48		1.97		1.55		2.03
Average sales price (per Boe)	17.68		26.57		21.96		24.65		14.35		10.90		15.23
Operating and Overhead Costs (per Boe)
Lease operating expense	8.77		7.89		8.38		7.86		6.14		6.62		7.00
Production taxes	1.22		1.76		1.48		1.72		.94		.74		.99
General and Administrative Expense (per Boe)	2.03		1.86		1.85		1.75		1.67		1.56		1.25
Total	12.02		11.51		11.71		11.33		8.75		8.92		9.24
Cash Operating Margin (per Boe)	5.66		15.06		10.25		13.32		5.60		1.98		5.99
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.55		.95		1.10		.36		.56		1.95		1.93
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	974,000		1,109,000		784,000		1,640,000		1,156,000		984,000		1,129,000
Oil (Bbls)	229,000		241,000		188,000		309,000		279,000		172,000		257,000
Total (Boe)	391,000		426,000		319,000		582,000		472,000		336,000		445,000

⁽¹⁾  Institutional Income Fund IX-B has no debt-related fixed charges.

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Merger Data:
Total assets for purposes of Merger Value	$	2,342,000
Merger Value per $500 investment	$	215.49

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

13

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND IX-B

General

Based on current conditions, management anticipates performing workovers during 2002 to enhance production. Institutional Income Fund IX-B may have an increase in production volumes for the years 2002 and 2003, otherwise, Institutional Income Fund IX-B will likely experience the historical production decline of approximately 9% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.62	$	25.75	(8	%)
Average price per Mcf of gas	$	2.81	$	3.69	(24	%)
Oil production in barrels		4,600		5,140	(11	%)
Gas production in Mcf		27,600		29,800	(7	%)
Income from net profits interests	$	83,203	$	127,673	(35	%)
Institutional Income Fund IX-B distributions	$	45,000	$	150,000	(70	%)
Limited partner distributions	$	40,500	$	135,000	(70	%)
Per unit distribution to limited partners	$	4.14	$	13.80	(70	%)
Number of limited partner interests		9,782		9,782

Revenues

Institutional Income Fund IX-B’s income from net profits interests decreased to $83,203 from $127,673 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 35%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund IX-B decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 8%, or $2.13 per barrel, resulting in a decrease of approximately $9,800 in income from net profits interests. Oil sales represented 58% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 55% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund IX-B decreased during the same period by 24%, or $.88 per Mcf, resulting in a decrease of approximately $24,300 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $34,100. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 540 barrels, or 11%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $13,900 in income from net profits interests.

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Gas production decreased approximately 2,200 Mcf, or 7%, during the same period, resulting in a decrease of approximately $8,100 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $22,000.

3.  Lease operating costs and production taxes decreased 7%, or approximately $7,400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $24,522 from $31,026 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 21%. The decrease is a result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 3%, or approximately $500, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $6,000 for the quarter ended June 30, 2002, from $12,000 for the same period in 2001. This represents a decrease of 50%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund IX-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund IX-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.45	$	26.26	(18	%)
Average price per Mcf of gas	$	2.29	$	4.48	(49	%)
Oil production in barrels		9,300		10,300	(10	%)
Gas production in Mcf		53,400		58,100	(8	%)
Income from net profits interests	$	140,108	$	338,229	(59	%)
Institutional Income Fund IX-B distributions	$	95,000	$	350,000	(73	%)
Limited partner distributions	$	85,500	$	315,000	(73	%)
Per unit distribution to limited partners	$	8.74	$	32.20	(73	%)
Number of limited partner interests		9,782		9,782

Revenues

Institutional Income Fund IX-B’s income from net profits interests decreased to $140,108 from $338,229 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 59%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund IX-B decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.81 per barrel,

15

resulting in a decrease of approximately $44,700 in income from net profits interests. Oil sales represented 62% of total oil and gas sales during the six months ended June 30, 2002 as compared to 51% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund IX-B decreased during the same period by 49%, or $2.19 per Mcf, resulting in a decrease of approximately $116,900 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $161,600.

2.  Oil production decreased approximately 1,000 barrels, or 10%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $26,300 in income from net profits interests.

Gas production decreased approximately 4,700 Mcf, or 8%, during the same period, resulting in a decrease of approximately $21,100 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $47,400.

3.  Lease operating costs and production taxes decreased 6%, or approximately $11,100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $46,922 from $56,283 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 17%. The decrease is the result of lower general and administrative expense and depletion expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $400, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $10,000 for the six months ended June 30, 2002 from $19,000 for the same period in 2001. This represents a decrease of 47%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund IX-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund IX-B during 2002 as compared to 2001.

16

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	23.40	$	28.76	(19	%)
Average price per Mcf of gas	$	3.40	$	3.48	(2	%)
Oil production in barrels		20,900		20,000	5	%
Gas production in Mcf		115,000		129,900	(11	%)
Income from net profits interests	$	484,452	$	628,194	(23	%)
Institutional Income Fund IX-B distributions	$	542,447	$	588,780	(8	%)
Limited partner distributions	$	488,202	$	540,523	(10	%)
Per unit distribution to limited partners	$	49.91	$	55.26	(10	%)
Number of limited partner interests		9,782		9,782

Revenues

Institutional Income Fund IX-B’s income from net profits interests decreased to $484,452 from $628,194 for the years ended December 31, 2001 and 2000, respectively, a decrease of 23%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund IX-B decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 19%, or $5.36 per barrel, resulting in a decrease of approximately $112,000 in income from net profits interests. Oil sales represented 56% of total oil and gas sales during the year ended December 31, 2001 as compared to 56% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Institutional Income Fund IX-B decreased during the same period by 2%, or $.08 per Mcf, resulting in a decrease of approximately $9,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $121,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 900 barrels, or 5%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in an increase of approximately $25,900 in income from net profits interests.

Gas production decreased approximately 14,900 Mcf, or 11%, during the same period, resulting in a decrease of approximately $51,900 in income from net profits interests.

The net total decrease in income from net profits interests due to the change in production is approximately $26,000.

3.  Lease operating costs and production taxes decreased 1%, or approximately $3,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

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Costs and Expenses

Total costs and expenses increased to $118,319 from $87,790 for the years ended December 31, 2001 and 2000, respectively, an increase of 35%. The increase is the result of higher general and administrative costs and depletion expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $1,500, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $44,000 for the year ended December 31, 2001 from $15,000 for the same period in 2000. This represents an increase of 193%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund IX-B’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Institutional Income Fund IX-B’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Institutional Income Fund IX-B during 2001 as compared to 2000, and the decrease in oil and gas revenues received by Institutional Income Fund IX-B during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $20,000 as of December 31, 2000.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.76	$	16.98	69	%
Average price per Mcf of gas	$	3.48	$	1.97	77	%
Oil production in barrels		20,000		21,770	(8	%)
Gas production in Mcf		129,900		135,640	(4	%)
Income from net profits interests	$	628,194	$	322,555	95	%
Institutional Income Fund IX-B distributions	$	588,780	$	274,382	115	%
Limited partner distributions	$	540,523	$	251,382	115	%
Per unit distribution to limited partners	$	55.26	$	25.70	115	%
Number of limited partner interests		9,782		9,782

Revenues

Institutional Income Fund IX-B’s income from net profits interests increased to $628,194 from $322,555 for the years ended December 31, 2000 and 1999, respectively, an increase of 95%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund IX-B increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 69%, or $11.78 per barrel, resulting in an increase of approximately $235,600 in income from net profits interests. Oil sales represented 56% of total oil and gas sales during the year ended December 31, 2000 as compared to 58% during the year ended December 31, 1999.

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The average price for an Mcf of gas received by Institutional Income Fund IX-B increased during the same period by 77%, or $1.51 per Mcf, resulting in an increase of approximately $196,200 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $431,800. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,770 barrels, or 8%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $30,100 in income from net profits interests.

Gas production decreased approximately 5,740 Mcf, or 4%, during the same period, resulting in a decrease of approximately $11,300 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $41,400.

3.  Lease operating costs and production taxes increased 27%, or approximately $84,400, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as pulling expenses on several leases, and in part to the rise in production taxes directly associated with the rise in oil and gas price received during the past year. The rise in oil and gas prices for 2000 has allowed Institutional Income Fund IX-B to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

Costs and Expenses

Total costs and expenses decreased to $87,790 from $98,939 for the years ended December 31, 2000 and 1999, respectively, a decrease of 11%. The decrease is the result of lower general and administrative costs and depletion expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $1,100, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $15,000 for the year ended December 31, 2000 from $25,000 for the same period in 1999. This represents a decrease of 40%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund IX-B’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Institutional Income Fund IX-B’s reserves for January 1, 2001 as compared to 2000. Another contributing factor was due to the impact of revisions of previous estimates on reserves. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have decreased depletion expense approximately $1,000 as of December 31, 1999.

Revenue and Distribution Comparison

Institutional Income Fund IX-B net income for the years ended December 31, 2001, 2000 and 1999 was $369,679, $547,498 and $228,523, respectively. Excluding the effects of depreciation, depletion and

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amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $413,679, $562,498 and $253,523, respectively. Correspondingly, Institutional Income Fund IX-B distributions for the years ended December 31, 2001, 2000 and 1999 were $542,447, $588,780 and $274,382. These differences are indicative of the changes in oil and gas prices, production and properties during 2001, 2000 and 1999.

The source for the 2001 distributions of $542,447 were oil and gas operations of approximately $488,700 and the change in oil and gas properties of approximately $700, with the balance from available cash on hand at the beginning of the period. The source for the 2000 distributions of $588,780 were oil and gas operations of approximately $525,700, with the balance from available cash on hand at the beginning of the period. The sources for the 1999 distributions of $274,382 were oil and gas operations of approximately $192,219 and property sales of approximately $213,100, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $542,447 of which $488,202 was distributed to the limited partners and $54,245 to the general partners. The per unit distribution to limited partners during the same period was $49.91. Total distributions during the year ended December 31, 2000 were $588,780 of which $540,523 was distributed to the limited partners and $48,257 to the general partners. The per unit distribution to limited partners during the same period was $55.26. Total distributions during the year ended December 31, 1999 were $274,382 of which $251,382 was distributed to the limited partners and $23,000 to the general partners. The per unit distribution to limited partners during the same period was $25.70.

Liquidity and Capital Resources of Institutional Income Fund IX-B

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Institutional Income Fund IX-B knows of no material change, nor does it anticipate any such change.

Cash flows provided by operating activities were approximately $85,300 in the six months ended June 30, 2002 as compared to approximately $316,400 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

There were no investing activities during the six months ended June 30, 2002. Cash flows provided by investing activities were approximately $700 in six months ended June 30, 2001.

Cash flows used in financing activities were approximately $95,100 in the six months ended June 30, 2002 as compared to approximately $349,900 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $95,000 of which $85,500 was distributed to the limited partners and $9,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2002 was $8.74. Total distributions during the six months ended June 30, 2001 were $350,000 of which $315,000 was distributed to the limited partners and $35,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $32.20.

The source for the 2002 distributions of $95,000 was oil and gas operations of approximately $85,300, with the balance from available cash on hand at the beginning of the period. The sources for the 2001 distributions of $350,000 were oil and gas operations of approximately $316,400 and the change in oil and gas properties of approximately $700, with the balance from available cash on hand at the beginning of the period.

Since inception of Institutional Income Fund IX-B, cumulative monthly cash distributions of $7,091,148 have been made to the partners. As of June 30, 2002, $6,436,952, or $658.04 per unit of limited partner interest, has been distributed to the limited partners, representing a 132% return of the capital contributed.

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As of June 30, 2002, Institutional Income Fund IX-B had approximately $95,300 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Institutional Income Fund IX-B.

Cash flows provided by operating activities were approximately $488,700 in 2001 compared to $525,700 in 2000 and approximately $192,200 in 1999. The primary sources of the 2001 cash flow from operating activities were profitable operations.

Cash flows provided by investing activities were approximately $700 in 2001. Institutional Income Fund IX-B had no cash flow from investing activities during 2000. Cash flows provided by investing activities were approximately $213,100 in 1999. The principal use of the 2001 cash flows from investing activities was term assignment proceeds.

Cash flows used in financing activities were approximately $542,200 in 2001 compared to $588,700 in 2000 and approximately $275,000 in 1999. The only use in financing activities was the distributions to partners.

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SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST OIL & GAS INCOME FUND X-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Oil & Gas Income Fund X-A, L.P., which we call Oil & Gas Income Fund X-A, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of the Oil & Gas Income Fund X-A. The purpose of the special meeting is for you to vote upon the merger of Oil & Gas Income Fund X-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Oil & Gas Income Fund X-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Oil & Gas Income Fund X-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Oil & Gas Income Fund X-A

• Compensation and distributions from Oil & Gas Income Fund X-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Oil & Gas Income Fund X-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Oil & Gas Income Fund X-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Oil & Gas Income Fund X-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Oil & Gas Income Fund X-A, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Oil & Gas Income Fund X-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Oil & Gas Income Fund X-A’s assets. The Merger Value of Oil & Gas Income Fund X-A is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Oil & Gas Income Fund X-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Oil & Gas Income Fund X-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Oil & Gas Income Fund X-A. We believe, however, that Oil & Gas Income Fund X-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Oil & Gas Income Fund X-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Oil & Gas Income Fund X-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Oil & Gas Income Fund X-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, and the liquidation value and the final presentment value of Oil & Gas Income Fund X-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger in the prospectus/proxy statement.”

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR OIL & GAS INCOME FUND X-A

The Merger Value for Oil & Gas Income Fund X-A was determined by calculating its Net Asset Value and then dividing Oil & Gas Income Fund X-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Oil & Gas Income Fund X-A’s ownership percentage of Southwest, and thus, the number of shares of our common stock to be distributed to Oil & Gas Income Fund X-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Oil & Gas Income Fund X-A. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-A is 1.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Oil & Gas Income Fund X-A
		Net Present Value of Reserves	$	692,931.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	14,380.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Oil & Gas Income Fund X-A	$	707,311.00	calculated

3

						Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Oil & Gas Income Fund X-A	$	707,311.00		calculated
	less	GP % owned by Southwest in Oil & Gas Income Fund X-A (10.0%)	$	70,731.10		Partnership records
	less	LP % owned by Southwest in Oil & Gas Income Fund X-A (1.47%)	$	10,397.47		Partnership records
	equals	Net Asset Value of Oil & Gas Income Fund X-A owned by limited partners (excluding Southwest’s ownership %)	$	626,182.43		calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00		July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58		calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58		calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58		calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42		calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00		calculated
	divided into	The Net Asset Value owned by limited partners of Oil & Gas Income Fund X-A (excluding Southwest’s ownership %)	$	626,182.43		calculated
	equals	The percentage of ownership of Oil & Gas Income Fund X-A (other than Southwest) to the total Net Asset Value		0.80	%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000		June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23	%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347		calculated
(6)		Total number of shares of common stock for combined entity		1,688,347		calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Oil & Gas Income Fund X-A (other than Southwest)		0.80	%	calculated
	equals	The number of shares of common stock attributable to Oil & Gas Income Fund X-A (other than to Southwest)		13,467.62		calculated
(7)		The number of shares of common stock attributable to Oil & Gas Income Fund X-A (other than to Southwest)		13,468		calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Oil & Gas Income Fund X-A		10,313		Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-A		1		calculated

4

				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Oil & Gas Income Fund X-A (other than to Southwest)	2,694	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Oil & Gas Income Fund X-A	10,313	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-A	.26	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement.” The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Oil & Gas Income Fund X-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	78,000	$	78,000	$	78,000	$	39,000
Administrative Overhead per Operating Agreements	$	39,829	$	45,130	$	56,745	$	19,861
Cash Distributions Paid to General Partners as General Partners(1)	$	6,000	$	257	$	—	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	823	$	1,013	$	—	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Oil & Gas Income Fund X-A’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	54,000	$	73,769	$	—	$	28,800	$	155,250	$	—
Return of Capital: 50%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

5

SUPPLEMENTAL INFORMATION TABLE FOR OIL & GAS INCOME FUND X-A

Aggregate Initial Investment by the Limited Partners:	$	5,242	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	2,603	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	637	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	60.72	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 Months ended June 30, 2002:		0	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	13.91	(2)(4)
—as of December 31, 2001:	$	13.73	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	27.23	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	46.13	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	51.14	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Oil & Gas Income Fund X-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Oil & Gas Income Fund X-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Oil & Gas Income Fund X-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Oil & Gas Income Fund X-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Oil & Gas Income Fund X-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Oil & Gas Income Fund X-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Oil & Gas Income Fund X-A is based upon (1) the sum of (A) the sale of Oil & Gas Income Fund X-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Oil & Gas Income Fund X-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Oil & Gas Income Fund X-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Oil & Gas Income Fund X-A is based upon (1) the sum of (A) Oil & Gas Income Fund X-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Oil & Gas Income Fund X-A.

6

OIL & GAS INCOME FUND X-A

Set forth below is basic information about Oil & Gas Income Fund X-A and its business and operations. It does not contain all the information about Oil & Gas Income Fund X-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Oil & Gas Income Fund X-A

General

Oil & Gas Income Fund X-A was organized as a Delaware limited partnership on January 29, 1990. The offering of limited partner interests began May 11, 1990 as part of a shelf offering registered under the name Southwest Oil & Gas 1990-91 Income Program. Minimum capital requirements for Oil & Gas Income Fund X-A were met on August 15, 1990, with the offering of limited partnership interests concluding on November 30, 1990, with total partner contributions of $5.2 million.

Principal Products, Marketing and Distribution

Oil & Gas Income Fund X-A has acquired and holds working interests in oil and gas properties located in New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil		Gas
2001	85	%	15	%
2000	85	%	15	%
1999	86	%	14	%

As the table indicates, the majority of Oil & Gas Income Fund X-A’s revenue is from its oil production.

Customer Dependence

No material portion of Oil & Gas Income Fund X-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Oil & Gas Income Fund X-A. Three purchasers accounted for 84% of Oil & Gas Income Fund X-A’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 52%, Navajo Refining Company for 22% and Duke Energy Field Services for 10%. Four purchasers accounted for 85% of Oil & Gas Income Fund X-A’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 27%, Eaglewing Trading Inc. for 23%, Navajo Refining Company for 22% and Phillips 66 for 13%. Three purchasers accounted for 73% of Oil & Gas Income Fund X-A’s total oil and gas production during 1999: Scurlock Permian Corporation for 27%, Navajo Refining Company for 26% and Eaglewing Trading Inc. for 20%. All purchasers of Oil & Gas Income Fund X-A’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Oil & Gas Income Fund X-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without delay. No other purchaser accounted for an amount equal to or greater than 10% of Oil & Gas Income Fund X-A’s sales of oil and gas production.

Properties

As of December 31, 2001, Oil & Gas Income Fund X-A possessed an interest in oil and gas properties located in Eddy and Lea Counties, New Mexico; and Culberson, Duval, Gaines, Hockley, Midland, Pecos, Runnels, Terry and Ward Counties, Texas. These properties consist of various interests in approximately 162 wells and units.

7

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

There were no property sales during 2001 and 2000. During 1999, nine leases were sold for $42,770.

Significant Properties

The following table reflects the significant properties in which Oil & Gas Income Fund X-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves**
			Oil (Bbls)	Gas (Mcf)
Texas Crude Acquisition Gaines, Hockley, Terry and Culberson Counties, Texas; Lea County, New Mexico	12/90* at 17.5% to 50% working interest	8	118,000	46,000

* Per the terms of the purchase, Oil & Gas Income Fund X-A received production runs from a period prior to the date of purchase.

** Ryder Scott Company, L.P. audited prepared the reserve and present value data for Oil & Gas Income Fund X-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $16.61 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.40 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Oil & Gas Income Fund X-A. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation.

In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

8

Oil & Gas Income Fund X-A has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Oil & Gas Income Fund X-A’s present reserves.

Because Oil & Gas Income Fund X-A does not engage in drilling activities, the development of proved undeveloped reserves in conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Oil & Gas Income Fund X-A retains a carried interest under the terms of a farm-out, or receives cash.

Oil & Gas Income Fund X-A or the owners of properties in which Oil & Gas Income Fund X-A owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-A” in this prospectus supplement.

Market for Oil & Gas Income Fund X-A’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Oil & Gas Income X-A should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 15 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $26.86 per unit. In 2000, 32 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $13.75 per unit. In 1999, 17 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $22.57 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 569 holders of limited partner interest in Oil & Gas Income Fund X-A

Distributions

Pursuant to Article III, Section 3.05 of Oil & Gas Income Fund X-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Oil & Gas Income Fund X-A’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Oil & Gas Income Fund X-A], as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $60,000, with $54,000 distributed to the limited partners and $6,000 to the general partners. For the year ended December 31, 2001, distributions of $5.15 per unit of limited partner interest were made, based upon 10,484 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $74,026, with $73,769 distributed to the limited partners. For the year ended December 31, 2000, distributions of $7.04 per unit of limited partner interest were made, based upon 10,484 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. There were no distributions during the year ended December 31, 1999.

9

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

OIL & GAS INCOME FUND X-A

The following tables present summary selected financial information and operating data for Oil & Gas Income Fund X-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Oil & Gas Income Fund X-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	155,810		216,124		346,699		447,179		273,357		288,182		557,088
Net income (loss)	2,662		46,527		8,927		125,731		(26,816	)	(263,850	)	40,793
Partners’ share of net income (loss):
General partners	766		5,153		2,093		13,373		(1,782	)	(11,946	)	10,479
Partners	1,896		41,374		6,834		112,358		(25,034	)	(251,904	)	30,314
Partners’ net income (loss) per unit of limited partner interest	.18		3.95		.65		10.72		(2.39	)	(24.03	)	2.89
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	(9,785	)	69,829		86,105		83,092		(57,346	)	(47,375	)	164,699
Net cash provided by investing activities	(7,471	)	(12,079	)	(20,899	)	6,312		43,618		89,847		3,781
Net cash used in financing activities	—		(60,299	)	(60,341	)	(74,160	)	260		(32,208	)	(172,991	)
Net increase (decrease) in cash and cash equivalents	(17,256	)	(2,549	)	4,865		15,244		(13,468	)	10,264		(4,511	)
EBITDA	7,662		51,527		20,927		133,731		(17,816	)	(119,464	)	104,793
Cash distributions	—		60,000		60,000		74,026		—		32,000		172,800
Partners’ cash distributions per $500 investment	—		5.15		5.15		7.04		—		2.75		14.83
Balance Sheet Data:
Cash and cash equivalents	4,057		13,899		21,313		16,448		1,204		14,672		4,408
Oil and gas properties, net at book value	112,871		108,580		110,400		101,501		115,813		168,431		402,664
Total assets	127,588		162,568		131,713		176,340		124,769		183,103		447,383
Total liabilities	336		378		7,123		677		811		32,329		759
Partners’ equity	145,854		178,498		143,958		191,124		152,535		177,569		458,273
General partners’ equity	(18,602	)	(16,308	)	(19,368	)	(15,461	)	(28,577	)	(26,795	)	(11,649	)
Partner’s book value per $500 investment	13.91		17.03		13.73		18.23		14.55		16.94		43.71
Production:
Oil production (Bbls)	6,500		6,800		13,300		13,500		14,550		21,500		26,600
Natural gas production (Mcf)	7,200		8,500		11,100		15,700		16,430		20,500		30,200
Equivalent production (Boe)	7,700		8,217		15,150		16,117		17,288		24,917		31,633

10

	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999		1998		1997
Average Sales Price:
Oil price (per/Bbl)	20.96	24.73	22.24	28.15	16.18		11.65		18.00
Natural gas price (per/Mcf)	2.72	5.65	4.58	4.28	2.31		1.83		2.60
Average sales price (per Boe)	20.24	26.30	22.88	27.75	15.81		11.57		17.61
Operating and Overhead Costs (per Boe)
Lease operating expense	13.21	13.38	14.59	12.97	11.19		11.86		10.86
Production taxes	1.25	1.56	1.36	1.36	.83		.66		.96
General and Administrative Expense (per Boe)	5.43	5.12	5.56	5.13	4.83		3.85		2.76
Total	19.89	20.06	21.51	19.46	16.85		16.37		14.58
Cash Operating Margin (per Boe)	.35	6.24	1.37	8.29	(1.04	)	(4.80	)	3.03
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.65	.61	.79	.50	.52		5.80		2.02
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	107,000	143,000	115,000	167,000	163,000		147,000		233,000
Oil (Bbls)	145,000	165,000	129,000	150,000	143,000		38,000		181,000
Total (Boe)	163,000	189,000	148,000	178,000	170,000		63,000		220,000

⁽¹⁾ Oil & Gas Income Fund X-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	707,000
Merger Value per $500 investment	$	60.72

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

11

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-A

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Oil & Gas Income Fund X-A will likely experience the historical production decline of approximately 7% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.41	$	24.27	(4	%)
Average price per Mcf of gas	$	3.13	$	4.56	(31	%)
Oil production in barrels		3,200		3,400	(6	%)
Gas production in Mcf		3,800		4,100	(7	%)
Gross oil and gas revenue	$	86,833	$	98,834	(12	%)
Net oil and gas revenue	$	34,805	$	46,225	(25	%)
Oil & Gas Income Fund X-A distributions	$	—	$	15,000	(100	%)
Limited partner distributions	$	—	$	13,500	(100	%)
Per unit distribution to limited partners	$	—	$	1.29	(100	%)
Number of limited partner interests		10,484		10,484

Revenues

Oil & Gas Income Fund X-A’s oil and gas revenues decreased to $86,833 from $98,834 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 12%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 4%, or $.86 per barrel, resulting in a decrease of approximately $2,800 in revenues. Oil sales represented 86% of total oil and gas sales during the quarter ended June 30, 2002 and 82% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-A decreased during the same period by 31%, or $1.43 per Mcf, resulting in a decrease of approximately $5,400 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $8,200. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 200 barrels, or 6%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $4,900 in revenues.

Gas production decreased approximately 300 Mcf, or 7%, during the same period, resulting in a decrease of approximately $1,400 in revenues.

The total decrease in revenues due to the change in production is approximately $6,300.

12

Costs and Expenses

Total costs and expenses increased to $75,773 from $75,746 for the quarters ended June 30, 2002 and 2001, respectively, an increase of less than 1%. The increase is the result of higher depletion expense, partially offset by a decrease in general and administrative expense and lease operating costs.

1.  Lease operating costs and production taxes decreased 1%, or approximately $600, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense increased to $3,000 for the quarter ended June 30, 2002, from $2,000 for the same period in 2001. This represents an increase of 50%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the increase in depletion expense between the comparative periods was the additions of oil and gas properties due to workovers, which increased the asset base to which the depletion percentage is applied.

Results of Operations—General Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	20.96	$	24.73	(15	%)
Average price per Mcf of gas	$	2.72	$	5.65	(52	%)
Oil production in barrels		6,500		6,800	(4	%)
Gas production in Mcf		7,200		8,500	(15	%)
Gross oil and gas revenue	$	155,810	$	216,124	(28	%)
Net oil and gas revenue	$	44,557	$	93,364	(52	%)
Oil & Gas Income Fund X-A distributions	$	—	$	60,000	(100	%)
Limited partner distributions	$	—	$	54,000	(100	%)
Per unit distribution to limited partners	$	—	$	5.15	(100	%)
Number of limited partner interests		10,484		10,484

Revenues

Oil & Gas Income Fund X-A’s oil and gas revenues decreased to $155,810 from $216,124 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 28%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 15%, or $3.77 per barrel, resulting in a decrease of approximately $24,500 in revenues. Oil sales represented 87% of total oil and gas sales during the six months ended June 30, 2002 as compared to 78% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-A decreased during the same period by 52%, or $2.93 per Mcf, resulting in a decrease of approximately $21,100 in income from revenues.

13

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $45,600. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 300 barrels, or 4%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $7,400 in revenues.

Gas production decreased approximately 1,300 Mcf, or 15%, during the same period, resulting in a decrease of approximately $7,300 in revenues.

The total decrease in revenues due to the change in production is approximately $14,700. The decrease in gas production is due to one lease having a steep natural decline during the six months ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $158,030 from $169,814 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 7%. The decrease is the result of lower lease operating costs and general and administrative expense.

1.  Lease operating costs and production taxes decreased 9%, or approximately $11,500, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $300, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense remained the same for the six months ended June 30, 2002 and 2001. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	22.24	$	28.15	(21	%)
Average price per Mcf of gas	$	4.58	$	4.28	7	%
Oil production in barrels		13,300		13,500	(1	%)
Gas production in Mcf		11,100		15,700	(29	%)
Gross oil and gas revenue	$	346,699	$	447,179	(22	%)
Net oil and gas revenue	$	104,976	$	216,159	(51	%)
Oil & Gas Income Fund X-A distributions	$	60,000	$	74,026	(19	%)
Limited partner distributions	$	54,000	$	73,769	(27	%)
Per unit distribution to limited partners	$	5.15	$	7.04	(27	%)
Number of limited partner interests		10,484		10,484

14

Revenues

Oil & Gas Income Fund X-A’s oil and gas revenues decreased to $346,699 from $447,179 for the years ended December 31, 2001 and 2000, respectively, a decrease of 22%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 21%, or $5.91 per barrel, resulting in a decrease of approximately $78,600 in revenues. Oil sales represented 85% of total oil and gas sales during the year ended December 31, 2001 as compared to 85% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-A increased during the same period by 7%, or $.30 per Mcf, resulting in an increase of approximately $3,300 in revenues.

The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $75,300. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 200 barrels, or 1%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $5,600 in revenues.

Gas production decreased approximately 4,600 Mcf, or 29%, during the same period, resulting in a decrease of approximately $19,700 in revenues.

The total decrease in revenues due to the change in production is approximately $25,300. The decrease in gas production is in connection with a change in estimate, which was reflected in the fourth quarter of 2001. Oil & Gas Income Fund X-A had a small interest in a well, which it was discovered was not producing the larger portion of gas for the lease, but another well on the same lease was the major producer, which Oil & Gas Income Fund X-A owned a very small interest.

Costs and Expenses

Total costs and expenses increased to $338,003 from $321,784 for the years ended December 31, 2001 and 2000, respectively, an increase of 5%. The increase is the result of higher general and administrative expense, depletion expense and lease operating costs.

1.  Lease operating costs and production taxes increased 5%, or approximately $10,700, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $1,500, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $12,000 for the year ended December 31, 2001 from $8,000 for the same period in 2000. This represents an increase of 50%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Oil & Gas Income Fund X-A’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Oil & Gas Income Fund X-A during

15

2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $3,000 as of December 31, 2000.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.15	$	16.18	74	%
Average price per Mcf of gas	$	4.28	$	2.31	85	%
Oil production in barrels		13,500		14,550	(7	%)
Gas production in Mcf		15,700		16,430	(4	%)
Gross oil and gas revenue	$	447,179	$	273,357	64	%
Net oil and gas revenue	$	216,159	$	65,632	229	%
Oil & Gas Income Fund X-A distributions	$	74,026	$	—	100	%
Limited partner distributions	$	73,769	$	—	100	%
Per unit distribution to limited partners	$	7.04	$	—	100	%
Number of limited partner interests		10,484		10,484

Revenues

Oil & Gas Income Fund X-A’s oil and gas revenues increased to $447,179 from $273,357 for the years ended December 31, 2000 and 1999, respectively, an increase of 64%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 74%, or $11.97 per barrel, resulting in an increase of approximately $161,600 in revenues. Oil sales represented 85% of total oil and gas sales during the year ended December 31, 2000 as compared to 86% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-A increased during the same period by 85%, or $1.97 per Mcf, resulting in an increase of approximately $30,900 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $192,500. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,050 barrels, or 7%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $17,000 in revenues.

Gas production decreased approximately 730 Mcf, or 4%, during the same period, resulting in a decrease of approximately $1,700 in revenues.

The total decrease in revenues due to the change in production is approximately $18,700.

Costs and Expenses

Total costs and expenses increased to $321,784 from $300,173 for the years ended December 31, 2000 and 1999, respectively, an increase of 7%. The increase is the result of higher lease operating costs, partially offset by a decrease in depletion expense and general and administrative expense.

16

1.  Lease operating costs and production taxes were 11% higher, or approximately $23,300, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $700, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $8,000 for the year ended December 31, 2000 from $9,000 for the same period in 1999. This represents a decrease of 11%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-A’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Oil & Gas Income Fund X-A’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $1,000 as of December 31, 1999.

Revenue and Distribution Comparison

Oil & Gas Income Fund X-A income (loss) for the years ended December 31, 2001, 2000 and 1999 was $8,927, $125,731 and $(26,816), respectively. Excluding the effects of depreciation, depletion and amortization, net income (loss) would have been $20,927 in 2001, $133,731 in 2000 and $(17,816) in 1999. Correspondingly, Oil & Gas Income Fund X-A distributions for the years ended December 31, 2001, 2000 and 1999 were $60,000, $74,026 and none, respectively. These differences are indicative of the changes in oil and gas prices, production and property sales.

The sources for the 2001 distributions of $60,000 were oil and gas operations of approximately $86,100 and the change in oil and gas properties of approximately $(20,900), resulting in excess cash for contingencies or subsequent distributions. The sources for the 2000 distributions of $74,026 were oil and gas operations of approximately $83,100 and the change in oil and gas properties of approximately $6,300, resulting in excess cash for contingencies or subsequent distributions. There were no distributions for the year ending December 31, 1999.

Total distributions during the year ended December 31, 2001 were $60,000 of which $54,000 was distributed to the limited partners and $6,000 to the general partners. The per unit distribution to limited partners during the same period was $5.15. Total distributions during the year ended December 31, 2000 were $74,026 of which $73,769 was distributed to the limited partners. The per unit distribution to limited partners during the same period was $7.04. There were no distributions during the year ending December 31, 1999.

Liquidity and Capital Resources of Oil & Gas Income Fund X-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Oil & Gas Income Fund X-A knows of no material change, nor does it anticipate any such change.

Cash flows (used in) provided by operating activities were approximately $(9,800) in the six months ended June 30, 2002 as compared to approximately $69,800 in the six months ended June 30, 2001. The primary use of the 2002 cash flow from operating activities was operations.

Cash flows used in investing activities were approximately $7,500 in the six months ended June 30, 2002 as compared to approximately $12,100 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was the addition to oil and gas properties.

17

There were no cash flows used in financing activities in the six months ended June 30, 2002. Cash flows used in financing activities were approximately $60,300 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $60,000 of which $54,000 was distributed to the limited partners and $6,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $5.15.

The sources for the 2001 distributions of $60,000 were oil and gas operations of approximately $69,800 and the change in oil and gas properties of approximately $(12,100), with the balance from available cash on hand at the beginning of the period.

Since inception of Oil & Gas Income Fund X-A, cumulative monthly cash distributions of $2,827,732 have been made to the partners. As of June 30, 2002, $2,602,574 or $248.24 per unit of limited partner interest has been distributed to the limited partners, representing a 50% return of the capital contributed.

As of June 30, 2002, Oil & Gas Income Fund X-A had approximately $14,400 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Oil & Gas Income Fund X-A.

Cash flows provided by (used in) operating activities were approximately $86,100 on 2001 compared to $83,100 in 2000 and approximately $(57,300) in 1999. The primary source of the 2001 cash flow from operating activities was for operations.

Cash flows (used in) provided by investing activities were approximately $(20,900) in 2001 compared to $6,300 in 2000 and approximately $43,600 in 1999. The principal use of the 2001 cash flow from investing activities was the additions of oil and gas properties.

Cash flows provided by (used in) financing activities were approximately $(60,300) in 2001 compared to $(74,200) in 2000 and approximately $260 in 1999.

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SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties Institutional Income Fund X-A, L.P., which we call Institutional Income Fund X-A, and supplements the prospectus/proxy statement dated             , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Institutional Income Fund X-A. The purpose of the special meeting is for you to vote upon the merger of Institutional Income Fund X-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Institutional Income Fund X-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on             .

This document contains the following information concerning Institutional Income Fund X-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Institutional Income Fund X-A

• Compensation and distributions from Institutional Income Fund X-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Institutional Income Fund X-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Institutional Income Fund X-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Institutional Income Fund X-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002 The properties of Institutional Income Fund X-A, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Institutional Income Fund X-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Institutional Income Fund X-A’s assets. The Merger Value of Institutional Income Fund X-A is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Institutional Income Fund X-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Institutional Income Fund X-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Institutional Income Fund X-A. We believe, however, that Institutional Income Fund X-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Institutional Income Fund X-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Institutional Income Fund X-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Institutional Income Fund X-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Institutional Income Fund X-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INSTITUTIONAL INCOME FUND X-A

The Merger Value for Institutional Income Fund X-A was determined by calculating its Net Asset Value and then dividing Institutional Income Fund X-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Institutional Income Fund X-A’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Institutional Income Fund X-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Institutional Income Fund X-A. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund X-A is 2.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Institutional Income Fund X-A
		Net Present Value of Reserves	$	1,341,375.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	47,751.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Institutional Income Fund X-A	$	1,389,126.00	calculated

3

					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Institutional Income Fund X-A	$	1,389,126.00	calculated
	less	GP% owned by Southwest in Institutional Income Fund X-A (10.0%)	$	138,912.60	Partnership records
	less	LP% owned by Southwest in Institutional Income Fund X-A (2.20%)	$	30,560.77	Partnership records
	equals	Net Asset Value of Institutional Income Fund X-A owned by limited partners (excluding Southwest’s ownership %)	$	1,219,652.63	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves & June 30, 2002 Financials
	plus	Southwest’s GP & LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final & Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Institutional Income Fund X-A (excluding Southwest’s ownership %)	$	1,219,652.63	calculated
	equals	The percentage of ownership of Institutional Income Fund X-A (other than Southwest) to the total Net Asset Value		1.55%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Institutional Income Fund X-A (other than Southwest)		1.55%	calculated
	equals	The number of shares of common stock attributable to Institutional Income Fund X-A (other than to Southwest)		26,231.69	calculated
(7)		The number of shares of common stock attributable to Institutional Income Fund X-A (other than to Southwest)		26,232	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund X-A		11,039	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund X-A		2	calculated

4

				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Institutional Income Fund X-A (other than to Southwest)	5,246	calculated
	divided by	The number of units of limited partner interest (less the GP & Southwest LP interests) in Institutional Income Fund X-A	11,039	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Institutional Income Fund X-A	48	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Institutional Income Fund X-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	90,000	$	90,000	$	90,000	$	45,000
Administrative Overhead per Operating Agreements	$	42,999	$	48,360	$	60,325	$	21,465
Cash Distributions Paid to General Partners as General Partners(1)	$	20,009	$	6,082	$	—	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	4,403	$	2,098	$	—	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Institutional Income Fund X-A’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	180,084	$	149,240	$	—	$	45,000	$	207,000	$	—
Return of Capital: 55%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR INSTITUTIONAL INCOME FUND X-A

Aggregate Initial Investment by the Limited Partners:	$	5,658	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	3,107	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	1,250	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	110.48	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		39.6	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	19.27	(2)(4)
—as of December 31, 2001:	$	19.12	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	18.42	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	68.38	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	92.76	(2)(7)

6

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Institutional Income Fund X-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Institutional Income Fund X-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Institutional Income Fund X-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Institutional Income Fund X-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Institutional Income Fund X-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Institutional Income Fund X-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Institutional Income Fund X-A is based upon (1) the sum of (A) the sale of Institutional Income Fund X-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Institutional Income Fund X-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Institutional Income Fund X-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Institutional Income Fund X-A is based upon (1) the sum of (A) Institutional Income Fund X-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Institutional Income Fund X-A.

INSTITUTIONAL INCOME FUND X-A

Set forth below is basic information about Institutional Income Fund X-A and its business and operations. It does not contain all the information about Institutional Income Fund X-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Institutional Income Fund X-A

General

Institutional Income Fund X-A was organized as a Delaware limited partnership on January 29, 1990. The offering of limited partnership interests began May 11, 1990 as part of a shelf offering registered under the name Southwest Royalties Institutional 1990-91 Income Program. Minimum capital requirements for Institutional Income Fund X-A were met on July 30, 1990, with the offering of limited partnership interests concluding on November 30, 1990 with total partner contributions of $5.7 million.

7

Principal Products, Marketing and Distribution

Institutional Income Fund X-A has acquired and holds royalty, overriding royalty and net profit interests in oil and gas properties located in Texas and New Mexico.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	71%	29%
2000	75%	25%
1999	74%	26%

As the table indicates, the majority of Institutional Income Fund X-A’s revenue is from its oil production.

Customer Dependence

No material portion of Institutional Income Fund X-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Institutional Income Fund X-A. Two purchasers accounted for 59% of Institutional Income Fund X-A’s total oil and gas production during 2001: Plains All-American Pipeline, L.P. for 42% and Navajo Refining Company Inc. for 17%. Four purchasers accounted for 72% of Institutional Income Fund X-A’s total oil and gas production during 2000: Plains All-American Pipeline, L.P. for 25%, Eaglewing Trading Inc. for 18%, Navajo Refining Company Inc. for 17% and Phillip 66 for 12%. Four purchasers accounted for 69% of Institutional Income Fund X-A’s total oil and gas production during 1999: Scurlock Permian LLC for 24%, Navajo Refining Company Inc. for 20%, Eaglewing Trading Inc. for 15% and Phillips 66 for 10%. All purchasers of Institutional Income Fund X-A’s oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing Institutional Income Fund X-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Institutional Income Fund X-A’s sales of oil and gas production.

Properties

As of December 31, 2001, Institutional Income Fund X-A possessed an interest in oil and gas properties located in Eddy and Lea Counties, New Mexico; and Andrews, Cherokee, Duval, Gaines Glasscock, Hockley, Howard, Midland, Panola, Pecos, Reagan, Runnels, Terry Upton, Ward and Yoakum Counties, Texas. These properties consist of various interests in approximately 400 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

There were no property sales during 2001 and 2000. During 1999, nine leases were sold for $42,772.

Significant Properties

The following table reflects the significant property in which Institutional Income Fund X-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves#(2)
			Oil (Bbls)	Gas (Mcf)
Cline Estate Andrews, Cherokee, Glasscock, Howard, Panola, Reagan, Upton and Yoakum Counties, Texas	1/91 at .3% to 100% net profits interest	143	51,000	43,000
Texas Crude Acquisition Gaines, Hockley and Terry Counties, Texas and Lea County, New Mexico	12/90(1) at 17.5% to 50% net profits interest	7	115,000	46,000

8

(1) Per the terms of the purchase, Institutional Income Fund X-A received production runs from a period prior to the date of purchase.

(2) Ryder Scott Company, L.P. audited the reserve and present value data for Institutional Income Fund X-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $16.88 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.33 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Institutional Income Fund X-A. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation.

In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Institutional Income Fund X-A has reserves, which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate Institutional Income Fund X-A’s present reserves.

Because Institutional Income Fund X-A does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Institutional Income Fund X-A retains a carried interest under the terms of a farm-out or receives cash.

Institutional Income Fund X-A, or the owners of properties in which Institutional Income Fund X-A owns an interest, can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-A” in this prospectus supplement.

9

Market for Institutional Income Fund X-A’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interest in Institutional Income Fund X-A should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 113 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $33.31 per unit. In 2000, 12 units of limited partner interest were tendered to and purchased by the managing general partner. In 1999, 24 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $20.80 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001 there were 580 holders of limited partner interest in Institutional Income Fund X-A.

Distributions

Pursuant to Article III, Section 3.05 of Institutional Income Fund X-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Institutional Income Fund X-A’s] investments in producing oil and gas properties, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of [Institutional Income Fund X-A], as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $200,093, with $180,084 distributed to the limited partners and $20,009 to the general partners. For the year ended December 31, 2001, distributions of $15.91 per unit of limited partner interest were made, based upon 11,316 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $155,322, with $149,240 distributed to the limited partners and $6,082 to the general partners. For the year ended December 31, 2000, distributions of $13.19 per unit of limited partner interest were made, based upon 11,316 units of limited partner interest outstanding. There were no distributions during the 12 months ended December 31, 1999.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

INSTITUTIONAL INCOME FUND X-A

The following tables present summary selected financial information and operating data for Institutional Income Fund X-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Institutional Income Fund X-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	187,046		294,172		488,579		577,784		372,921		350,210		660,556
Net income (loss)	2,484		84,633		76,774		214,142		24,636		(283,067	)	87,080
Partners’ share of net income (loss):
General partners	748		9,263		9,477		22,614		3,764		(12,192	)	17,008
Partners	1,736		75,370		67,297		191,528		20,872		(270,875	)	70,072
Partners’ net income (loss) per unit of limited partner interest	.15		6.66		5.95		16.93		1.84		(23.94	)	6.19
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	(94	)	125,515		151,588		184,927		(23,429	)	(45,955	)	226,916
Net cash provided by investing activities	—		—		—		(5	)	44,871		100,286		2,500
Net cash used in financing activities	(79	)	(164,770	)	(199,791	)	(155,632	)	139		(50,001	)	(229,851	)
Net increase (decrease) in cash and cash equivalents	(173	)	(39,255	)	(48,203	)	29,290		21,581		4,330		(435	)
EBITDA	7,484		92,633		94,774		226,142		37,636		(121,924	)	170,080
Cash distributions	—		165,000		200,093		155,322		—		50,000		230,000
Partners’ cash distributions per $500 investment	—		13.12		15.91		13.19		—		3.98		18.29

11

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Balance Sheet Data:
Cash and cash equivalents	13,126		22,247		13,299		61,502		32,212		10,631		6,301
Oil and gas properties, net at book value	158,347		173,347		163,347		181,347		193,342		251,213		512,642
Total assets	206,439		246,914		204,034		327,051		268,541		261,844		576,834
Total liabilities	342		349		421		119		429		18,368		291
Partners’ equity	218,076		255,997		216,340		329,127		286,839		265,967		581,842
General partners’ equity	(11,979	)	(9,432	)	(12,727	)	(2,195	)	(18,727	)	(22,491	)	(5,299	)
Partner’s book value per $500 investment	19.27		22.62		19.12		29.09		25.35		23.50		51.42
Production:
Oil production (Bbls)	7,100		7,800		15,300		15,400		16,830		23,700		29,400
Natural gas production (Mcf)	14,200		18,000		32,700		33,400		38,830		38,150		49,800
Equivalent production (Boe)	9,467		10,800		20,750		20,967		23,302		30,058		37,700
Average Sales Price:
Oil price (per/Bbl)	20.99		25.11		22.57		28.32		16.36		11.60		18.06
Natural gas price (per/Mcf)	2.68		5.46		4.38		4.24		2.51		1.97		2.60
Average sales price (per Boe)	19.76		27.24		23.55		27.56		16.00		11.65		17.52
Operating and Overhead Costs (per Boe)
Lease operating expense	12.93		12.54		12.94		10.97		9.43		11.47		9.67
Production taxes	1.22		1.72		1.46		1.45		.86		.67		.98
General and Administrative Expense (per Boe)	5.04		4.44		4.61		4.51		4.10		3.57		2.60
Total	19.19		18.70		19.01		16.93		14.39		15.71		13.25
Cash Operating Margin (per Boe)	.57		8.54		4.54		10.63		1.61		(4.06	)	4.27
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.53		.74		.87		.43		.56		5.37		2.20
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	245,000		283,000		221,000		332,000		278,000		223,000		378,000
Oil (Bbls)	203,000		229,000		187,000		218,000		214,000		46,000		198,000
Total (Boe)	244,000		276,000		224,000		273,000		260,000		83,000		261,000

⁽¹⁾ Institutional Income Fund X-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	1,389,000
Merger Value per $500 investment	$	110.48

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-A

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Institutional Income Fund X-A will likely experience the historical production decline of approximately 8% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.57	$	24.48	(4	%)
Average price per Mcf of gas	$	3.24	$	4.35	(26	%)
Oil production in barrels		3,400		3,900	(13	%)
Gas production in Mcf		6,800		8,600	(21	%)
Income from net profits interests	$	35,774	$	49,278	(27	%)
Institutional Income Fund X-A distributions	$	—	$	65,000	(100	%)
Limited partner distributions	$	—	$	58,500	(100	%)
Per unit distribution to limited partners	$	—	$	5.17	(100	%)
Number of limited partner interests		11,316		11,316

Revenues

Institutional Income Fund X-A’s income from net profits interests decreased to $35,774 from $49,278 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 27%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 4%, or $.91 per barrel, resulting in a decrease of approximately $3,100 in income from net profits interests. Oil sales represented 78% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 72% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund X-A decreased during the same period by 26%, or $1.11 per Mcf, resulting in a decrease of approximately $7,500 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $10,600.

2.  Oil production decreased approximately 500 barrels, or 13%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $12,200 in income from net profits interests.

Gas production decreased approximately 1,800 Mcf, or 21%, during the same period, resulting in a decrease of approximately $7,800 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $20,000. The decrease in gas production is due to several small wells experiencing a sharp natural decline during the quarter ended June 30, 2002.

3.  Lease operating costs and production taxes decreased 8%, or approximately $5,600, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

13

Costs and Expenses

Total costs and expenses decreased to $26,762 from $27,112 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 1%. The decrease is the result of lower general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense remained the same for the quarter ended June 30, 2002, as compared to the same period in 2001. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	20.99	$	25.11	(16	%)
Average price per Mcf of gas	$	2.68	$	5.46	(51	%)
Oil production in barrels		7,100		7,800	(9	%)
Gas production in Mcf		14,200		18,000	(21	%)
Income from net profits interests	$	53,156	$	140,126	(62	%)
Institutional Income Fund X-A distributions	$	—	$	165,000	(100	%)
Limited partner distributions	$	—	$	148,500	(100	%)
Per unit distribution to limited partners	$	—	$	13.12	(100	%)
Number of limited partner interests		11,316		11,316

Revenues

Institutional Income Fund X-A’s income from net profits interests decreased to $53,156 from $140,126 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 62%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 16%, or $4.12 per barrel, resulting in a decrease of approximately $29,300 in income from net profits interests. Oil sales represented 80% of total oil and gas sales during the six months ended June 30, 2002 as compared to 67% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund X-A decreased during the same period by 51%, or $2.78 per Mcf, resulting in a decrease of approximately $39,500 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $68,800. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 700 barrels, or 9%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $17,600 in income from net profits interests.

Gas production decreased approximately 3,800 Mcf, or 21%, during the same period, resulting in a decrease of approximately $20,700 in income from net profits interests.

14

The total decrease in income from net profits interests due to the change in production is approximately $38,300. The decrease in gas production is due to several small wells experiencing a sharp natural decline during the six months ended June 30, 2002.

3.  Lease operating costs and production taxes decreased 13%, or approximately $20,200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $52,708 from $55,906 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 6%. The decrease is the result of lower general and administrative expense and depletion expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased less than 1%, or approximately $200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $5,000 for the six months ended June 30, 2002 from $8,000 for the same period in 2001. This represents a decrease of 38%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund X-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	22.57	$	28.32	(20	%)
Average price per Mcf of gas	$	4.38	$	4.24	3	%
Oil production in barrels		15,300		15,400	(1	%)
Gas production in Mcf		32,700		33,400	(2	%)
Income from net profits interests	$	189,907	$	317,883	(40	%)
Institutional Income Fund X-A distributions	$	200,093	$	155,322	29	%
Limited partner distributions	$	180,084	$	149,240	21	%
Per unit distribution to limited partners	$	15.91	$	13.19	21	%
Number of limited partner interests		11,316		11,316

Revenues

Institutional Income Fund X-A’s income from net profits interests decreased to $189,907 from $317,883 for the years ended December 31, 2001 and 2000, respectively, a decrease of 40%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 20%, or $5.75 per barrel, resulting in a decrease of approximately $88,000 in income from net profits interests. Oil sales represented 71% of total oil and gas sales during the year ended December 31, 2001 as compared to 75% during the year ended December 31, 2000.

15

The average price for an Mcf of gas received by Institutional Income Fund X-A increased during the same period by 3%, or $.14 per Mcf, resulting in an increase of approximately $4,600 in income from net profits interests.

The net total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $83,400. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 100 barrels, or 1%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $2,800 in income from net profits interests.

Gas production decreased approximately 700 Mcf, or 2%, during the same period, resulting in a decrease of approximately $3,000 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $5,800.

3.  Lease operating costs and production taxes increased 15%, or approximately $38,800, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

Costs and Expenses

Total costs and expenses increased to $113,625 from $106,326 for the years ended December 31, 2001 and 2000, respectively, an increase of 7%. The increase is the result of higher depletion expense and general and administrative costs.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $1,300, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $18,000 for the year ended December 31, 2001 from $12,000 for the same period in 2000. This represents an increase of 50%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Institutional Income Fund X-A’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Institutional Income Fund X-A during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $3,000 as of December 31, 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.32	$	16.36	73	%
Average price per Mcf of gas	$	4.24	$	2.51	69	%
Oil production in barrels		15,400		16,830	(8	%)
Gas production in Mcf		33,400		38,830	(14	%)
Income from net profits interests	$	317,883	$	133,177	139	%
Institutional Income Fund X-A distributions	$	155,322	$	—	100	%
Partner distributions	$	149,240	$	—	100	%
Per unit distribution to partners	$	13.19	$	—	100	%
Number of limited partner interests		11,316		11,316

Revenues

Institutional Income Fund X-A’s income from net profits interests increased to $317,883 from $133,177 for the years ended December 31, 2000 and 1999, respectively, an increase of 139%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 73%, or $11.96 per barrel, resulting in an increase of approximately $184,200 in income from net profits interests. Oil sales represented 75% of total oil and gas sales during the year ended December 31, 2000 as compared to 74% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Institutional Income Fund X-A increased during the same period by 69%, or $1.73 per Mcf, resulting in an increase of approximately $57,800 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $242,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,430 barrels, or 8%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $23,400 in income from net profits interests.

Gas production decreased approximately 5,430 Mcf, or 14%, during the same period, resulting in a decrease of approximately $13,600 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $37,000.

3.  Lease operating costs and production taxes increased 8%, or approximately $20,200, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

Costs and Expenses

Total costs and expenses decreased to $106,326 from $108,635 for the years ended December 31, 2000 and 1999, respectively, a decrease of 2%. The decrease is the result of lower depletion expense and general and administrative costs.

17

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $1,300, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $12,000 for the year ended December 31, 2000 from $13,000 for the same period in 1999. This represents a decrease of 8%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-A’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Institutional Income Fund X-A’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $2,000 as of December 31, 1999.

Revenue and Distribution Comparison

Institutional Income Fund X-A income for the years ended December 31, 2001, 2000 and 1999 was $76,774, $214,142 and $24,636, respectively. Excluding the effects of depreciation, depletion and amortization, net income would have been $94,774 in 2001, $226,142 in 2000 and $37,636 in 1999. Correspondingly, Institutional Income Fund X-A distributions for the years ended December 31, 2001, 2000 and 1999 were $200,093, $155,322 and none, respectively. These differences are indicative of the changes in oil and gas prices, production and property sales.

The sources for the 2001 distributions of $200,093 were oil and gas operations of approximately $151,600, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $155,322 were oil and gas operations of approximately $184,900 and the change in oil and gas properties of approximately $(5), resulting in excess cash for contingencies or subsequent distributions. There were no distributions for the 12 months ended December 31, 1999.

Total distributions during the year ended December 31, 2001 were $200,093 of which $180,084 was distributed to the limited partners and $20,009 to the general partners. The per unit distribution to limited partners during the same period was $15.91. Total distributions during the year ended December 31, 2000 were $155,322 of which $149,240 was distributed to the limited partners and $6,082 to the general partners. The per unit distribution to limited partners during the same period was $13.19. There were no distributions for the 12 months ended December 31, 1999.

Liquidity and Capital Resources of Institutional Income Fund X-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Institutional Income Fund X-A knows of no material change, nor does it anticipate any such change.

Cash flows (used in) provided by operating activities were approximately $(100) in the six months ended June 30, 2002 as compared to approximately $125,500 in the six months ended June 30, 2001.

Cash flows used in financing activities were approximately $80 in the six months ended June 30, 2002 as compared to approximately $164,800 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $165,000 of which $148,500 was distributed to the limited partners and $16,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $13.12.

18

The sources for the six months ended June 30, 2001 distributions of $165,000 were oil and gas operations of approximately $125,500, with the balance from available cash on hand at the beginning of the period.

Since inception of Institutional Income Fund X-A, cumulative monthly cash distributions of $3,388,537 have been made to the partners. As of June 30, 2002, $3,107,485 or $274.61 per unit of limited partner interest has been distributed to the limited partners, representing a 55% return of the capital contributed.

As of June 30, 2002, Institutional Income Fund X-A had approximately $47,800 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Institutional Income Fund X-A.

Cash flows provided by (used in) operating activities were approximately $151,600 in 2001 compared to $184,900 in 2000 and approximately $(23,400) in 1999. The primary source of the 2001 cash flow from operating activities was for operations.

There was no cash flows provided by (used in) investing activities in 2001 compared to $(5) in 2000 and approximately $44,900 in 1999.

Cash flows provided by (used in) financing activities were approximately $(199,800) in 2001, $(155,600) in 2000 and $100 in 1999.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST OIL & GAS INCOME FUND X-B, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Oil & Gas Income Fund X-B, L.P., which we call Oil & Gas Income Fund X-B, and supplements the prospectus/proxy statement dated                 , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Oil & Gas Income Fund X-B. The purpose of the special meeting is for you to vote upon the merger of Oil & Gas Income Fund X-B with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Oil & Gas Income Fund X-B is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                     .

This document contains the following information concerning Oil & Gas Income Fund X-B:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Oil & Gas Income Fund X-B

• Compensation and distributions from Oil & Gas Income Fund X-B

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Oil & Gas Income Fund X-B for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Oil & Gas Income Fund X-B’s management’s discussion and analysis of financial condition and results of operations for the quarter ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P. , has audited the volumes of the oil and gas reserves of Oil & Gas Income Fund X-B as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Oil & Gas Income Fund X-B, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Oil & Gas Income Fund X-B in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK AND SPECIAL STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Oil & Gas Income Fund X-B’s assets. The Merger Value of Oil & Gas

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Income Fund X-B is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Oil & Gas Income Fund X-B, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Oil & Gas Income Fund X-B by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Oil & Gas Income Fund X-B. We believe, however, that Oil & Gas Income Fund X-B will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Oil & Gas Income Fund X-B. Our decision is based on the following factors in order of significance:

• Our method of valuation for Oil & Gas Income Fund X-B uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Oil & Gas Income Fund X-B, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Oil & Gas Income Fund X-B. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

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MERGER VALUE FOR OIL & GAS INCOME FUND X-B

The Merger Value for Oil & Gas Income Fund X-B was determined by calculating its Net Asset Value and then dividing Oil & Gas Income Fund X-B’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Oil & Gas Income Fund X-B’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Oil & Gas Income Fund X-B’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Oil & Gas Income Fund X-B. As indicated below, the number of shares of common stock issuable per each unit of Oil & Gas Income Fund X-B is 2.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Oil & Gas Income Fund X-B
		Net Present Value of Reserves	$	1,058,686.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	80,751.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Oil & Gas Income Fund X-B	$	1,139,437.00	calculated
(2)		Net Asset Value of Oil & Gas Income Fund X-B	$	1,139,437.00	calculated
	less	GP % owned by Southwest in Oil & Gas Income Fund X-B 10.0%	$	113,943.70	Partnership records
	less	LP % owned by Southwest in Oil & Gas Income Fund X-B 1.69%	$	19,256.49	Partnership records
	equals	Net Asset Value of Oil & Gas Income Fund X-B owned by limited partners (excluding Southwest’s ownership %)	$	1,006,236.81	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Oil & Gas Income Fund X-B (excluding Southwest’s ownership %)	$	1,006,236.81	calculated
	equals	The percentage of ownership of Oil & Gas Income Fund X-B (other than Southwest) to the total Net Asset Value		1.28%	calculated

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				Document(s) from which information was obtained or calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Oil & Gas Income Fund X-B (other than Southwest)	1.28%	calculated
	equals	The number of shares of common stock attributable to Oil & Gas Income Fund X-B (other than to Southwest)	21,641.65	calculated
(7)		The number of shares of common stock attributable to Oil & Gas Income Fund X-B (other than to Southwest)	21,642	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Oil & Gas Income Fund X-B	10,685	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-B	2	calculated
(8)		The number of shares of special stock attributable to Oil & Gas Income Fund X-B (other than to Southwest)	4,328	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Oil & Gas Income Fund X-B	10,685	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-B	.41	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B special stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

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COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Oil & Gas Income Fund X-B for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	72,000	$	72,000	$	72,000	$	36,000
Administrative Overhead per Operating Agreements	$	164,872	$	158,924	$	161,534	$	80,286
Cash Distributions Paid to General Partners as General Partners(1)	$	37,944	$	40,664	$	7,000	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	5,427	$	4,035	$	523	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Oil & Gas Income Fund X-B’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	341,499	$	365,980	$	71,268	$	185,084	$	465,155	$—

Return of Capital: 90%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR OIL & GAS INCOME FUND X-B

Aggregate Initial Investment by the Limited Partners:	$	5,445	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	4,914	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	1,025	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	94.18	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		8.9	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	35.50	(2)(4)
—as of December 31, 2001:	$	33.90	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	61.08	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	71.58	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	78.25	(2)(7)

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⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Oil & Gas Income Fund X-B is equal to (1) the sum of (A) the present value of estimated future net revenues from Oil & Gas Income Fund X-B’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Oil & Gas Income Fund X-B is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Oil & Gas Income Fund X-B is based upon (1) the sum of (A) the estimated net cash flow from the sale of Oil & Gas Income Fund X-B’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Oil & Gas Income Fund X-B’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Oil & Gas Income Fund X-B is based upon (1) the sum of (A) the sale of Oil & Gas Income Fund X-B’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Oil & Gas Income Fund X-B’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Oil & Gas Income Fund X-B and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Oil & Gas Income Fund X-B is based upon (1) the sum of (A) Oil & Gas Income Fund X-B’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Oil & Gas Income Fund X-B.

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OIL & GAS INCOME FUND X-B

Set forth below is basic information about Oil & Gas Income Fund X-B and its business and operations. It does not contain all the information about Oil & Gas Income Fund X-B that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Oil & Gas Income Fund X-B

General

Oil & Gas Income Fund X-B was organized as a Delaware limited partnership on November 27, 1990. The offering of limited partner interests began December 1, 1990 as part of a shelf offering registered under the name Southwest Oil & Gas 1990-91 Income Program. Minimum capital requirements for Oil & Gas Income Fund X-B were met on March 1, 1991, with the offering of limited partnership interests concluding September 30, 1991, with total partner contributions of $5.4 million.

Principal Products, Marketing and Distribution

Oil & Gas Income Fund X-B has acquired and holds working interests in oil and gas properties located in Arkansas, Louisiana, New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	80%	20%
2000	83%	17%
1999	83%	17%

As the table indicates, the majority of Oil & Gas Income Fund X-B’s revenue is from its oil production.

Customer Dependence

No material portion of Oil & Gas Income Fund X-B’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Oil & Gas Income Fund X-B. Three purchasers accounted for 71% of Oil & Gas Income Fund X-B’s total oil and gas production during 2001: Teppco Crude Oil LLC for 40%, Plains All American Pipeline, L.P. for 21% and Raptor Resources Inc. for 10%. Three purchasers accounted for 79% of Oil & Gas Income Fund X-B’s total oil and gas production during 2000: Teppco Crude Oil LLC for 47%, All American Pipeline, L.P. for 20% and ExxonMobil for 12%. Three purchasers accounted for 78% of Oil & Gas Income Fund X-B’s total oil and gas production during 1999: Teppco Crude Oil LLC for 46%, Scurlock Permian LLC for 19% and ExxonMobil for 13%. All purchasers of Oil & Gas Income Fund X-B’s oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing Oil & Gas Income Fund X-B’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Oil & Gas Income Fund X-B’s sales of oil and gas production.

Properties

As of December 31, 2001, Oil & Gas Income Fund X-B possessed an interest in oil and gas properties located in Columbia County, Arkansas; Calcasieu Parish, Louisiana; Eddy and Lea Counties, New Mexico; and Ector, Duval, Midland, Reeves, Schleicher, Scurry, Ward, Winkler Counties, Texas. These properties consist of various interests in approximately 376 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

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There were no leases sold during 2001, 2000 and 1999.

Significant Properties

The following table reflects the significant properties in which Oil & Gas Income Fund X-B has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
NE Vacuum Abo Acquisition Lea County, New Mexico	9/91 at 25% to 50% working interest	7	119,000	86,000
SWRI Acquisition Midland and Ward Counties, Texas and Eddy County, NM	1/92 at 5.8% to 50% working interest	4	22,000	102,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Oil & Gas Income Fund X-B’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.48 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.00 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-B” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Oil & Gas Income Fund X-B. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Oil & Gas Income Fund X-B has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Oil & Gas Income Fund X-B’s present reserves.

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Because Oil & Gas Income Fund X-B does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Oil & Gas Income Fund X-B retains a carried interest under the terms of a farm-out, or receives cash.

Oil & Gas Income Fund X-B, or the owners of properties in which Oil & Gas Income Fund X-B owns an interest, can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-B” in this prospectus supplement.

Market for Oil & Gas Income Fund X-B’s Limited Partnership Interest and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 60 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $98.72 per unit. In 2000, 64 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $52.28 per unit. In 1999, 44 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $72.57 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 527 holders of limited partner interest in Oil & Gas Income  Fund X-B.

Distributions

Pursuant to Article III, Section 3.05 of Oil & Gas Income Fund X-B’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Oil & Gas Income Fund X-B’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Oil & Gas Income Fund X-B,] as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $379,443, with $341,499 distributed to the limited partners and $37,944 to the general partners. For the year ended December 31, 2001, distributions of $31.36 per unit of limited partner interest were made, based upon 10,889 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $406,644, with $365,980 distributed to the limited partners and $40,664 to the general partners. For the year ended December 31, 2000, distributions of $33.61 per unit of limited partner interest were made, based upon 10,889 unit of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $78,268, with $71,268 distributed to the limited partners and $7,000 to the general partners. For the year ended December 31, 1999, distributions of $6.54 per units of limited partner interest were made, based upon 10,889 limited partner units outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

OIL & GAS INCOME FUND X-B

The following tables present summary selected financial information and operating data for Oil & Gas Income Fund X-B for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-B” found elsewhere in this prospectus supplement and the financial statements and related notes for Oil & Gas Income Fund X-B included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	346,059		526,481		869,806		1,150,000		734,011		680,756		1,322,821
Net income (loss)	21,248		187,287		138,618		496,120		143,687		(762,994	)	274,614
Partners’ share of net income (loss):
General partners	3,825		21,129		20,362		52,512		17,369		(4,789	)	48,861
Partners	17,423		166,158		118,256		443,608		126,318		(758,205	)	225,753
Partners’ net income (loss) per unit of limited partner interest	1.60		15.26		10.86		40.74		11.60		(69.63	)	20.73
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	7,725		225,260		316,353		493,492		74,264		49,249		541,259
Net cash provided by investing activities	(10,141	)	(29,346	)	(16,694	)	(29,520	)	(7,653	)	184,445		(27,748	)
Net cash used in financing activities	—		(252,017	)	(379,128	)	(406,658	)	(78,293	)	(197,271	)	(516,589	)
Net increase (decrease) in cash and cash equivalents	(2,416	)	(56,103	)	(79,469	)	57,314		(11,682	)	36,423		(3,078	)
EBITDA	38,248		211,287		203,618		525,120		173,687		(47,892	)	488,614
Cash distributions	—		252,000		379,443		406,644		78,268		197,234		516,555
Partners’ cash distributions per $500 investment	—		20.83		31.36		33.61		6.54		17.00		42.72

11

	Six months ended June 30,			Years ended December 31,
	2002		2001	2001		2000	1999		1998		1997
Balance Sheet Data:
Cash and cash equivalents	10,774		36,556	13,190		92,659	35,345		47,027		10,604
Oil and gas properties, net at book value	303,432		363,943	310,291		358,597	358,077		380,424		1,241,471
Total assets	384,556		539,088	363,308		603,818	514,356		448,962		1,409,227
Total liabilities	373		41	373		58	72		97		134
Partners’ equity	386,577		531,755	369,154		592,397	514,769		459,719		1,403,008
General partners’ equity	(2,394	)	7,292	(6,219	)	11,363	(485	)	(10,854	)	6,085
Partner’s book value per $500 investment	35.50		48.83	33.90		54.40	47.27		42.22		128.85
Production:
Oil production (Bbls)	14,400		15,900	30,900		33,700	37,800		47,800		57,700
Natural gas production (Mcf)	21,800		25,100	52,000		50,700	54,670		78,000		110,700
Equivalent production (Boe)	18,033		20,083	39,567		42,150	46,912		60,800		76,150
Average Sales Price:
Oil price (per/Bbl)	20.61		25.26	22.42		28.15	16.15		11.25		18.36
Natural gas price (per/Mcf)	2.26		4.97	3.40		3.97	2.26		1.83		2.36
Average sales price (per Boe)	19.19		26.22	21.98		27.28	15.65		11.20		17.37
Operating and Overhead Costs (per Boe)
Lease operating expense	13.76		12.26	13.53		11.45	9.40		9.89		8.98
Production taxes	1.17		1.60	1.41		1.67	.92		.62		.96
General and Administrative Expense (per Boe)	2.14		1.93	1.97		1.82	1.64		1.50		1.07
Total	17.07		15.79	16.91		14.94	11.96		12.01		11.01
Cash Operating Margin (per Boe)	2.12		10.43	5.07		12.34	3.69		(.81	)	6.36
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.94		1.20	1.64		.69	.64		11.77		2.81
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	361,000		520,000	335,000		630,000	460,000		383,000		884,000
Oil (Bbls)	183,000		272,000	159,000		311,000	339,000		80,000		344,000
Total (Boe)	243,000		359,000	215,000		416,000	416,000		144,000		491,000

⁽¹⁾ Oil & Gas Income Fund X-B has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	1,139,000
Merger Value per $500 investment	$	94.18

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-B

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Oil & Gas Income Fund X-B will likely experience the historical production decline of approximately 9% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.22	$	24.70	(6	%)
Average price per Mcf of gas	$	2.87	$	4.06	(29	%)
Oil production in barrels		6,900		7,900	(13	%)
Gas production in Mcf		10,000		13,400	(25	%)
Gross oil and gas revenue	$	188,881	$	249,303	(24	%)
Net oil and gas revenue	$	54,740	$	108,885	(50	%)
Oil & Gas Income Fund X-B distributions	$	—	$	100,000	(100	%)
Limited partner distributions	$	—	$	90,000	(100	%)
Per unit distribution to limited partners	$	—	$	8.27	(100	%)
Number of limited partner interests		10,889		10,889

Revenues

Oil & Gas Income Fund X-B’s oil and gas revenues decreased to $188,881 from $249,303 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 24%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1. The average price for a barrel of oil received by Oil & Gas Income Fund X-B decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 6%, or $1.48 per barrel, resulting in a decrease of approximately $10,200 in revenues. Oil sales represented 85% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 78% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-B decreased during the same period by 29%, or $1.19 per Mcf, resulting in a decrease of approximately $11,900 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $22,100. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2. Oil production decreased approximately 1,000 barrels, or 13%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $24,700 in revenues.

Gas production decreased approximately 3,400 Mcf, or 25%, during the same period, resulting in a decrease of approximately $13,800 in revenues.

13

The total decrease in revenues due to the change in production is approximately $38,500. The decrease in gas production is primarily due to one lease experiencing a steep natural decline during the quarter ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $163,421 from $173,982 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 6%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative expense.

1.  Lease operating costs and production taxes decreased 4%, or approximately $6,300, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $300, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $10,000 for the quarter ended June 30, 2002, from $14,000 for the same period in 2001. This represents a decrease of 29%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund X-B during 2002 as compared to 2001.

Results of Operations—General Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	20.61	$	25.26	(18	%)
Average price per Mcf of gas	$	2.26	$	4.97	(55	%)
Oil production in barrels		14,400		15,900	(9	%)
Gas production in Mcf		21,800		25,100	(13	%)
Gross oil and gas revenue	$	346,059	$	526,481	(34	%)
Net oil and gas revenue	$	76,809	$	247,987	(69	%)
Oil & Gas Income Fund X-B distributions	$	—	$	252,000	(100	%)
Limited partner distributions	$	—	$	226,800	(100	%)
Per unit distribution to limited partners	$	—	$	20.83	(100	%)
Number of limited partner interests		10,889		10,889

Revenues

Oil & Gas Income Fund X-B’s oil and gas revenues decreased to $346,059 from $526,481 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 34%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-B decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.65 per barrel,

14

resulting in a decrease of approximately $67,000 in revenues. Oil sales represented 86% of total oil and gas sales during the six months ended June 30, 2002 as compared to 76% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-B decreased during the same period by 55%, or $2.71 per Mcf, resulting in a decrease of approximately $59,100 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $126,100. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,500 barrels, or 9%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $37,900 in revenues.

Gas production decreased approximately 3,300 Mcf, or 13%, during the same period, resulting in a decrease of approximately $16,400 in revenues.

The total decrease in revenues due to the change in production is approximately $54,300.

Costs and Expenses

Total costs and expenses decreased to $324,863 from $341,313 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 5%. The decrease is the result of lower depletion expense, lease operating costs and general and administrative expense.

1.  Lease operating costs and production taxes decreased 3%, or approximately $9,200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $17,000 for the six months ended June 30, 2002 from $24,000 for the same period in 2001. This represents a decrease of 29%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund X-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	22.42	$	28.15	(20	%)
Average price per Mcf of gas	$	3.40	$	3.97	(14	%)
Oil production in barrels		30,900		33,700	(8	%)
Gas production in Mcf		52,000		50,700	3	%
Gross oil and gas revenue	$	869,806	$	1,150,000	(24	%)
Net oil and gas revenue	$	278,649	$	597,207	(53	%)
Oil & Gas Income Fund X-B distributions	$	379,443	$	406,644	(7	%)
Limited partner distributions	$	341,499	$	365,980	(7	%)
Per unit distribution to limited partners	$	31.36	$	33.61	(7	%)
Number of limited partner interests		10,889		10,889

15

Revenues

Oil & Gas Income Fund X-B’s oil and gas revenues decreased to $869,806 from $1,150,000, for the years ended December 31, 2001 and 2000, respectively, a decrease of 24%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-B decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 20%, or $5.73 per barrel, resulting in a decrease of approximately $177,100 in revenues. Oil sales represented 80% of total oil and gas sales during the year ended December 31, 2001 as compared to 82% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-B decreased during the same period by 14%, or $.57 per Mcf, resulting in a decrease of approximately $29,600 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $206,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 2,800 barrels, or 8%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $78,800 in revenues.

Gas production increased approximately 1,300 Mcf, or 3%, during the same period, resulting in an increase of approximately $5,200 in revenues.

The net total decrease in revenues due to the change in production is approximately $73,600.

Costs and Expenses

Total costs and expenses increased to $734,017 from $658,633 for the years ended December 31, 2001 and 2000, respectively, an increase of 11%. The increase is the result of higher lease operating costs, general and administrative costs and depletion expense.

1.  Lease operating costs and production taxes increased 7%, or approximately $38,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $1,000, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $65,000 for the year ended December 31, 2001 from $29,000 for the same period in 2000. This represents an increase of 124%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-B’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Oil & Gas Income Fund X-B’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Oil & Gas Income Fund X-B during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $26,000 as of December 31, 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.15	$	16.15	74	%
Average price per Mcf of gas	$	3.97	$	2.26	76	%
Oil production in barrels		33,700		37,800	(11	%)
Gas production in Mcf		50,700		54,670	(7	%)
Gross oil and gas revenue	$	1,150,000	$	734,011	57	%
Net oil and gas revenue	$	597,207	$	249,535	139	%
Oil & Gas Income Fund X-B distributions	$	406,644	$	78,268	420	%
Limited partner distributions	$	365,980	$	71,268	414	%
Per unit distribution to limited partners	$	33.61	$	6.54	414	%
Number of limited partner interests		10,889		10,889

Revenues

Oil & Gas Income Fund X-B’s oil and gas revenues increased to $1,150,000 from $734,011 for the years ended December 31, 2000 and 1999, respectively, an increase of 57%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-B increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 74%, or $12.00 per barrel, resulting in an increase of approximately $404,400 in revenues. Oil sales represented 82% of total oil and gas sales during the year ended December 31, 2000 as compared to 83% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-B increased during the same period by 76%, or $1.71 per Mcf, resulting in an increase of approximately $86,700 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $491,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 4,100 barrels, or 11%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $66,200 in revenues.

Gas production decreased approximately 3,970 Mcf, or 7%, during the same period, resulting in a decrease of approximately $9,000 in revenues.

The total decrease in revenues due to the change in production is approximately $75,200.

Costs and Expenses

Total costs and expenses increased to $658,633 from $591,548 for the years ended December 31, 2000 and 1999, respectively, an increase of 11%. The increase is the result of higher lease operating costs, partially offset by a decrease in general and administrative costs and depletion expense.

1.  Lease operating costs and production taxes increased 14%, or approximately $68,300, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

17

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased less than 1%, or approximately $200, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $29,000 for the year ended December 31, 2000 from $30,000 for the same period in 1999. This represents a decrease of 3%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-B’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Oil & Gas Income Fund X-B’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $6,000 as of December 31, 1999.

Revenue and Distribution Comparison

Oil & Gas Income Fund X-B income for the years ended December 31, 2001, 2000 and 1999 was $138,618, $496,120 and $143,687, respectively. Excluding the effects of depreciation, depletion and amortization, net income would have been $203,618 in 2001, $525,120 in 2000 and $173,687 in 1999. Correspondingly, Oil & Gas Income Fund X-B distributions for the years ended December 31, 2001, 2000 and 1999 were $379,443, $406,644 and $78,268, respectively. These differences are indicative of the changes in oil and gas prices, production and property sales.

The source for the 2001 distributions of $379,443 were oil and gas operations of approximately $316,400 and the change in oil and gas properties of approximately $(16,700), with the balance from available cash on hand at the beginning of the period. The source for the 2000 distributions of $406,644 were oil and gas operations of approximately $493,500 and the change in oil and gas properties of approximately $(29,500), resulting in excess cash for contingencies or subsequent distributions. The source for the 1999 distributions of $78,268 were oil and gas operations of approximately $74,300 and the change in oil and gas properties of approximately $(7,700), with the balance from available cash on hand at the beginning of the period.

Total distributions during the year ended December 31, 2001 were $379,443 of which $341,499 was distributed to the limited partners and $37,944 to the general partners. The per unit distribution to limited partners during the same period was $31.36. Total distributions during the year ended December 31, 2000 were $406,644 of which $365,980 was distributed to the limited partners and $40,664 to the general partners. The per unit distribution to limited partners during the same period was $33.61. Total distributions during the year ended December 31, 1999 were $78,268 of which $71,268 was distributed to the limited partners and $7,000 to the general partners. The per unit distribution to limited partners during the same period was $6.54.

Liquidity and Capital Resources of Oil & Gas Income Fund X-B

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Oil & Gas Income Fund X-B knows of no material change, nor does it anticipate any such change.

Cash flows provided by operating activities were approximately $7,700 in the six months ended June 30, 2002 as compared to approximately $225,300 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $10,100 in the six months ended June 30, 2002 as compared to approximately $29,300 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was the addition of oil and gas properties.

18

There were no cash flows in the six months ended June 30, 2002, as compared to approximately $252,000 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $252,000 of which $226,800 was distributed to the limited partners and $25,200 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $20.83.

The sources for the 2001 distributions of $252,000 were oil and gas operations of approximately $225,300 and the change in oil and gas properties of approximately $(29,300), with the balance from available cash on hand at the beginning of the period.

Since inception of Oil & Gas Income Fund X-B, cumulative monthly cash distributions of $5,430,382 have been made to the partners. As of June 30, 2002, $4,913,799 or $451.26 per unit of limited partner interest has been distributed to the limited partners, representing a 90% return of the capital contributed.

As of June 30, 2002, Oil & Gas Income Fund X-B had approximately $80,800 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Oil & Gas Income Fund X-B.

Cash flows provided by operating activities were approximately $316,400 in 2001 compared to $493,500 in 2000 and approximately $74,300 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $16,700 in 2001 compared to $29,500 in 2000 and approximately $7,700 in 1999. The principle use of the 2001 cash flow from investing activities was additions to oil and gas properties.

Cash flows used in financing activities were approximately $379,100 in 2001 compared to $406,700 in 2000 and approximately $78,300 in 1999. The only use in the 2001 financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-B, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties Institutional Income Fund X-B, L.P., which we call Institutional Income Fund X-B, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Institutional Income Fund X-B. The purpose of the special meeting is for you to vote upon the merger of Institutional Income Fund X-B with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Institutional Income Fund X-B is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Institutional Income Fund X-B:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Institutional Income Fund X-B

• Compensation and distributions from Institutional Income Fund X-B

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Institutional Income Fund X-B for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Institutional Income Fund X-B’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Institutional Income Fund X-B as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Institutional Income Fund X-B, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Institutional Income Fund X-B in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market value for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Institutional Income Fund X-B’s assets. The Merger Value of Institutional Income Fund X-B is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Institutional Income Fund X-B, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Institutional Income Fund X-B by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Institutional Income Fund X-B. We believe, however, that Institutional Income Fund X-B will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Institutional Income Fund X-B. Our decision is based on the following factors in order of significance:

• Our method of valuation for Institutional Income Fund X-B uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Institutional Income Fund X-B, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Institutional Income Fund X-B. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger in this prospectus/proxy statement.”

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INSTITUTIONAL INCOME FUND X-B

The Merger Value for Institutional Income Fund X-B was determined by calculating its Net Asset Value and then dividing Institutional Income Fund X-B’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Institutional Income Fund X-B’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Institutional Income Fund X-B’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Institutional Income Fund X-B. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund X-B is 3.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Income Fund X-B
		Net Present Value of Reserves	$	1,495,029.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	103,688.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Institutional Income Fund X-B	$	1,598,717.00	calculated

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					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Institutional Income Fund X-B	$	1,598,717.00	calculated
	less	GP% owned by Southwest in Institutional Income Fund X-B (10%)	$	159,871.70	Partnership records
	less	LP% owned by Southwest in Institutional Income Fund X-B (3.99%)	$	63,788.81	Partnership records
	equals	Net Asset Value of Institutional Income Fund X-B owned by limited partners (excluding Southwest’s ownership %)	$	1,375,056.49	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships		32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Institutional Income Fund X-B (excluding Southwest’s ownership %)	$	1,375,056.49	calculated
	equals	The percentage of ownership of Institutional Income Fund X-B (other than Southwest) to the total Net Asset Value		1.75%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Institutional Income Fund X-B (other than Southwest)		1.75%	calculated
	equals	The number of shares of common stock attributable to Institutional Income Fund X-B (other than to Southwest)		29,574.04	calculated

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				Document(s) from which information was obtained or calculated
(7)		The number of shares of common stock attributable to Institutional Income Fund X-B (other than to Southwest)	29,574	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund X-B	10,685	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund X-B	3	calculated
(8)		The number of shares of special stock attributable to Institutional Income Fund X-B (other than to Southwest)	5,915	calculated
	divided by	The number of unit of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund X-B	10,685	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Institutional Income Fund X-B	.55	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK - Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Institutional Income Fund X-B for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	72,000	$	72,000	$	72,000	$	36,000
Administrative Overhead per Operating Agreements	$	76,392	$	73,966	$	80,315	$	38,476
Cash Distributions Paid to General Partners as General Partners(1)	$	40,180	$	27,674	$	12,000	$	5,000
Cash Distributions Paid to General Partner as Limited Partner	$	16,214	$	10,449	$	5,075	$	2,027

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⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Institutional Income Fund X-B’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	361,616	$	249,067	$	144,511	$	179,121	$	549,958	$	45,000

Return of Capital: 90%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR INSTITUTIONAL INCOME FUND X-B

Aggregate Initial Investment by the Limited Partners:	$	5,591	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	5,053	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	1,439	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	128.69	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		7.0	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	45.57	(2)(4)
—as of December 31, 2001:	$	46.75	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	21.95	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	94.49	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	106.54	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Institutional Income Fund X-B is equal to (1) the sum of (A) the present value of estimated future net revenues from Institutional Income Fund X-B’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Institutional Income Fund X-B is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Institutional Income Fund X-B is based upon (1) the sum of (A) the estimated net cash flow from the sale of Institutional Income Fund X-B’s reserves during a 12-year operating period

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and (B) the estimated residual value from the sale of Institutional Income Fund X-B’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Institutional Income Fund X-B is based upon (1) the sum of (A) the sale of Institutional Income Fund X-B’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Institutional Income Fund X-B’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Institutional Income Fund X-B and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Institutional Income Fund X-B is based upon (1) the sum of (A) Institutional Income Fund X-B’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Institutional Income Fund X-B.

INSTITUTIONAL INCOME FUND X-B

Set forth below is basic information about Institutional Income Fund X-B and its business and operations. It does not contain all the information about Institutional Income Fund X-B that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Institutional Income Fund X-B

General

Institutional Income Fund X-B was organized as a Delaware limited partnership on November 27, 1990. The offering of limited partner interests began December 1, 1990 as part of a shelf offering registered under the name Southwest Royalties Institutional 1990-91 Income Program. Minimum capital requirements for Institutional Income Fund X-B were met on March 11, 1991, with the offering of limited partnership interests concluding September 30, 1991, with total partner contributions of $5.6 million.

Principal Products, Marketing and Distribution

Institutional Income Fund X-B has acquired and holds royalty, overriding royalty and net profit interests in oil and gas properties located in Arkansas, Louisiana, New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	66%	34%
2000	72%	28%
1999	75%	25%

As the table indicates, the majority of Institutional Income Fund X-B’s revenue is from its oil production.

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Customer Dependence

No material portion of Institutional Income Fund X-B’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Institutional Income Fund X-B. Four purchasers accounted for 67% of Institutional Income Fund X-B’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 29%, Duke Energy Field Services for 17%, Mobil Corporation for 11% and Exxon Company USA for 10%. Three purchasers accounted for 78% of Institutional Income Fund X-B’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 34%, Mobil Corporation for 24% and Phillips 66 for 20%. Three purchasers accounted for 73% of Institutional Income Fund X-B’s total oil and gas production during 1999: Scurlock Permian LLC for 30%, Mobil Corporation for 26% and Phillips 66 for 17%. All purchasers of Institutional Income Fund X-B’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Institutional Income Fund X-B’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Institutional Income Fund X-B’s sales of oil and gas production.

Properties

As of December 31, 2001, Institutional Income Fund X-B possessed an interest in oil and gas properties located in Columbia County, Arkansas; Calcasieu Parish, Louisiana; Eddy and Lea Counties, New Mexico; and Crane, Duval, Howard, Midland, Reeves, Schleicher, Scurry, Ward, Winkler and Yoakum Counties, Texas. These properties consist of various interests in approximately 197 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

There were no property sales during 2001, 2000 and 1999.

Significant Properties

The following table reflects the significant properties in which Institutional Income Fund X-B has an interest:

	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
Name and Location			Oil (Bbls)	Gas (Mcf)
NE Vacuum ABO Acquisition Lea County, New Mexico	9/91 at 25% to 50% net profits interest	7	119,000	86,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Institutional Income Fund X-B’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.44 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $1.80 per Mcf.

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As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-B” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Institutional Income Fund X-B. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying the industry audit standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Institutional Income Fund X-B has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Institutional Income Fund X-B’s present reserves.

Because Institutional Income Fund X-B does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Institutional Income Fund X-B retains a carried interest under the terms of a farm-out or receives cash.

Institutional Income Fund X-B, or the owners of properties in which Institutional Income Fund X-B owns an interest, can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-B” in this prospectus supplement.

Market for Institutional Income Fund X-B’s Limited Partnership Interests and Related Matters

Market Information

Managing general partner has the right, but not the obligation, to purchase limited partner interests of Institutional Income Fund X-B should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the managing general partner in its sole and absolute discretion. As of December 31, 2001, no units of limited partner interest were purchased by the managing general partner. In 2000, 118 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $30.71 per unit. In 1999, 42 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $62.96 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

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Number of Limited Partner Interest Holders

As of December 31, 2001, there were 593 holders of limited partner interest in Institutional Income Fund X-B.

Distributions

Pursuant to Article III, Section 3.05 of Institutional Income Fund X-B’s Certificate and Agreement of Limited Partnership, “Net Cash Flow” is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Institutional Income Fund X-B’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Institutional Income Fund X-B], as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $401,796, with $361,616 distributed to the limited partners and $40,180 to the general partners. For the year ended December 31, 2001, distributions of $32.34 per unit of limited partner interest were made, based upon 11,181 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $276,741, with $249,067 distributed to the limited partners and $27,674 to the general partners. For the year ended December 31, 2000, distributions of $22.28 per unit of limited partner interest were made, based upon 11,181 units of limited partner interest outstanding. During 1999, distributions were made totaling $156,511, with $144,511 distributed to the limited partners and $12,000 to the general partners. For the year ended December 31, 1999, distributions of $12.92 per unit of limited partner interest were made, based upon 11,181 units of limited partner interest outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA  FOR INSTITUTIONAL INCOME FUND X-B

The following tables present summary selected financial information and operating data for Institutional Income Fund X-B for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-B” found elsewhere in this prospectus supplement and the financial statements and related notes for Institutional Income Fund X-B included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	294,691		479,929		802,908		884,770		559,510		633,441		1,273,052
Net income (loss)	36,811		186,340		251,639		335,842		89,273		(664,064	)	256,108
Partners’ share of net income (loss):
General partners	5,081		20,834		30,664		36,084		11,827		(11,530	)	45,411
Partners	31,730		165,506		220,975		299,758		77,446		(652,534	)	210,697
Partners’ net income (loss) per unit of limited partner interest	2.84		14.80		19.76		26.81		6.93		(58.36	)	18.84
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	37,173		211,197		369,849		336,665		40,381		(40,102	)	501,605
Net cash provided by investing activities	—		—		—		—		7,990		352,101		95,874
Net cash used in financing activities	(50,036	)	(224,952	)	(401,760	)	(276,779	)	(156,521	)	(189,973	)	(607,058	)
Net increase (decrease) in cash and cash equivalents	(12,863	)	(13,755	)	(31,911	)	59,886		(108,150	)	122,026		(9,579	)
EBITDA	50,811		208,340		306,639		360,842		118,273		(115,302	)	454,108
Cash distributions	50,000		225,000		401,796		276,741		156,511		190,021		607,058
Partners’ cash distributions per $500 investment	4.02		18.11		32.34		22.28		12.92		16.02		49.19

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	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Balance Sheet Data:
Cash and cash equivalents	36,089		67,108		48,952		80,863		20,977		129,127		7,101
Oil and gas properties, net at book value	364,029		411,029		378,029		433,029		458,029		495,019		1,357,382
Total assets	467,718		592,452		480,943		631,064		572,001		639,249		1,493,285
Total liabilities	1		49		37		1		39		49		—
Partners’ equity	509,467		626,384		522,737		663,378		612,687		679,752		1,511,407
General partners’ equity	(41,750	)	(33,981	)	(41,831	)	(32,315	)	(40,725	)	(40,552	)	(18,122	)
Partner’s book value per $500 investment	45.57		56.02		46.75		59.33		54.80		60.80		135.18
Production:
Oil production (Bbls)	9,900		11,200		21,800		22,000		25,700		39,700		53,100
Natural gas production (Mcf)	33,700		37,700		76,700		64,100		67,350		88,400		119,300
Equivalent production (Boe)	15,517		17,483		34,583		32,683		36,925		54,433		72,983
Average Sales Price:
Oil price (per/Bbl)	21.58		26.83		24.22		28.80		16.34		12.02		18.74
Natural gas price (per/Mcf)	2.41		4.76		3.59		3.92		2.07		1.77		2.31
Average sales price (per Boe)	18.99		27.45		23.22		27.07		15.15		11.64		17.44
Operating and Overhead Costs (per Boe)
Lease operating expense	11.93		11.51		10.57		11.99		8.99		11.46		9.20
Production taxes	1.32		1.91		1.62		1.80		.93		.67		.98
General and Administrative Expense (per Boe)	2.48		2.22		2.25		2.34		2.08		1.67		1.11
Total	15.73		15.64		14.44		16.13		12.00		13.80		11.29
Cash Operating Margin (per Boe)	3.26		11.81		8.78		10.94		3.15		(2.16	)	6.15
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.90		1.26		1.59		.76		.79		10.09		2.71
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	617,000		698,000		615,000		793,000		684,000		504,000		882,000
Oil (Bbls)	217,000		283,000		195,000		301,000		310,000		95,000		399,000
Total (Boe)	320,000		399,000		298,000		433,000		424,000		179,000		546,000

⁽¹⁾ Institutional Income Fund X-B has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	1,599,000
Merger Value per $500 investment	$	128.69

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-B

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Institutional Income Fund X-B will likely experience the historical production decline of approximately 10% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.48	$	26.21	(7	%)
Average price per Mcf of gas	$	2.85	$	3.86	(26	%)
Oil production in barrels		4,700		5,600	(16	%)
Gas production in Mcf		16,300		19,800	(18	%)
Income from net profits interests	$	59,801	$	98,922	(40	%)
Institutional Income Fund X-B distributions	$	—	$	100,000	(100	%)
Limited partner distributions	$	—	$	90,000	(100	%)
Per unit distribution to limited partners	$	—	$	8.05	(100	%)
Number of limited partner interests		11,181		11,181

Revenues

Institutional Income Fund X-B’s income from net profits interests decreased to $59,801 from $98,922 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 40%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-B decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 7%, or $1.73 per barrel, resulting in a decrease of approximately $8,100 in income from net profits interests. Oil sales represented 71% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 66% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund X-B decreased during the same period by 26%, or $1.01 per Mcf, resulting in a decrease of approximately $16,500 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $24,600. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 900 barrels, or 16%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $23,600 in income from net profits interests.

Gas production decreased approximately 3,500 Mcf, or 18%, during the same period, resulting in a decrease of approximately $13,500 in income from net profits interests.

13

The total decrease in income from net profits interests due to the change in production is approximately $37,100. The decrease in gas production is due to major repairs and maintenance performed during 2001 that caused an initial increase during the quarter ended June 30, 2001.

3.  Lease operating costs and production taxes decreased 23%, or approximately $31,100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in lease operating expense is due to maintenance and other repairs being performed during the second quarter of 2001.

Costs and Expenses

Total costs and expenses decreased to $27,205 from $31,702 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 14%. The decrease is primarily the result of lower depletion expense and general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 3%, or approximately $500, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $8,000 for the quarter ended June 30, 2002, from $12,000 for the same period in 2001. This represents a decrease of 33%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund X-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.58	$	26.83	(20	%)
Average price per Mcf of gas	$	2.41	$	4.76	(49	%)
Oil production in barrels		9,900		11,200	(12	%)
Gas production in Mcf		33,700		37,700	(11	%)
Income from net profits interests	$	89,060	$	245,183	(64	%)
Institutional Income Fund X-B distributions	$	50,000	$	225,000	(78	%)
Limited partner distributions	$	45,000	$	202,500	(78	%)
Per unit distribution to limited partners	$	4.02	$	18.11	(78	%)
Number of limited partner interests		11,181		11,181

Revenues

Institutional Income Fund X-B’s income from net profits interests decreased to $89,060 from $245,183 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 64%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-B decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 20%, or $5.25 per barrel,

14

resulting in a decrease of approximately $52,000 in income from net profits interests. Oil sales represented 72% of total oil and gas sales during the six months ended June 30, 2002 as compared to 63% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund X-B decreased during the same period by 49%, or $2.35 per Mcf, resulting in a decrease of approximately $79,200 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $131,200. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,300 barrels, or 12%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $34,900 in income from net profits interests.

Gas production decreased approximately 4,000 Mcf, or 11%, during the same period, resulting in a decrease of approximately $19,000 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $53,900.

3.  Lease operating costs and production taxes decreased 12%, or approximately $29,100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $52,488 from $60,859 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 14%. The decrease is primarily the result of lower general and administrative expense and depletion expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $400, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $14,000 for the six months ended June 30, 2002 from $22,000 for the same period in 2001. This represents a decrease of 36%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-B’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund X-B during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	24.22	$	28.80	(16	%)
Average price per Mcf of gas	$	3.59	$	3.92	(8	%)
Oil production in barrels		21,800		22,000	(1	%)
Gas production in Mcf		76,700		64,100	20	%
Income from net profits interests	$	381,306	$	433,937	(12	%)
Institutional Income Fund X-B distributions	$	401,796	$	276,741	45	%
Limited partner distributions	$	361,616	$	249,067	45	%
Per unit distribution to limited partners	$	32.34	$	22.28	45	%
Number of limited partner interests		11,181		11,181

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Revenues

Institutional Income Fund X-B’s income from net profits interests decreased to $381,306 from $433,937 for the years ended December 31, 2001 and 2000, respectively, a decrease of 12%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-B decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 16%, or $4.58 per barrel, resulting in a decrease of approximately $99,800 in income from net profits interests. Oil sales represented 66% of total oil and gas sales during the year ended December 31, 2001 as compared to 72% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Institutional Income Fund X-B decreased during the same period by 8%, or $.33 per Mcf, resulting in a decrease of approximately $25,300 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $125,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 200 barrels, or 1%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $5,800 in income from net profits interests.

Gas production increased approximately 12,600 Mcf, or 20%, during the same period, resulting in an increase of approximately $49,400 in income from net profits interests.

The net total increase in income from net profits interests due to the change in production is approximately $43,600. The increase in gas production is due to successful workovers, repairs, and maintenance performed on one lease during 2001.

3.  Lease operating costs and production taxes decreased 6%, or approximately $29,200, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

Costs and Expenses

Total costs and expenses increased to $132,887 from $101,486 for the years ended December 31, 2001 and 2000, respectively, an increase of 31%. The increase is the result of higher depletion expense and general and administrative costs.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $1,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $55,000 for the year ended December 31, 2001 from $25,000 for the same period in 2000. This represents an increase of 120%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-B’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Institutional Income Fund X-B’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Institutional Income Fund X-B during

16

2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $16,000 as of December 31, 2000.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.80	$	16.34	76	%
Average price per Mcf of gas	$	3.92	$	2.07	89	%
Oil production in barrels		22,000		25,700	(14	%)
Gas production in Mcf		64,100		67,350	(5	%)
Income from net profits interests	$	433,937	$	193,199	125	%
Institutional Income Fund X-B distributions	$	276,741	$	156,511	77	%
Limited partner distributions	$	249,067	$	144,511	72	%
Per unit distribution to limited partners	$	22.28	$	12.92	72	%
Number of limited partner interests		11,181		11,181

Revenues

Institutional Income Fund X-B’s income from net profits interests increased to $433,937 from $193,199 for the years ended December 31, 2000 and 1999, respectively, an increase of 125%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-B increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 76%, or $12.46 per barrel, resulting in an increase of approximately $274,100 in income from net profits interests. Oil sales represented 72% of total oil and gas sales during the year ended December 31, 2000 as compared to 75% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Institutional Income Fund X-B increased during the same period by 89%, or $1.85 per Mcf, resulting in an increase of approximately $118,600 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $392,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 3,700 barrels, or 14%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $60,500 in income from net profits interests.

Gas production decreased approximately 3,250 Mcf, or 5%, during the same period, resulting in a decrease of approximately $6,700 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $67,200.

3.  Lease operating costs and production taxes increased 23%, or approximately $84,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating

17

costs and production taxes is due in part to an increase in major repairs and maintenance and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Institutional Income Fund X-B to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

Costs and Expenses

Total costs and expenses decreased to $101,486 from $105,975 for the years ended December 31, 2000 and 1999, respectively, a decrease of 4%. The decrease is the result of lower depletion expense and general and administrative costs.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $25,000 for the year ended December 31, 2000 from $29,000 for the same period in 1999. This represents a decrease of 14%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-B’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Institutional Income Fund X-B’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $7,000 as of December 31, 1999.

Revenue and Distribution Comparison

Institutional Income Fund X-B net income for the years ended December 31, 2001, 2000 and 1999 was $251,639, $335,842 and $89,273, respectively. Excluding the effects of depreciation, depletion and amortization, net income would have been $306,639 in 2001, $360,842 in 2000 and $118,273 in 1999. Correspondingly, Institutional Income Fund X-B distributions for the years ended December 31, 2001, 2000 and 1999 were $401,796, $276,741 and $156,511, respectively. These differences are indicative of the changes in oil and gas prices, production and property sales.

The sources for the 2001 distributions of $401,796 were oil and gas operations of approximately $369,800, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $276,741 were oil and gas operations of approximately $336,700, resulting in excess cash for contingencies and subsequent distribution. The sources for the 1999 distributions of $156,511 were oil and gas operations of approximately $40,400 and the change in oil and gas properties of approximately $8,000, with the balance from available cash on hand at the beginning of the period.

Total distributions during the year ended December 31, 2001 were $401,796 of which $361,616 was distributed to the limited partners and $40,180 to the general partners. The per unit distribution to limited partners during the same period was $32.34. Total distributions during the year ended December 31, 2000 were $276,741 of which $249,067 was distributed to the limited partners and $27,674 to the general partners. The per unit distribution to limited partners during the same period was $22.28. Total distributions during the year ended December 31, 1999 were $156,511 of which $144,511 was distributed to the limited partners and $12,000 to the general partners. The per unit distribution to limited partners during the same period was $12.92.

18

Liquidity and Capital Resources of Institutional Income Fund X-B

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Institutional Income Fund X-B knows of no material change, nor does it anticipate any such change.

Cash flows provided by operating activities were approximately $37,200 in the six months ended June 30, 2002 as compared to approximately $211,200 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in financing activities were approximately $50,000 in the six months ended June 30, 2002 as compared to approximately $225,000 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $50,000 of which $45,000 was distributed to the limited partners and $5,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2002 was $4.02. Total distributions during the six months ended June 30, 2001 were $225,000 of which $202,500 was distributed to the limited partners and $22,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $18.11.

The sources for the 2002 distributions of $50,000 were oil and gas operations of approximately $37,200, with the balance from available cash on hand at the beginning of the period. The sources for the 2001 distributions of $225,000 were oil and gas operations of approximately $211,200, with the balance from available cash on hand at the beginning of the period.

Since inception of Institutional Income Fund X-B, cumulative monthly cash distributions of $5,549,098 have been made to the partners. As of June 30, 2002, $5,053,231 or $451.95 per unit of limited partner interest has been distributed to the limited partners, representing a 90% return of the capital contributed.

As of June 30, 2002, Institutional Income Fund X-B had approximately $103,700 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Institutional Income Fund X-B.

Cash flows provided by operating activities were approximately $369,800 in 2001 compared to $336,700 in 2000 and approximately $40,400 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Institutional Income Fund X-B had no cash flows from investing activities in 2001 and 2000. Cash flows provided by investing activities were approximately $8,000 in 1999.

Cash flows used in financing activities were approximately $401,800 in 2001 compared to $276,800 in 2000 and approximately $156,500 in 1999. The only use in financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST OIL & GAS INCOME FUND X-C, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Oil & Gas Income Fund X-C, L.P., which we call Oil & Gas Income Fund X-C, and supplements the prospectus/proxy statement dated             , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Oil & Gas Income Fund X-C. The purpose of the special meeting is for you to vote upon the merger of Oil & Gas Income Fund X-C with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Oil & Gas Income Fund X-C is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on             .

This document contains the following information concerning Oil & Gas Income Fund X-C:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Oil & Gas Income Fund X-C

• Compensation and distributions from Oil & Gas Income Fund X-C

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Oil & Gas Income Fund X-C for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Oil & Gas Income Fund X-C’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999.

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Oil & Gas Income Fund X-C as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Oil & Gas Income Fund X-C, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Oil & Gas Income Fund X-C in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Oil & Gas Income Fund X-C’s assets. The Merger Value of Oil & Gas Income Fund X-C is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Oil & Gas Income Fund X-C, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Oil & Gas Income Fund X-C by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Oil & Gas Income Fund X-C. We believe, however, that Oil & Gas Income Fund X-C will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Oil & Gas Income Fund X-C. Our decision is based on the following factors in order of significance:

• Our method of valuation for Oil & Gas Income Fund X-C uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Oil & Gas Income Fund X-C, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Oil & Gas Income Fund X-C. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR OIL & GAS INCOME FUND X-C

The Merger Value for Oil & Gas Income Fund X-C was determined by calculating its Net Asset Value and then dividing Oil & Gas Income Fund X-C’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Oil & Gas Income Fund X-C’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Oil & Gas Income Fund X-C’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Oil & Gas Income Fund X-C. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-C is 3.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Oil & Gas Income Fund X-C
		Net Present Value of Reserves	$	793,219.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	36,265.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Oil & Gas Income Fund X-C	$	829,484.00	calculated

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					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Oil & Gas Income Fund X-C	$	829,484.00	calculated
	less	GP% owned by Southwest in Oil & Gas Income Fund X-C (10.0%)	$	82,948.40	Partnership records
	less	LP% owned by Southwest in Oil & Gas Income Fund X-C (3.05%)	$	25,299.26	Partnership records
	equals	Net Asset Value of Oil & Gas Income Fund X-C owned by limited partners (excluding Southwest’s ownership %)	$	721,236.34	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Oil & Gas Income Fund X-C (excluding Southwest’s ownership %)	$	721,236.34	calculated
	equals	The percentage of ownership of Oil & Gas Income Fund X-C (other than Southwest) to the total Net Asset Value		.92%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Oil & Gas Income Fund X-C (other than Southwest)		92%	calculated
	equals	The number of shares of common stock attributable to Oil & Gas Income Fund X-C (other than to Southwest)		15,512.00	calculated
(7)		The number of shares of common stock attributable to Oil & Gas Income Fund X-C (other than to Southwest)		15,512	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Oil & Gas Income Fund X-C		6,034	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-C		3	calculated

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				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Oil & Gas Income Fund X-C (other than to Southwest)	3,102	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Oil & Gas Income Fund X-C	6,034	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Oil & Gas Income Fund X-C	.51	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Oil & Gas Income Fund X-C for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	36,000	$	36,000	$	36,000	$	18,000
Administrative Overhead per Operating Agreements	$	180,026	$	172,181	$	173,796	$	90,002
Cash Distributions Paid to General Partners as General Partners(1)	$	36,148	$	27,730	$	9,500	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	8,498	$	6,308	$	2,559	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Oil & Gas Income Fund X-C’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	325,331	$	249,570	$	103,704	$	168,750	$	657,450	$—
Return of Capital: 100%  Return on Capital: 7%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR OIL & GAS INCOME FUND X-C

Aggregate Initial Investment by the Limited Partners:	$	3,123	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	3,327	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	747	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	119.52	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		6.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	40.35	(2)(4)
—as of December 31, 2001:	$	45.20	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	78.37	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	78.36	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	98.36	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

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⁽³⁾ The Merger Value for Oil & Gas Income Fund X-C is equal to (1) the sum of (A) the present value of estimated future net revenues from Oil & Gas Income Fund X-C’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Oil & Gas Income Fund X-C is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Oil & Gas Income Fund X-C is based upon (1) the sum of (A) the estimated net cash flow from the sale of Oil & Gas Income Fund X-C’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Oil & Gas Income Fund X-C’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Oil & Gas Income Fund X-C is based upon (1) the sum of (A) the sale of Oil & Gas Income Fund X-C’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Oil & Gas Income Fund X-C’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Oil & Gas Income Fund X-C and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Oil & Gas Income Fund X-C is based upon (1) the sum of (A) Oil & Gas Income Fund X-C’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Oil & Gas Income Fund X-C.

OIL & GAS INCOME FUND X-C

Set forth below is basic information about Oil & Gas Income Fund X-C and its business and operations. It does not contain all the information about Oil & Gas Income Fund X-C that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Oil & Gas Income Fund X-C

General

Oil & Gas Income Fund X-C was organized as a Delaware limited partnership on September 20, 1991. The offering of limited partner interests began October 1, 1991 as part of a shelf offering registered under the name Southwest Oil & Gas 1990-91 Income Program. Minimum capital requirements for Oil & Gas Income Fund X-C were met on January 13, 1992 and concluded April 30, 1992.

Principal Products, Marketing and Distribution

Oil & Gas Income Fund X-C has acquired and holds working interests in oil and gas properties located in Alabama, Kansas, Louisiana, New Mexico, Oklahoma and Texas.

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Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	72%	28%
2000	89%	11%
1999	78%	22%

As the table indicates, the majority of Oil & Gas Income Fund X-C’s revenue is from its oil production.

Customer Dependence

The managing general partner intends that no material portion of Oil & Gas Income Fund X-C’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Oil & Gas Income Fund X-C. Three purchasers accounted for 85% of Oil & Gas Income Fund X-C’s total oil and gas production during 2001: Teppco Crude Oil LLC for 60%, George L McLeod Inc. for 14% and Plains All American Pipeline, L.P. for 11%. Two purchasers accounted for 84% of Oil & Gas Income Fund X-C’s total oil and gas production during 2000: Teppco Crude oil LLC for 73% and Plains All American Pipeline, L.P. for 11%. Three purchasers accounted for 82% of Oil & Gas Income Fund X-C’s total oil and gas production during 1999: Teppco Crude Oil LLC for 62%, George L. McLeod Inc. for 10% and Scurlock Permian LLC for 10%. All purchasers of Oil & Gas Income Fund X-C’s oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Oil & Gas Income Fund X-C’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Oil & Gas Income Fund X-C’s sales of oil and gas production.

Properties

As of December 31, 2001, Oil & Gas Income Fund X-C possessed an interest in oil and gas properties located in Escambia and Lamar Counties, Alabama; Labette and Neosho Counties, Kansas; La Fourche, Pointe Coupe and Terrebonne Parishes, Louisiana; Chaves, Eddy, and Lea Counties, New Mexico; Custer, Roger Mills and Washita Counties, Oklahoma; and Colorado, Dickens, Hemphill, Live Oak, Martin, Mitchell, Scurry, Upton and Yoakum Counties, Texas. These properties consist of various interests in 422 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletions.

There were no property sales during 2001 and 2000. During 1999, eight leases were sold for approximately $18,644.

Significant Properties

The following table reflects the significant property in which Oil & Gas Income Fund X-C has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Kelt Ohio Acquisition Chaves County, New Mexico	1/94 at 25% to 50% working interest	1	1,000	253,000
Mettie Poole Acquisition Colorado County, Texas LaFourche Parish Louisiana	10/92 at 1% to 26% working interest	1	3,000	128,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Oil & Gas Income Fund X-C’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

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Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.48 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $1.85 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-C” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Oil & Gas Income Fund X-C. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Oil & Gas Income Fund X-C has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Oil & Gas Income Fund X-C’s present reserves.

Because Oil & Gas Income Fund X-C does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Oil & Gas Income Fund X-C retains a carried interest under the terms of a farm-out, or receives cash.

Oil & Gas Income Fund X-C or the owners of properties in which Oil & Gas Income Fund X-C owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-C” in this prospectus supplement.

Market for Oil & Gas Income Fund X-C’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Oil & Gas Income Fund X-C should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the managing general partner in its sole and

9

absolute discretion. In 2001, 50 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $148.04 per unit. In 2000, 8 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $68.25 per unit. In 1999, 66 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $79.62 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 291 holders of limited partner interest in Oil & Gas Income Fund X-C.

Distributions

Pursuant to Article III, Section 3.05 of Oil & Gas Income Fund X-C’s Certificate and Agreement of Limited Partnership, “Net Cash Flow” is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Oil & Gas Income Fund X-C’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Oil & Gas Income Fund X-C], as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $361,479, with $325,331 distributed to the limited partners and $36,148 to the general partners. For the year ended December 31, 2001, distributions of $52.09 per unit of limited partner interest were made, based upon 6,246 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $277,300, with $249,570 distributed to the limited partners and $27,730 to the general partners. For the year ended December 31, 2000, distributions of $39.96 per unit of limited partner interest were made, based upon 6,246 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $113,204, with $103,704 distributed to the limited partners and $9,500 to the general partners. For the year ended December 31, 1999, distributions of $16.60 per unit of limited partner interest were made, based upon 6,246 units of limited partner interest outstanding.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

OIL & GAS INCOME FUND X-C

The following tables present summary selected financial information and operating data for Oil & Gas Income Fund X-C for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-C” found elsewhere in this prospectus supplement and the financial statements and related notes for Oil & Gas Income Fund X-C included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	309,316		498,314		871,673		929,367		734,832		672,717		1,190,719
Net income (loss)	(31,424	)	144,917		125,209		282,522		134,810		(104,046	)	345,547
Partners’ share of net income (loss):
General partners	(1,142	)	19,492		25,721		32,052		18,481		9,295		49,955
Partners	(30,282	)	125,425		99,488		250,470		116,329		(113,341	)	295,592
Partners’ net income (loss) per unit of limited partner interest	(4.85	)	20.08		15.93		40.10		18.62		(18.15	)	47.33
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	9,006		241,994		331,172		331,134		120,001		175,260		539,596
Net cash provided by investing activities	(18,386	)	177		(7,152	)	(14,870	)	(3,273	)	26,143		(7,771	)
Net cash used in financing activities	—		(225,000	)	(361,348	)	(277,300	)	(113,111	)	(187,708	)	(730,475	)
Net increase (decrease) in cash and cash equivalents	(9,380	)	17,171		(37,328	)	38,964		3,617		13,695		(198,650	)
EBITDA	(11,424	)	194,917		257,209		320,522		184,810		92,954		499,547
Cash distributions	—		225,000		361,479		277,300		113,204		187,500		730,500
Partners’ cash distributions per $500 investment	—		32.42		52.09		39.96		16.60		27.02		105.26

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	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Balance Sheet Data:
Cash and cash equivalents	18,691	82,570	28,071	65,399	26,435	22,818	9,123
Oil and gas properties, net at book value	201,824	278,109	203,438	328,286	351,416	398,143	619,586
Total assets	238,220	425,700	269,644	505,783	500,561	478,955	770,617

Total liabilities	—		—		131		—		—		—		116
Partners’ equity	252,041		431,091		282,323		508,166		507,266		494,641		776,732
General partners’ equity	(13,952	)	(5,391	)	(12,810	)	(2,383	)	(6,705	)	(15,686	)	(6,231	)
Partner’s book value per $500 investment	40.35		69.02		45.20		81.36		81.21		79.19		124.36
Production:
Oil production (Bbls)	13,500		14,200		28,700		30,000		35,190		42,500		47,500
Natural gas production (Mcf)	20,600		30,700		55,000		27,700		74,540		104,900		129,800
Equivalent production (Boe)	16,933		19,317		37,867		34,617		47,613		59,983		69,133
Average Sales Price:
Oil price (per/Bbl)	19.52		24.37		21.79		27.55		16.28		10.90		18.03
Natural gas price (per/Mcf)	2.22		4.95		4.48		3.71		2.17		2.00		2.58
Average sales price (per Boe)	18.27		25.80		23.02		26.85		15.43		11.22		17.22
Operating and Overhead Costs (per Boe)
Lease operating expense	16.96		13.52		14.24		15.16		9.92		8.21		8.53
Production taxes	.78		1.21		.97		1.34		.79		.61		.95
General and Administrative Expense (per Boe)	1.21		1.07		1.09		1.17		.87		.87		.64
Total	18.95		15.80		16.30		17.67		11.58		9.69		10.12
Cash Operating Margin (per Boe)	(.68	)	10.00		6.72		9.18		3.85		1.53		7.10
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.18		2.59		3.49		1.10		1.05		3.28		2.23
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	520,000		466,000		455,000		563,000		669,000		573,000		1,170,000
Oil (Bbls)	68,000		85,000		28,000		115,000		168,000		40,000		127,000
Total (Boe)	155,000		163,000		104,000		209,000		279,000		135,000		322,000

⁽¹⁾ Oil & Gas Income Fund X-C has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$829,000
Merger Value per $500 investment	$119.52

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR OIL & GAS INCOME FUND X-C

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Oil & Gas Income Fund X-C will likely experience the historical production decline of approximately 7% per year from the prior year’s production.

Results of Operations—General Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.55	$	23.89	(6	%)
Average price per Mcf of gas	$	2.54	$	3.54	(28	%)
Oil production in barrels		6,700		7,200	(7	%)
Gas production in Mcf		9,300		15,500	(40	%)
Gross oil and gas revenue	$	174,722	$	200,383	(13	%)
Net oil and gas revenue	$	13,157	$	52,215	(75	%)
Oil & Gas Income Fund X-C distributions	$	—	$	100,000	(100	%)
Limited partner distributions	$	—	$	90,000	(100	%)
Per unit distribution to limited partners	$	—	$	14.41	(100	%)
Number of limited partner interests		6,246		6,246

Revenues

Oil & Gas Income Fund X-C’s oil and gas revenues decreased to $174,722 from $200,383 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 13%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-C decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 6%, or $1.34 per barrel, resulting in a decrease of approximately $9,000 in revenues. Oil sales represented 86% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 76% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-C decreased during the same period by 28%, or $1.00 per Mcf, resulting in a decrease of approximately $9,300 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $18,300. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 500 barrels, or 7%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $11,900 in revenues.

Gas production decreased approximately 6,200 Mcf, or 40%, during the same period, resulting in a decrease of approximately $21,900 in revenues.

The total decrease in revenues due to the change in production is approximately $33,800. Gas production is down primarily due to downtime on one lease in addition to a non-operated lease having a steep natural decline.

13

Costs and Expenses

Total costs and expenses decreased to $182,785 from $189,606 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 4%. The decrease is the result of lower general and administrative and depletion expense, partially offset by an increase in lease operating expense.

1.  Lease operating costs and production taxes increased 9%, or approximately $13,400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $200, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $11,000 for the quarter ended June 30, 2002, from $31,000 for the same period in 2001. This represents a decrease of 65%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-C’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund X-C during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	19.52	$	24.37	(20	%)
Average price per Mcf of gas	$	2.22	$	4.95	(55	%)
Oil production in barrels		13,500		14,200	(5	%)
Gas production in Mcf		20,600		30,700	(33	%)
Gross oil and gas revenue	$	309,316	$	498,314	(38	%)
Net oil and gas revenue	$	9,022	$	213,580	(96	%)
Oil & Gas Income Fund X-C distributions	$	—	$	225,000	(100	%)
Limited partner distributions	$	—	$	202,500	(100	%)
Per unit distribution to limited partners	$	—	$	32.42	(100	%)
Number of limited partner interests		6,246		6,246

Revenues

Oil & Gas Income Fund X-C’s oil and gas revenues decreased to $309,316 from $498,314 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 38%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-C decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 20%, or $4.85 per barrel, resulting in a decrease of approximately $65,500 in revenues. Oil sales represented 85% of total oil and gas sales during the six months ended June 30, 2002 as compared to 69% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-C decreased during the same period by 55%, or $2.73 per Mcf, resulting in a decrease of approximately $56,200 in revenues.

14

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $121,700. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 700 barrels, or 5%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $17,100 in revenues.

Gas production decreased approximately 10,100 Mcf, or 33%, during the same period, resulting in a decrease of approximately $50,000 in revenues.

The total decrease in revenues due to the change in production is approximately $67,100. Gas production is down primarily due to downtime on one lease in addition to a non-operated lease having a steep natural decline.

Costs and Expenses

Total costs and expenses decreased to $340,829 from $355,400 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 4%. The decrease is the result of a lower depletion expense and general and administrative expense, partially offset by an increase in lease operating costs.

1.  Lease operating costs and production taxes increased 5%, or approximately $15,600, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 1%, or approximately $100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $20,000 for the six months ended June 30, 2002 from $50,000 for the same period in 2001. This represents a decrease of 60%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-C’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Oil & Gas Income Fund X-C during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	21.79	$	27.55	(21	%)
Average price per Mcf of gas	$	4.48	$	3.71	21	%
Oil production in barrels		28,700		30,000	(4	%)
Gas production in Mcf		55,000		27,700	99	%
Gross oil and gas revenue	$	871,673	$	929,367	(6	%)
Net oil and gas revenue	$	295,710	$	357,918	(17	%)
Oil & Gas Income Fund X-C distributions	$	361,479	$	277,300	30	%
Limited partner distributions	$	325,331	$	249,570	30	%
Per unit distribution to limited partners	$	52.09	$	39.96	30	%
Number of limited partner interests		6,246		6,246

15

Revenues

Oil & Gas Income Fund X-C’s oil and gas revenues decreased to $871,673 from $929,367 for the years ended December 31, 2001 and 2000, respectively, a decrease of 6%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-C decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 21%, or $5.76 per barrel, resulting in a decrease of approximately $165,300 in revenues. Oil sales represented 72% of total oil and gas sales during the year ended December 31, 2001 as compared to 89% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-C increased during the same period by 21%, or $.77 per Mcf, resulting in an increase of approximately $42,400 in revenues.

The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $207,700. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,300 barrels, or 4%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $35,800 in revenues.

Gas production increased approximately 27,300 Mcf, or 99%, during the same period, resulting in an increase of approximately $101,300 in revenues.

The net total increase in revenues due to the change in production is approximately $65,500. Oil & Gas Income Fund X-C’s dramatic increase in gas production was primarily in connection with one well. Oil & Gas Income Fund X-C was informed that a workover which was performed during the last quarter of 1999 on a non-operated well was not only unsuccessful but caused the well to shut down. This well was not believed to be recoverable; thus, the loss to Oil & Gas Income Fund X-C was considered to be permanent. This well represented approximately 2,890 Mcf a month. Total decline for Oil & Gas Income Fund X-C during the year ended December 31, 2000 in connection with this non-operated well was approximately 36,700 Mcf. During 2001, this well was successfully brought back on line and producing at approximately 2,100 Mcf a month.

Costs and Expenses

Total costs and expenses increased to $749,425 from $650,044 for the years ended December 31, 2001 and 2000, respectively, an increase of 15%. The increase is the result of higher lease operating costs, depletion expense and general and administrative expense.

1.  Lease operating costs and production taxes increased 1%, or approximately $4,500, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $900, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $132,000 for the year ended December 31, 2001 from $38,000 for the same period in 2000. This represents an increase of 247%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-C’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Oil & Gas Income Fund X-C’s reserves for January 1, 2002 as

16

compared to 2001, and the decrease in oil and gas revenues received by Oil & Gas Income Fund X-C during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $40,000 as of December 31, 2000.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	27.55	$	16.28	69	%
Average price per Mcf of gas	$	3.71	$	2.17	71	%
Oil production in barrels		30,000		35,190	(15	%)
Gas production in Mcf		27,700		74,540	(63	%)
Gross oil and gas revenue	$	929,367	$	734,832	26	%
Net oil and gas revenue	$	357,918	$	224,796	59	%
Oil & Gas Income Fund X-C distributions	$	277,300	$	113,204	145	%
Limited partner distributions	$	249,570	$	103,704	141	%
Per unit distribution to limited partners	$	39.96	$	16.60	141	%
Number of limited partner interests		6,246		6,246

Revenues

Oil & Gas Income Fund X-C’s oil and gas revenues increased to $929,367 from $734,832 for the years ended December 31, 2000 and 1999, respectively, an increase of 26%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Oil & Gas Income Fund X-C increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 69%, or $11.27 per barrel, resulting in an increase of approximately $338,100 in revenues. Oil sales represented 89% of total oil and gas sales during the year ended December 31, 2000 as compared to 78% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Oil & Gas Income Fund X-C increased during the same period by 71%, or $1.54 per Mcf, resulting in an increase of approximately $42,700 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $380,800. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 5,190 barrels, or 15%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $84,500 in revenues.

Gas production decreased approximately 46,840 Mcf, or 63%, during the same period, resulting in a decrease of approximately $101,600 in revenues.

The total decrease in revenues due to the change in production is approximately $186,100. Oil & Gas Income Fund X-C’s dramatic decline in gas production was primarily in connection with two wells. During 1999, Oil & Gas Income Fund X-C was involved in a lawsuit in order to receive payment for two months of production from the purchaser at that time. The lawsuit was settled in the current year with Oil & Gas Income Fund X-C receiving less than was owed from the purchaser. The original accrual recorded during the second quarter of

17

1999 was reversed in the current year. This reversal represented approximately 2,800 Mcf. Additionally, Oil & Gas Income Fund X-C was informed during the current year that a workover which was performed during the last quarter of 1999 on a non-operated well was not only unsuccessful but caused the well to shut down. This well is not believed to be recoverable; thus, the loss to Oil & Gas Income Fund X-C is considered to be permanent. This well represented approximately 2,890 Mcf a month. Total decline for Oil & Gas Income Fund X-C during the year ended December 31, 2000 in connection with this non-operated well was approximately 36,700 Mcf.

Costs and Expenses

Total costs and expenses increased to $650,044 from $601,379 for the years ended December 31, 2000 and 1999, respectively, an increase of 8%. The increase is the result of higher lease operating costs, partially offset by a decrease in depletion expense and general and administrative expense.

1.  Lease operating costs and production taxes increased 12%, or approximately $61,400, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $700, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $38,000 for the year ended December 31, 2000 from $50,000 for the same period in 1999. This represents a decrease of 24%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Oil & Gas Income Fund X-C’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Oil & Gas Income Fund X-C’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $17,000 as of December 31, 1999.

Revenue and Distribution Comparison

Oil & Gas Income Fund X-C income for the years ended December 31, 2001, 2000 and 1999 was $125,209, $282,522 and $134,810, respectively. Excluding the effects of depreciation, depletion and amortization, net income would have been $257,209 in 2001, $320,522 in 2000 and $184,810 in 1999. Correspondingly, Oil & Gas Income Fund X-C distributions for the years ended December 31, 2001, 2000 and 1999 were $361,479, $277,300 and $113,204, respectively. These differences are indicative of the changes in oil and gas prices, production and property sales.

The source for the 2001 distributions of $361,479 was oil and gas operations of approximately $331,200 and the change in oil and gas properties of approximately $(7,200), with the balance from available cash on hand at the beginning of the period. The source for the 2000 distributions of $277,300 was oil and gas operations of approximately $331,100 and the change in oil and gas properties of approximately $(14,900), resulting in excess cash for contingencies or subsequent distributions. The source for the 1999 distributions of $113,204 was oil and gas operations of approximately $120,000 and the change in oil and gas properties of approximately $(3,300), resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $361,479 of which $325,331 was distributed to the limited partners and $36,148 to the general partners. The per unit distribution to limited

18

partners during the same period was $52.09. Total distributions during the year ended December 31, 2000 were $277,300 of which $249,570 was distributed to the limited partners and $27,730 to the general partners. The per unit distribution to limited partners during the same period was $39.96. Total distributions during the year ended December 31, 1999 were $113,204 of which $103,704 was distributed to the limited partners and $9,500 to the general partners. The per unit distribution to limited partners during the same period was $16.60.

Liquidity and Capital Resources of Oil & Gas Income Fund X-C

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Oil & Gas Income Fund X-C knows of no material change, nor does it anticipate any such change.

Cash flows provided by operating activities were approximately $9,000 in the six months ended June 30, 2002 as compared to approximately $242,000 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows (used in) provided by investing activities were approximately $(18,400) in the six months ended June 30, 2002 as compared to approximately $200 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was the addition to oil and gas properties.

There were no cash flows used in financing activities in the six months ended June 30, 2002 as compared to approximately $225,000 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $225,000 of which $202,500 was distributed to the limited partners and $22,500 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $32.42.

The source for the 2001 distributions of $225,000 was oil and gas operations of approximately $242,000, and the change in oil and gas properties of approximately $200, resulting in excess cash for contingencies or subsequent distributions.

Since inception of Oil & Gas Income Fund X-C, cumulative monthly cash distributions of $3,675,801 have been made to the partners. As of June 30, 2002, $3,327,049 or $532.67 per unit of limited partner interest has been distributed to the limited partners, representing a 107% return of the capital contributed.

As of June 30, 2002, Oil & Gas Income Fund X-C had approximately $36,300 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Oil & Gas Income Fund X-C.

Cash flows provided by operating activities were approximately $331,200 in 2001 compared to $331,100 in 2000 and approximately $120,000 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $7,200 in 2001 compared to $14,900 in 2000 and approximately $3,300 in 1999. The primary use of investing activities was the purchase of oil and gas properties.

Cash flows used in financing activities were approximately $361,300 in 2001 compared to $277,300 in 2000 and approximately $113,100 in 1999. The only 2001 use in financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Royalties Institutional Income Fund X-C, L.P., which we call Institutional Income Fund X-C, and supplements the prospectus/proxy statement dated                     , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Institutional Income Fund X-C. The purpose of the special meeting is for you to vote upon the merger of Institutional Income Fund X-C with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Institutional Income Fund X-C is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                                 .

This document contains the following information concerning Income Fund X-C:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Institutional Income Fund X-C

• Compensation and distributions from Institutional Income Fund X-C

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Institutional Income Fund X-C for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Institutional Income Fund X-C’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Institutional Income Fund X-C as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Institutional Income Fund X-C, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Institutional Income Fund X-C in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Institutional Income Fund X-C’s assets. The Merger Value of Institutional Income Fund X-C is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Institutional Income Fund X-C, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Institutional Income Fund X-C by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Institutional Income Fund X-C. We believe, however, that Institutional Income Fund X-C will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Institutional Income Fund X-C. Our decision is based on the following factors in order of significance:

• Our method of valuation for Institutional Income Fund X-C uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Institutional Income Fund X-C, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Institutional Income Fund X-C. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.”

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR INSTITUTIONAL INCOME FUND X-C

The Merger Value for Institutional Income Fund X-C was determined by calculating its Net Asset Value and then dividing Institutional Income Fund X-C’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Institutional Income Fund X-C’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Institutional Income Fund X-C’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Institutional Income Fund X-C. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund X-C is 2.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Institutional Income Fund X-C
		Net Present Value of Reserves	$	649,785.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	26,917.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Institutional Income Fund X-C	$	676,702.00	calculated

3

					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Institutional Income Fund X-C	$	676,702.00	calculated
	less	GP% owned by Southwest in Institutional Income Fund X-C (10%)	$	67,670.20	Partnership records
	less	LP% owned by Southwest in Institutional Income Fund X-C (1.57%)	$	10,624.22	Partnership records
	equals	Net Asset Value of Institutional Income Fund X-C owned by limited partners (excluding Southwest’s ownership %)	$	598,407.58	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Institutional Income Fund X-C (excluding Southwest’s ownership %)	$	598,407.58	calculated
	equals	The percentage of ownership of Institutional Income Fund X-C (other than Southwest) to the total Net Asset Value		0.76%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Institutional Income Fund X-C (other than Southwest)		0.76%	calculated
	equals	The number of shares of common stock attributable to Institutional Income Fund X-C (other than to Southwest)		12,870.26	calculated
(7)		The number of shares of common stock attributable to Institutional Income Fund X-C (other than to Southwest)		12,870	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Institutional Income Fund X-C		5,879	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Institutional Income Fund X-C		2	calculated
(8)		The number of shares of special stock attributable to Institutional Income Fund X-C (other than to Southwest)		2,574	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Institutional Income Fund X-C		5,879	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Institutional Income Fund X-C		.44	calculated

4

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general limited partner and as a limited partner) from Institutional Income Fund X-C for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	36,000	$	36,000	$	36,000	$	18,000
Administrative Overhead per Operating Agreements	$	183,257	$	175,293	$	176,290	$	91,638
Cash Distributions Paid to General Partners as General Partners(1)	$	33,059	$	28,605	$	5,800	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	4,967	$	3,695	$	732	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Institutional Income Fund X-C’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	297,528	$	257,445	$	68,477	$	103,950	$	503,550	$	—

Return of Capital: 99%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

5

SUPPLEMENTAL INFORMATION TABLE FOR INSTITUTIONAL INCOME FUND X-C

Aggregate Initial Investment by the Limited Partners:	$	2,992	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	2,951	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	609	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	101.79	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		6.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	32.84	(2)(4)
—as of December 31, 2001:	$	39.01	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	70.05	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	68.99	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	84.04	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Institutional Income Fund X-C is equal to (1) the sum of (A) the present value of estimated future net revenues from Institutional Income Fund X-C’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Institutional Income Fund X-C is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Institutional Income Fund X-C is based upon (1) the sum of (A) the estimated net cash flow from the sale of Institutional Income Fund X-C’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Institutional Income Fund X-C’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Institutional Income Fund X-C is based upon (1) the sum of (A) the sale of Institutional Income Fund X-C’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Institutional Income Fund X-C’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Institutional Income Fund X-C and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Institutional Income Fund X-C is based upon (1) the sum of (A) Institutional Income Fund X-C’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Institutional Income Fund X-C.

6

INSTITUTIONAL INCOME FUND X-C

Set forth below is basic information about Institutional Income Fund X-C and its business and operations. It does not contain all the information about Institutional Income Fund X-C that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Institutional Income Fund X-C

General

Income Fund X-C was organized as a Delaware limited partnership on September 20, 1991. The offering of limited partner interests began October 1, 1991, reached minimum capital requirements on January 28, 1992, and concluded April 30, 1992, with total limited partner contributions of $3.0 million.

Principal Products, Marketing and Distribution

Institutional Income Fund X-C has acquired and holds royalty interests and net profit interests in oil and gas properties located in New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	78%	22%
2000	88%	12%
1999	84%	16%

As the table indicates, the majority of Institutional Income Fund X-C’s revenue is from its oil production.

Customer Dependence

No material portion of Institutional Income Fund X-C’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Institutional Income Fund X-C. Two purchasers accounted for 77% of Institutional Income Fund X-C’s total oil and gas production during 2001: Teppco Crude Oil LLC for 65% and Plains All American Pipeline, L.P. for 12%. Two purchasers accounted for 84% of Institutional Income Fund X-C’s total oil and gas production during 2000: Teppco Crude Oil LLC for 72% and Plains All American Pipeline, L.P. for 12%. Two purchasers accounted for 79% of Institutional Income Fund X-C’s total oil and gas production during 1999: Teppco Crude Oil LLC for 68% and Scurlock Permian LLC for 11%. All purchasers of Institutional Income Fund X-C’s oil and gas production are unrelated third parties. In the event either of these purchasers were to discontinue purchasing Institutional Income Fund X-C’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Institutional Income Fund X-C’s sales of oil and gas production.

Properties

As of December 31, 2001, Institutional Income Fund X-C possessed an interest in oil and gas properties located in Chaves, Eddy and Lea Counties, New Mexico; and Colorado, Comanche, Glasscock, Howard, Martin, Midland, Mitchell, Scurry, Throckmorton, Tom Green and Winkler Counties, Texas. These properties consist of various interests in 470 wells and units.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

During 2001 and 2000, there were no property sales. During 1999, eight leases were sold for approximately $18,644.

7

Significant Properties

The following table reflects the significant properties in which Institutional Income Fund X-C has an interest:

	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
Name and Location			Oil (Bbls)	Gas (Mcf)
Ackerly-Ira-Sharon Ridge Acquisition Scurry, Mitchell and Martin Counties, Texas	10/92 at 4% to 50% net profits interest	405	17,000	68,000
Kelt Ohio Chaves County, New Mexico	1/94 at 25% to 50% net profits interests	1	1,000	253,000
Meltie Pool #1 Colorado County, Texas	10/92 at 11% net profits interests	1	1,000	55,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Institutional Income Fund X-C’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.66 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $1.65 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-C” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Institutional Income Fund X-C. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

8

Institutional Income Fund X-C has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Institutional Income Fund X-C’s present reserves.

Because Institutional Income Fund X-C does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Institutional Income Fund X-C retains a carried interest under the terms of a farm-out or receives cash.

Institutional Income Fund X-C or the owners of properties in which Institutional Income Fund X-C owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves which qualify as proved developed non-producing reserves. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-C” in this prospectus supplement.

Market for Institutional Income Fund X-C’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Institutional Income Fund X-C should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 10.5 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $132.66 per unit. In 2000, 30 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $56.14 per unit. As of December 31, 1999, no units of limited partner interest were purchased by the managing general partner. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 334 holders of limited partner interest in Institutional Income Fund X-C.

Distributions

Pursuant to Article III, Section 3.05 of Institutional Income Fund X-C’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Institutional Income Fund X-C’s] investments in producing oil and gas properties, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Institutional Income Fund X-C], as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $330,587, with $297,528 distributed to the limited partners and $33,059 to the general partners. For the year ended December 31, 2001, distributions of $49.73 per unit of limited partner interest were made, based upon 5,983 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $286,050, with $257,445 distributed to the limited partners and $28,605 to the general partners. For the year ended December 31, 2000, distributions of $43.03 per unit of limited partner interest were made, based upon 5,983 units of limited partner interest outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $74,277, with $68,477 distributed to the limited partners and $5,800 to the general partners. For the year ended December 31, 1999, distributions of $11.45 per unit of limited partner interest were made, based upon 5,983 units of limited partner interest outstanding.

9

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

INSTITUTIONAL INCOME FUND X-C

The following tables present summary selected financial information and operating data for Institutional Income Fund X-C for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-C” found elsewhere in this prospectus supplement and the financial statements and related notes for Institutional Income Fund X-C included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	299,705		449,631		787,598		954,695		675,408		569,601		1,013,391
Net income (loss)	(39,355	)	115,940		76,865		318,946		99,087		(149,133	)	235,030
Limited Partners’ share of net income (loss):
General limited Partners	(2,435	)	15,194		18,286		34,995		13,909		3,687		38,403
Limited Partners	(36,920	)	100,746		58,579		283,951		85,178		(152,820	)	196,627
Limited Partners’ net income (loss) per unit of limited partner interest	(6.17	)	16.84		9.79		47.46		14.24		(25.54	)	32.86
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	(2,989	)	192,945		257,927		351,914		72,286		96,555		409,145
Net cash provided by investing activities	—		—		—		—		18,762		4,204		—
Net cash used in financing activities	—		(220,000	)	(330,587	)	(286,052	)	(74,291	)	(115,484	)	(559,500	)
Net increase (decrease) in cash and cash equivalents	(2,989	)	(27,055	)	(72,660	)	65,862		16,757		(14,725	)	(150,355	)
EBITDA	(24,355	)	151,940		182,865		349,946		139,087		36,867		384,030
Cash distributions	—		220,000		330,587		286,050		74,277		115,500		559,500
Limited Partners’ cash distributions per $500 investment	—		33.09		49.73		43.03		11.45		17.37		84.16
Balance Sheet Data:
Cash and cash equivalents	12,311		60,905		15,300		87,960		22,098		5,341		20,066
Oil and gas properties, net at book value	140,183		225,183		155,183		261,183		292,183		350,945		541,149
Total assets	167,101		356,117		206,456		460,179		427,285		40,249		667,106
Total liabilities	—		—		—		—		2		16		—
Limited Partners’ equity	196,459		375,074		233,379		472,328		445,822		429,121		685,891
General Limited Partners’ equity	(29,358	)	(18,957	)	(26,923	)	(12,149	)	(18,539	)	(26,648	)	(18,785	)
Limited Partner’s book value per $500 investment	32.84		62.69		39.01		78.95		74.51		71.72		114.64

10

	Six months ended June 30,			Years ended December 31,
	2002		2001	2001	2000	1999	1998	1997
Production:
Oil production (Bbls)	13,500		14,100	28,700	30,400	34,820	41,500	45,800
Natural gas production (Mcf)	15,700		23,000	43,500	30,100	49,970	64,800	74,000
Equivalent production (Boe)	16,117		17,933	35,950	35,417	43,148	52,300	58,133
Average Sales Price:
Oil price (per/Bbl)	19.51		24.35	21.52	27.70	16.32	10.93	18.15
Natural gas price (per/Mcf)	2.31		4.62	3.91	3.73	2.14	1.79	2.46
Average sales price (per Boe)	18.60		25.07	21.91	26.95	15.65	10.89	17.43
Operating and Overhead Costs (per Boe)
Lease operating expense	18.03		14.34	14.72	14.67	10.69	8.63	9.25
Production taxes	.87		1.26	1.05	1.37	.79	.59	.93
General and Administrative Expense (per Boe)	1.27		1.11	1.13	1.13	.97	.98	.75
Total	20.17		16.71	16.90	17.17	12.45	10.20	10.93
Cash Operating Margin (per Boe)	(1.57	)	8.36	5.01	9.78	3.20	.69	6.50
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.93		2.01	2.95	.88	.93	3.56	2.56
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	434,000		446,000	393,000	548,000	600,000	481,000	776,000
Oil (Bbls)	62,000		88,000	22,000	115,000	164,000	32,000	123,000
Total (Boe)	134,000		162,000	88,000	206,000	264,000	112,000	252,000

⁽¹⁾ Institutional Income Fund X-C has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$677,000
Merger Value per $500 investment	$101.79

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

11

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR INSTITUTIONAL INCOME FUND X-C

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Institutional Income Fund X-C will likely experience the historical production decline of approximately 9% per year from the prior year’s production.

Results of Operations—General Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.38	$	24.00	(7	%)
Average price per Mcf of gas	$	2.73	$	3.57	(24	%)
Oil production in barrels		6,700		7,100	(6	%)
Gas production in Mcf		7,200		11,500	(37	%)
Income from net profits interests	$	7,687	$	47,597	(84	%)
Institutional Income Fund X-C distributions	$	—	$	100,000	(100	%)
Limited partner distributions	$	—	$	90,000	(100	%)
Per unit distribution to limited partners	$	—	$	15.04	(100	%)
Number of limited partner units		5,983		5,983

Revenues

Institutional Income Fund X-C’s income from net profits interests decreased to $7,687 from $47,597 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 84%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-C decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 7%, or $1.62 per barrel, resulting in a decrease of approximately $10,900 in income from net profits interests. Oil sales represented 88% of total oil and gas sales during the quarters ended June 30, 2002 as compared to 81% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund X-C decreased during the same period by 24%, or $.84 per Mcf, resulting in a decrease of approximately $6,000 in income from net profits interests.

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $16,900. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 400 barrels, or 6%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $9,600 in income from net profits interests.

Gas production decreased approximately 4,300 Mcf, or 37%, during the same period, resulting in a decrease of approximately $15,400 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $25,000. Gas production is down primarily due to downtime on one lease during the quarter ended June 30, 2002.

12

3.  Lease operating costs and production taxes increased 10%, or approximately $15,100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $18,380 from $31,935 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 42%. The decrease is the result of lower depletion expense, partially offset by an increase in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 4%, or approximately $400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  Depletion expense decreased to $8,000 for the quarter ended June 30, 2002, from $22,000 for the same period in 2001. This represents a decrease of 64%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-C’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund X-C during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,					Percentage Increase (Decrease)
	2002			2001
Average price per barrel of oil	$	19.51		$	24.35	(20	%)
Average price per Mcf of gas	$	2.31		$	4.62	(50	%)
Oil production in barrels		13,500			14,100	(4	%)
Gas production in Mcf		15,700			23,000	(32	%)
Income from net profits interests	$	(5,028	)	$	169,882	(103	%)
Institutional Income Fund X-C distributions	$	—		$	220,000	(100	%)
Limited partner distributions	$	—		$	198,000	(100	%)
Per unit distribution to limited partners	$	—		$	33.09	(100	%)
Number of limited partner interests		5,983			5,983

Revenues

Institutional Income Fund X-C’s income from net profits interests decreased to $(5,028) from $169,882 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 103%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-C decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 20%, or $4.84 per barrel, resulting in a decrease of approximately $65,300 in income from net profits interests. Oil sales represented 88% of total oil and gas sales during the six months ended June 30, 2002 as compared to 76% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Institutional Income Fund X-C decreased during the same period by 50%, or $2.31 per Mcf, resulting in a decrease of approximately $36,300 in income from net profits interests.

13

The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $101,600. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 600 barrels, or 4%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $14,600 in income from net profits interests.

Gas production decreased approximately 7,300 Mcf, or 32%, during the same period, resulting in a decrease of approximately $33,700 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $48,300. Gas production is down primarily due to downtime on one lease in addition to a non-operated lease having a steep natural decline.

3.  Lease operating costs and production taxes increased 9%, or approximately $25,000, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

Costs and Expenses

Total costs and expenses decreased to $35,515 from $55,989 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 37%. The decrease is the result of lower depletion expense, partially offset by an increase in general and administrative expense.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $500, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  Depletion expense decreased to $15,000 for the six months ended June 30, 2002 from $36,000 for the same period in 2001. This represents a decrease of 58%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-C’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Institutional Income Fund X-C during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	21.52	$	27.70	(22	%)
Average price per Mcf of gas	$	3.91	$	3.73	5	%
Oil production in barrels		28,700		30,400	(6	%)
Gas production in Mcf		43,500		30,100	45	%
Income from net profits interests	$	220,775	$	386,562	(43	%)
Institutional Income Fund X-C distributions	$	330,587	$	286,050	15	%
Limited partner distributions	$	297,528	$	257,445	15	%
Per unit distribution to limited partners	$	49.73	$	43.03	15	%
Number of limited partner interests		5,983		5,983

14

Revenues

Institutional Income Fund X-C’s income from net profits interests decreased to $220,775 from $386,562 for the years ended December 31, 2001 and 2000, respectively, a decrease of 43%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-C decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 22%, or $6.18 per barrel, resulting in a decrease of approximately $177,400 in income from net profits interests. Oil sales represented 78% of total oil and gas sales during the year ended December 31, 2001 as compared to 88% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Institutional Income Fund X-C increased during the same period by 5%, or $.18 per Mcf, resulting in an increase of approximately $7,800 in income from net profits interests.

The net total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $169,600. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,700 barrels, or 6%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $47,100 in income from net profits interests.

Gas production increased approximately 13,400 Mcf, or 45%, during the same period, resulting in an increase of approximately $50,000 in income from net profits interests.

The net total increase in income from net profits interests due to the change in production is approximately $2,900. Institutional Income Fund X-C’s dramatic increase in gas production was primarily in connection with one well. Institutional Income Fund X-C was informed that a workover which was performed during the last quarter of 1999 on a non-operated well was not only unsuccessful but caused the well to shut down. This well was not believed to be recoverable; thus, the loss to Institutional Income Fund X-C was considered to be permanent. This well represented approximately 1,320 Mcf a month. Total decline for Institutional Income Fund X-C during the year ended December 31, 2000 in connection with this non-operated well was approximately 15,700 Mcf. During 2001, this well was successfully recovered and brought back online, producing approximately 930 Mcf a month.

3.  Lease operating costs and production taxes decreased less than 1%, or approximately $1,300, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

Costs and Expenses

Total costs and expenses increased to $146,655 from $71,195 for the years ended December 31, 2001 and 2000, respectively, an increase of 106%. The increase is the result of higher depletion expense and general and administrative costs.

1.  General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $500, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  Depletion expense increased to $106,000 for the year ended December 31, 2001 from $31,000 for the same period in 2000. This represents an increase of 242%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-C’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Institutional Income Fund X-C’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Institutional Income Fund X-C during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $39,000 as of December 31, 2000.

15

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	1999		2000
Average price per barrel of oil	$	27.70	$	16.32	70	%
Average price per Mcf of gas	$	3.73	$	2.14	74	%
Oil production in barrels		30,400		34,820	(13	%)
Gas production in Mcf		30,100		49,970	(40	%)
Income from net profits interests	$	386,562	$	180,192	115	%
Institutional Income Fund X-C distributions	$	286,050	$	74,277	285	%
Limited Partner distributions	$	257,445	$	68,477	276	%
Per unit distribution to limited partners	$	43.03	$	11.45	276	%
Number of limited partner interests		5,983		5,983

Revenues

Institutional Income Fund X-C’s income from net profits interests increased to $386,562 from $180,192 for the years ended December 31, 2000 and 1999, respectively, an increase of 115%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Institutional Income Fund X-C increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 70%, or $11.38 per barrel, resulting in an increase of approximately $346,000 in income from net profits interests. Oil sales represented 88% of total oil and gas sales during the year ended December 31, 2000 as compared to 84% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Institutional Income Fund X-C increased during the same period by 74%, or $1.59 per Mcf, resulting in an increase of approximately $47,900 in income from net profits interests.

The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $393,900. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 4,420 barrels, or 13%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $72,100 in income from net profits interests.

Gas production decreased approximately 19,870 Mcf, or 40%, during the same period, resulting in a decrease of approximately $42,500 in income from net profits interests.

The total decrease in income from net profits interests due to the change in production is approximately $114,600. Institutional Income Fund X-C’s dramatic decline in gas production was primarily in connection with two wells. During 1999, Institutional Income Fund X-C was involved in a lawsuit in order to receive payment for two months of production from the purchaser at that time. The lawsuit was settled in the current year with Institutional Income Fund X-C receiving less than was owed from the purchaser. The original accrual recorded during the second quarter of 1999 was reversed in the current year. This reversal represented approximately 2,800 Mcf. Additionally, Institutional Income Fund X-C was informed during the current year that a workover which was performed during the last quarter of 1999 on a non-operated well was not only unsuccessful but caused the well to shut down. This well is not believed to be recoverable; thus, the loss to Institutional Income Fund X-C is considered to be permanent. This well represented approximately 1,320 Mcf a month. Total decline for Institutional Income Fund X-C during the year ended December 31, 2000 in connection with this non-operated well was approximately 15,700 Mcf.

16

3.  Lease operating costs and production taxes increased 15%, or approximately $72,900, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as overhead and pulling expense on two leases, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Institutional Income Fund X-C to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

Costs and Expenses

Total costs and expenses decreased to $71,195 from $81,876 for the years ended December 31, 2000 and 1999, respectively, a decrease of 13%. The decrease is the result of lower depletion expense and general and administrative costs.

1.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 4%, or approximately $1,700, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  Depletion expense decreased to $31,000 for the year ended December 31, 2000 from $40,000 for the same period in 1999. This represents a decrease of 23%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Institutional Income Fund X-C’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Institutional Income Fund X-C’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $12,000 as of December 31, 1999.

Revenue and Distribution Comparison

Institutional Income Fund X-C net income for the years ended December 31, 2001, 2000 and 1999 was $76,865, $318,946 and $99,087, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $182,865, $349,946, $139,087, respectively. Correspondingly, Institutional Income Fund X-C distributions for the years ended December 31, 2001, 2000 and 1999 were $330,587, $286,050 and $74,277, respectively. The differences are indicative of the changes in oil and gas prices, production and properties.

The source for the 2001 distributions of $330,587 were oil and gas operations of approximately $257,900, with the balance from available cash on hand at the beginning of the period. The source for the 2000 distributions of $286,050 were oil and gas operations of approximately $352,000, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $74,277 were oil and gas operations of approximately $72,300 and the change in oil and gas properties of approximately $18,800, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $330,587 of which $297,528 was distributed to the limited partners and $33,059 to the general partners. The per unit distribution to limited partners during the same period was $49.73. Total distributions during the year ended December 31, 2000 were $286,050 of which $257,445 was distributed to the limited partners and $28,605 to the general partners. The per unit distribution to limited partners during the same period was $43.03. Total distributions during the year ended December 31, 1999 were $74,277 of which $68,477 was distributed to the limited partners and $5,800 to the general partners. The per unit distribution to limited partners during the same period was $11.45.

17

Liquidity and Capital Resources of Institutional Income Fund X-C

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Institutional Income Fund X-C knows of no material change, nor does it anticipate any such change.

Cash flows (used in) provided by operating activities were approximately $(3,000) in the six months ended June 30, 2002 as compared to approximately $192,900 in the six months ended June 30, 2001.

Cash flows used in financing activities in the six months ended June 30, 2002 were none as compared to approximately $220,000 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $220,000 of which $198,000 was distributed to the limited partners and $22,000 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $33.09.

The source for the six months ended June 30, 2001 distributions of $220,000 were oil and gas operations of approximately $192,900, with the balance from available cash on hand at the beginning of the period.

Since inception of Institutional Income Fund X-C, cumulative monthly cash distributions of $3,263,882 have been made to the partners. As of June 30, 2002, $2,950,978 or $493.23 per unit of limited partner interest has been distributed to the limited partners, representing a 99% return of the capital contributed.

As of June 30, 2002, Institutional Income Fund X-C had approximately $26,900 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Institutional Income Fund X-C.

Cash flows provided by operating activities were approximately $257,900 in 2001 compared to $352,000 in 2000 and approximately $72,300 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Institutional Income Fund X-C had no cash flows from investing activities in 2001 and 2000. Cash flows provided by investing activities were approximately $18,800.

Cash flows used in financing activities were approximately $330,600 in 2001 compared to $286,100 in 2000 and approximately $74,300 in 1999. The only 2001 use in financing activities was the distributions to partners.

Liquidity—MD&A

Institutional Income Fund X-C accrued an oil and gas revenue receivable (included in the receivable from the managing general partner) of $66,667 at June 30, 2002, and recognized a net loss in the first quarter of 2002 which was partially offset by a net profit in the second quarter of 2002 on an accrual basis for its net profits interest in oil and gas properties. Cash distributions of the net profits interest are based on actual cash received from the underlying oil and gas properties, net of expenses incurred during that quarterly period. Accordingly, if the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter no net cash is due to Institutional Income Fund X-C’s net profits interest until the deficit is recovered from future net profits. Future cash distributions to Institutional Income Fund X-C are dependent on a positive quarterly net profits calculation on the underlying properties, which differs from the calculation on an accrual basis.

Institutional Income Fund X-C’s wells have been depleting over its life and production has experienced declines from year to year, while costs have not always decreased proportionately. This economic decline, coupled with the fluctuation of prices, has caused Institutional Income Fund X-C to experience periodic net losses. Because Institutional Income Fund X-C is a net profit interest, this situation can cause Institutional Income Fund X-C to generate a payable to the managing general partner. If Institutional Income Fund X-C should continue to experience this economic decline thereby creating net losses and increasing the payable, the managing general partner may have to consider dissolution and termination steps according to the Partnership Agreement.

18

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST COMBINATION INCOME/DRILLING PROGRAM 1988, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Combination Income/Drilling Program 1988, L.P., which we call Combination Income/Drilling Program 1988, and supplements the prospectus/proxy statement dated                     , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Combination Income/Drilling Program 1988. The purpose of the special meeting is for you to vote upon the merger of Combination Income/Drilling Program 1988 with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Combination Income/Drilling Program 1988 is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                     .

This document contains the following information concerning Combination Income/Drilling Program 1988:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Combination Income/Drilling Program 1988

• Compensation and distributions from Combination Income/Drilling Program 1988

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial data and operating data for Combination Income/Drilling Program 1988 for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Combination Income/Drilling Program 1988’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Combination Income/Drilling Program 1988 as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Combination Income/Drilling Program 1988, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Combination Income/Drilling Program 1988 in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Combination Income/Drilling Program 1988’s assets. The Merger Value of Combination Income/Drilling Program 1988 is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Combination Income/Drilling Program 1988, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Combination Income/Drilling Program 1988 by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Combination Income/Drilling Program 1988. We believe, however, that Combination Income/Drilling Program 1988 will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Combination Income/Drilling Program 1988. Our decision is based on the following factors in order of significance:

• Our method of valuation for Combination Income/Drilling Program 1988 uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Combination Income/Drilling Program 1988, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Combination Income/Drilling Program 1988. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR COMBINATION INCOME/DRILLING PROGRAM 1988

The Merger Value for Combination Income/Drilling Program 1988 was determined by calculating its Net Asset Value and then dividing Combination Income/Drilling Program 1988’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Combination Income Drilling Program 1988’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Combination Income/Drilling Program 1988’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Combination Income/Drilling Program 1988. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Combination Income/Drilling Program 1988 is 0.4.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Combination Income/Drilling Program 1988
		Net Present Value of Reserves	$	61,669.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	16,793.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Combination Income/Drilling Program 1988	$	78,462.00	calculated

3

					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Combination Income/Drilling Program 1988	$	78,462.00	calculated
	less	GP% owned by Southwest in Combination Income/Drilling Program 1988 (15%)	$	11,769.30	Partnership records
	less	LP% owned by Southwest in Combination Income/Drilling Program 1988 (3.68%)	$	2,887.40	Partnership records
	equals	Net Asset Value of Combination Income/Drilling Program 1988 owned by limited partners (excluding Southwest’s ownership %)	$	63,805.30	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value		46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships		32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Combination Income/Drilling Program 1988 (excluding Southwest’s ownership %)		63,805.30	calculated
	equals	The percentage of ownership of Combination Income/Drilling Program 1988 (other than Southwest) to the total Net Asset Value		0.08%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total NVA for Combination Income/Drilling Program 1988 (other than Southwest)		0.08%	calculated
	equals	The number of shares of common stock attributable to Combination Income/Drilling Program 1988 (other than to Southwest)		1,372.29	calculated
(7)		The number of shares of common stock attributable to Combination Income/Drilling Program 1988 (other than to Southwest)		1,372	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Combination Income/Drilling Program 1988		3,359	Partnership records

4

					Document(s) from which information was obtained or calculated
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Combination Income/Drilling Program 1988	.4	*	calculated
(8)		The number of shares of special stock attributable to Combination Income/Drilling Program 1988 (other than to Southwest)	274		calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Combination Income/Drilling Program 1988	3,359		Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Combination Income/Drilling Program 1988	.08		calculated

* Fractional shares of our common stock will not be distributed to the limited partners in connection with the merger. Instead, fractional shares of common stock will be rounded off to the nearest whole.

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Combination Income/Drilling Program 1988 for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	21,000	$	21,000	$	21,000	$	10,500
Administrative Overhead per Operating Agreements	$	27,845	$	36,300	$	34,517	$	13,824
Cash Distributions Paid to General Partners as General Partners(1)	$	1,650	$	20	$	—	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	400	$	—	$	—	$	—

⁽¹⁾ Cash Distributions paid to general partners include distributions paid to Southwest Royalties, Inc. as managing general partner and H.H. Wommack, III, Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. as an additional general partner.

Set forth below is a table showing the cash distributions to Combination Income/Drilling Program 1988’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	9,350	$	113	$	—	$	3,825	$	60,966	$	—

Return of Capital: 51%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

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SUPPLEMENTAL INFORMATION TABLE FOR

COMBINATION INCOME/DRILLING PROGRAM 1988

Aggregate Initial Investment by the Limited Partners:	$	1,755	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	893	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	67	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	19.01	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		13.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	6.89	(2)(4)
—as of December 31, 2001:	$	5.68	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	18.91	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	17.57	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	17.56	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Combination Income/Drilling Program 1988 is equal to (1) the sum of (A) the present value of estimated future net revenues from Combination Income/Drilling Program 1988’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Combination Income/Drilling Program 1988 is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Combination Income/Drilling Program 1988 is based upon (1) the sum of (A) the estimated net cash flow from the sale of Combination Income/Drilling Program 1988’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Combination Income/Drilling Program 1988’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Combination Income/Drilling Program 1988 is based upon (1) the sum of (A) the sale of Combination Income/Drilling Program 1988’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Combination Income/Drilling Program 1988’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Combination Income/Drilling Program 1988 and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Combination Income/Drilling Program 1988 is based upon (1) the sum of (A) Combination Income/Drilling Program 1988’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Combination Income/Drilling Program 1988.

7

COMBINATION INCOME/DRILLING PROGRAM 1988

Set forth below is basic information about Combination Income/Drilling Program 1988 and its business and operations. It does not contain all the information about Combination Income/Drilling Program 1988 that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Combination Income/Drilling Program 1988

General

Combination Income/Drilling Program 1988 was organized as a Delaware limited partnership on November 14, 1988. The offering of limited partner and general limited partner interests began November 14, 1988, reached minimum capital requirements on August 25, 1989 and concluded October 31, 1989, with total investor partner contributions of $1.75 million. The managing general partner contribution was $30,450. Total capital contributions were $1.78 million.

Principal Products, Marketing and Distribution

Combination Income/Drilling Program 1988 has acquired leasehold interests and drilled oil and gas properties located in Texas and New Mexico.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	70%	30%
2000	67%	33%
1999	69%	31%

As the table indicates, the majority of Combination Income/Drilling Program 1988’s revenue is from its oil production.

Customer Dependence

No material portion of Combination Income/Drilling Program 1988’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Combination Income/Drilling Program 1988. Two purchasers accounted for 100% of Combination Income/Drilling Program 1988’s total oil and gas production during 2001: Navajo Refining Company, Inc. for 69% and Duke Energy Field Services for 31%. Two purchasers accounted for 100% of Combination Income/Drilling Program 1988’s total oil and gas production during 2000: Navajo Refining Company, Inc. for 68% and Phillips 66 Natural Gas Co., for 32%. Two purchasers accounted for 100% of Combination Income/Drilling Program 1988’s total oil and gas production during 1999: Navajo Refining Company, Inc. for 67% and Phillips 66 Natural Gas Company for 33%. All purchasers of Combination Income/Drilling Program 1988’s oil and gas production are unrelated third parties. In the event these purchasers were to discontinue purchasing Combination Income/Drilling Program 1988’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Combination Income/Drilling Program 1988’s total oil and gas production.

Properties

As of December 31, 2001, Combination Income/Drilling Program 1988 possessed an interest in oil and gas properties located in Eddy County, New Mexico and Andrews County, Texas. These properties consist of various interests in 9 wells.

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There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

During 2001, 3 leases were sold for approximately $1,200. There were no leases sold during 2000 and 1999.

Significant Properties

The following table reflects the significant properties in which Combination Income/Drilling Program 1988 has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Kuykendall, Humble Acquisition Andrews County, Texas	9/89; 67.4% working interest	8	5,000	14,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Combination Income/Drilling Program 1988’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.40 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.49 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR COMBINATION INCOME/DRILLING PROGRAM 1988,” oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Combination Income/Drilling Program 1988. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Combination Income/Drilling Program 1988 has reserves which are classified as proved developed producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate Combination Income/Drilling Program 1988’s present reserves.

9

Because Combination Income/Drilling Program 1988 does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the managing general partner or unrelated third parties. Generally, Combination Income/Drilling Program 1988 retains a carried interest under the terms of a farm-out, or receives cash.

Market Information for Combination Income/Drilling Program 1988’s Partnership Interests and Related Partnership Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Combination Income/Drilling Program 1988 should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by United Bank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, no units of limited partner interest were tendered to the managing general partner. In 2000, 20 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $5.00 per unit. In 1999, 40 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $5.00 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited and General Partner Interest Holders

As of December 31, 2001, 2000 and 1999, there were 177, 174 and 174 holders of limited partner interest and no holders of general partner interests in Combination Income/Drilling Program 1988.

Distributions

Pursuant to Article IV, Section 4.01 of Combination Income/Drilling Program 1988’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by Combination Income/Drilling Program 1988’s drilling activities, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of Combination Income/Drilling Program 1988, including, but not limited to, drilling cost overruns, as determined in the sole discretion of the managing general partner.”

Total distributions during the year ended December 31, 2001 were $11,000 of which $9,350 was distributed to the limited partners and $1,650 to the general partners. The per unit distribution to limited partners during the same period was $2.66. Total distributions during the year ended December 31, 2000 were $133 of which $113 was distributed to the limited partners and $20 to the general partners. The per unit distribution to limited partners during the same period was $.03. There were no distributions made during 1999.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

COMBINATION INCOME/DRILLING PROGRAM 1988

The following tables present summary selected financial information and operating data for Combination Income/Drilling Program 1988 for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR COMBINATION INCOME/DRILLING PROGRAM 1988” found elsewhere in this prospectus supplement and the financial statements and related notes for Combination Income/Drilling Program 1988 included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	45,917		70,941		114,533		165,052		100,304		89,122		173,891
Net income (loss)	5,141		21,051		10,348		40,452		(1,229	)	(103,919	)	1,659
Partners’ share of net income (loss):
General partners	875		3,418		2,203		6,184		76		(7,718	)	1,809
Partners	4,266		17,633		8,145		34,268		(1,305	)	(96,201	)	(150	)
Partners’ net income (loss) per unit of limited partner interest	1.22		5.03		2.32		9.77		(.37	)	(27.42	)	(.04	)
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	(3,063	)	14,126		23,814		142		12		2,376		32,105
Net cash provided by investing activities	—		1,200		1,160		(12	)	(12	)	3,224		28,844
Net cash used in financing activities	—		(5,500	)	(11,224	)	(179	)	(1	)	(4,330	)	(69,260	)
Net increase (decrease) in cash and cash equivalents	(3,063	)	9,826		13,750		(49	)	(1	)	1,270		(8,311	)
EBITDA	5,941		23,051		15,348		41,352		771		(43,384	)	13,659
Cash distributions	—		5,000		11,000		133		—		4,500		69,441
Partners’ cash distributions per $500 investment	—		1.21		2.66		.03		—		1.09		17.37
Balance Sheet Data:
Cash and cash equivalents	10,918		10,057		13,981		231		280		281		—
Oil and gas properties, net at book value	10,161		13,921		10,961		17,121		18,009		19,997		83,756
Total assets	27,299		38,585		24,942		23,034		18,289		20,278		93,229
Total liabilities	345		69		3,129		569		36,143		36,903		1,435
Partners’ equity	24,185		34,507		19,919		21,124		(13,031	)	(11,726	)	88,300

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	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999		1998		1997
General partners’ equity	2,769	4,009	1,894	1,341	(4,823	)	(4,899	)	3,494
Partner’s book value per $500 investment	6.89	9.83	5.68	6.02	(3.71	)	(3.34	)	25.16
Production:
Oil production (Bbls)	1,800	1,900	3,610	3,900	4,110		5,000		6,600
Natural gas production (Mcf)	4,250	5,600	10,300	14,600	16,180		16,400		23,500
Equivalent production (Boe)	2,508	2,833	5,327	6,333	6,807		7,733		10,517
Average Sales Price:
Oil price (per/Bbl)	20.25	24.29	22.14	28.38	16.75		11.65		18.47
Natural gas price (per/Mcf)	2.23	4.43	3.36	3.72	1.94		1.88		2.21
Average sales price (per Boe)	18.31	25.04	21.50	26.06	14.74		11.52		16.53
Operating and Overhead Costs (per Boe)
Lease operating expense	9.95	11.12	12.77	14.17	10.01		12.22		11.93
Production taxes	.92	1.37	1.16	1.40	.75		.64		.72
General and Administrative Expense (per Boe)	5.13	4.42	4.70	3.96	3.87		4.29		2.60
Total	16.00	16.91	18.63	19.53	14.63		17.15		15.25
Cash Operating Margin (per Boe)	2.31	8.13	2.87	6.53	.11		(5.63	)	1.28
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.32	.71	.94	.14	.29		7.83		1.14
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	46,000	79,000	21,000	191,000	126,000		6,000		150,000
Oil (Bbls)	19,000	23,000	9,000	49,000	35,000		4,000		50,000
Total (Boe)	27,000	36,000	13,000	81,000	56,000		5,000		75,000

⁽¹⁾ Combination Income/Drilling Program 1988 has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$78,000
Merger Value per $500 investment	$  19.01

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS FOR COMBINATION INCOME/DRILLING PROGRAM 1988

General

Combination Income/Drilling Program 1988 was formed to engage primarily in the business of drilling developmental wells, to produce and market crude oil and natural gas produced from such properties, to distribute any net proceeds from operations to the general and limited partners and to the extent necessary, acquire leases which contain drilling prospects. Net revenues will not be reinvested in other revenue producing assets except to the extent that performance of remedial work is needed to improve a well’s producing capabilities. The economic life of Combination Income/Drilling Program 1988 thus depends on the period over which Combination Income/Drilling Program 1988’s oil and gas reserves are economically recoverable.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.77	$	23.87	(5	%)
Average price per Mcf of gas	$	2.73	$	3.64	(25	%)
Oil production in barrels		950		950	—
Gas production in Mcf		1,910		2,800	(32	%)
Gross oil and gas revenue	$	26,840	$	31,843	(16	%)
Net oil and gas revenue	$	11,242	$	17,865	(37	%)
Combination Income/Drilling Program 1988 distribution	$	—	$	5,000	(100	%)
Limited partner distribution	$	—	$	4,500	(100	%)
Number of limited partner interests		3,509		3,509

Revenues

Combination Income/Drilling Program 1988’s oil and gas revenues decreased to $26,840 from $31,843 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 16%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Combination Income/Drilling Program 1988 decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 5%, or $1.10 per barrel, resulting in a decrease of approximately $1,000 in revenues. Oil sales represented 81% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 69% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Combination Income/Drilling Program 1988 decreased during the same period by 25%, or $.91 per Mcf, resulting in a decrease of approximately $1,700 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $2,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production remained the same during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

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Gas production decreased approximately 890 Mcf, or 32%, during the same period, resulting in a decrease of approximately $3,200 in revenues.

The total decrease in revenues due to the change in production is approximately $3,200. The decrease in gas production is due primarily to recalibration and the discontinuance of hot water treatments to the one lease of Combination Income/Drilling Program 1988 during the quarter ended June 30, 2002.

Costs and Expenses

Total costs and expenses increased to $22,572 from $21,873 for the quarters ended June 30, 2002 and 2001, respectively, an increase of 3%. The increase is the result of higher lease operating costs and general and administrative expense, partially offset by a decrease in depletion expense.

1.  Lease operating costs and production taxes increased 12%, or approximately $1,600, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $200, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $500 for the quarter ended June 30, 2002, from $1,600 for the same period in 2001. This represents a decrease of 69%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Combination Income/Drilling Program 1988’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. Contributing factors to the decrease in depletion expense between the comparative periods was the increase in the price of gas used to determine Combination Income/Drilling Program 1988’s reserves for July 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Combination Income/Drilling Program 1988 during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	20.25	$	24.29	(17	%)
Average price per Mcf of gas	$	2.23	$	4.43	(50	%)
Oil production in barrels		1,800		1,900	(5	%)
Gas production in Mcf		4,250		5,600	(24	%)
Gross oil and gas revenue	$	45,917	$	70,941	(35	%)
Net oil and gas revenue	$	18,657	$	35,540	(48	%)
Combination Income/Drilling Program 1988 distributions	$	—	$	5,000	(100	%)
Limited partner distribution	$	—	$	4,250	(100	%)
Number of limited partner interests		3,509		3,509

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Revenues

Combination Income/Drilling Program 1988’s oil and gas revenues decreased to $45,917 from $70,941 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 35%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Combination Income/Drilling Program 1988 decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 17%, or $4.04 per barrel, resulting in a decrease of approximately $7,300 in revenues. Oil sales represented 79% of total oil and gas sales during the six months ended June 30, 2002 as compared to 65% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Combination Income/Drilling Program 1988 decreased during the same period by 50%, or $2.20 per Mcf, resulting in a decrease of approximately $9,400 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $16,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 100 bbl, or 5%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $2,400 in revenues.

Gas production decreased approximately 1,350 Mcf, or 24%, during the same period, resulting in a decrease of approximately $6,000 in revenues.

The total decrease in revenues due to the change in production is approximately $8,400. The decrease in gas production is due primarily to recalibration and the discontinuance of hot water treatments to the one lease of Combination Income/Drilling Program 1988 during the six months ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $40,930 from $49,927 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 18%. The decrease is the result of lower lease operating costs and depletion expense, partially offset by an increase in general and administrative expense depletion expense.

1.  Lease operating costs and production taxes decreased 23%, or approximately $8,100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001. The decrease in lease operating expense is due to maintenance and other repairs being performed in 2001 on one lease, and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $300, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $800 for the six months ended June 30, 2002 from $2,000 for the same period in 2001. This represents a decrease of 60%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Combination Income/Drilling Program 1988’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. Contributing factors to the decrease in depletion expense between the comparative periods was the increase in the price of gas used to determine Combination Income/Drilling Program 1988’s reserves for July 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Combination Income/Drilling Program 1988 during 2002 as compared to 2001.

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Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	22.14	$	28.38	(22	%)
Average price per Mcf of gas	$	3.36	$	3.72	(10	%)
Oil production in barrels		3,610		3,900	(7	%)
Gas production in Mcf		10,300		14,600	(29	%)
Gross oil and gas revenue	$	114,533	$	165,052	(31	%)
Net oil and gas revenue	$	40,331	$	66,435	(39	%)
Combination Income/Drilling Program 1988 distributions	$	11,000	$	133	8,171	%
Limited partner distributions	$	9,350	$	113	8,174	%
Per unit distribution to limited partners	$	2.66	$	.03	8,767	%
Number of limited partner interests		3,509		3,509

Revenues

Combination Income/Drilling Program 1988’s oil and gas revenues decreased to $114,533 from $165,052 for the years ended December 31, 2001 and 2000, respectively, a decrease of 31%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Combination Income/Drilling Program 1988 decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 22%, or $6.24 per barrel, resulting in a decrease of approximately $22,500 in revenues. Oil sales represented 70% of total oil and gas sales during the year ended December 31, 2001 as compared to 67% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Combination Income/Drilling Program 1988 decreased during the same period by 10%, or $.36 per Mcf, resulting in a decrease of approximately $3,700 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $26,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2. Oil production decreased approximately 300 barrels, or 7%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $8,200 in revenues.

Gas production decreased approximately 4,300 Mcf, or 29%, during the same period, resulting in a decrease of approximately $16,000 in revenues.

The total decrease in revenues due to the change in production is approximately $24,200. The decrease in gas production is due to a lease having a hole in the tubing and was shut down part of the year ended December 31, 2001. In addition one lease was sold during the year ended December 31, 2001.

Costs and Expenses

Total costs and expenses decreased to $104,200 from $124,600 for the years ended December 31, 2001 and 2000, respectively, a decrease of 16%. The decrease is the result of lower lease operating costs and general and administrative costs, partially offset by an increase in depletion expense.

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1.  Lease operating costs and production taxes decreased 25%, or approximately $24,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000. The decrease in lease operating costs is due to property sales of three leases during the year ended December 31, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased less than 1%, or approximately $35, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $5,000 for the year ended December 31, 2001 from $900 for the same period in 2000. This represents an increase of 456%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Combination Income/Drilling Program 1988’s independent petroleum consultants. The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Combination Income/Drilling Program 1988’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Combination Income/Drilling Program 1988 during 2001 as compared to 2000.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.38	$	16.75	69	%
Average price per Mcf of gas	$	3.72	$	1.94	92	%
Oil production in barrels		3,900		4,110	(5	%)
Gas production in Mcf		14,600		16,180	(10	%)
Gross oil and gas revenue	$	165,052	$	100,304	65	%
Net oil and gas revenue	$	66,435	$	27,099	145	%
Combination Income/Drilling Program 1988 distributions	$	133	$	—	100	%
Limited partner distributions	$	113	$	—	100	%
Per unit distribution to limited partners	$	20	$	—	100	%
Number of limited partner interests		3,509		3,509

Revenues

Combination Income/Drilling Program 1988’s oil and gas revenues increased to $165,052 from $100,304 for the years ended December 31, 2000 and 1999, respectively, an increase of 65%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Combination Income/Drilling Program 1988 increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 69%, or $11.63 per barrel, resulting in an increase of approximately $45,400 in revenues. Oil sales represented 67% of total oil and gas sales during the year ended December 31, 2000 as compared to 69% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Combination Income/Drilling Program 1988 increased during the same period by 92%, or $1.78 per Mcf, resulting in an increase of approximately $26,000 in revenues.

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The total increase in revenues due to the change in prices received from oil and gas production is approximately $71,400. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 210 barrels, or 5%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $3,500 in revenues.

Gas production decreased approximately 1,580 Mcf, or 10%, during the same period, resulting in a decrease of approximately $3,100 in revenues.

The total decrease in revenues due to the change in production is approximately $6,600.

Costs and Expenses

Total costs and expenses increased to $124,600 from $101,500 for the years ended December 31, 2000 and 1999, respectively, an increase of 23%. The increase is the result of higher lease operating costs partially offset by a decrease in depletion expense and general and administrative costs.

1.  Lease operating costs and production taxes were 35% higher, or approximately $25,400 more, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as pulling expense being performed on one lease, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Combination Income/Drilling Program 1988 to perform these repairs and maintenance in hopes of increasing production, thereby increasing revenues.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 5%, or approximately $1,200, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $900 for the year ended December 31, 2000 from $2,000 for the same period in 1999. This represents a decrease of 55%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Combination Income/Drilling Program 1988’s independent petroleum consultants. The major factor to the decline in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Combination Income/Drilling Program 1988’s reserves for January 1, 2001 as compared to 2000.

Revenue and Distribution Comparison

Combination Income/Drilling Program 1988’s net income (loss) for the years ended December 31, 2001, 2000 and 1999 was $10,348, $40,452 and $(1,229), respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 was $15,348, $41,352, and $771, respectively. Correspondingly, Combination Income/Drilling Program 1988’s distributions for the years ended December 31, 2001, 2000 and 1999 were $11,000, $133 and none, respectively.

The sources for the 2001 distributions of $11,000 were oil and gas operations of approximately $23,800 and the change in oil and gas properties of approximately $1,200 resulting in excess cash for contingencies or subsequent distributions. The sources for the 2000 distributions of $133 were oil and gas operations of approximately $140 resulting in excess cash for contingencies or subsequent distributions. There were no distributions during 1999.

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Total distributions during the year ended December 31, 2001 were $11,000 of which $9,350 was distributed to the limited partners and $1,650 to the managing general partner. The per unit distribution to limited partners during the same period was $2.66. Total distributions during the year ended December 31, 2000 were $133 of which $113 was distributed to the limited partners and $20 to the general partners. The per unit distribution to limited partners during the same period was $.03. There were no distributions made during 1999.

Liquidity and Capital Resources of Combination Income/Drilling Program 1988

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Combination Income/Drilling Program 1988 knows of no material change.

Cash flows (used in) provided by operating activities were approximately $(3,100) in the six months ended June 30, 2002 as compared to approximately $14,100 in the six months ended June 30, 2001. The primary use of the 2002 cash flow from operating activities was operations.

There were no cash flows from investing activities in 2002. Cash flows provided by investing activities were approximately $1,200 in the six months ended June 30, 2001.

There were no cash flows from financing activities in 2002. Cash flows used in financing activities were approximately $5,500 in the six months ended June 30, 2001.

Since inception of Combination Income/Drilling Program 1988, cumulative monthly cash distributions of $1,042,534 have been made to the partners. As of June 30, 2002, $892,747 or $254.42 per unit of limited partner interest had been distributed to the limited partners, representing a 51% return of the capital contributed.

As of June 30, 2002, Combination Income/Drilling Program 1988 had approximately $16,800 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Combination Income/Drilling Program 1988.

Cash flows provided by operating activities were approximately $23,800 in 2001 compared to $142 in 2000 and $12 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows provided by (used in) investing activities were approximately $1,200 in 2001 compared to $(12) in 2000 and 1999. The primary source of the 2001 cash flow from investing activities was sale of oil and gas properties.

Cash flows used in financing activities were approximately $11,200 in 2001 compared to $179 in 2000 and none in 1999. The only use in financing activities was the distributions to partners.

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SOUTHWEST ROYALTIES, INC.  

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1990, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Developmental Drilling Fund 1990, L.P., which we call Developmental Drilling Fund 1990, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Developmental Drilling Fund 1990. The purpose of the special meeting is for you to vote upon the merger of Developmental Drilling Fund 1990 with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Developmental Drilling Fund 1990 is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Developmental Drilling Fund 1990:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Developmental Drilling Fund 1990

• Compensation and distributions from Developmental Drilling Fund 1990

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial data and operating data for Developmental Drilling Fund 1990 for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Developmental Drilling Fund 1990’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Developmental Drilling Fund 1990 as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Developmental Drilling Fund 1990, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Developmental Drilling Fund 1990 in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of Developmental Drilling Fund 1990s have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on the Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our

2

common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Developmental Drilling Fund 1990’s assets. The Merger Value of Developmental Drilling Fund 1990 is based upon a formula to allocate shares of common stock and does not constitute a market value of our stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Developmental Drilling Fund 1990, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Developmental Drilling Fund 1990 by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Developmental Drilling Fund 1990. We believe, however, Developmental Drilling Fund 1990 will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Developmental Drilling Fund 1990. Our decision is based on the following factors in order of significance:

• Our method of valuation for Developmental Drilling Fund 1990 uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Developmental Drilling Fund 1990, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Developmental Drilling Fund 1990. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

3

MERGER VALUE FOR DEVELOPMENTAL DRILLING FUND 1990

The Merger Value for Development Drilling Fund 1990 was determined by calculating its Net Asset Value and then dividing Development Drilling Fund 1990’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Development Drilling Fund 1990’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Developmental Drilling Fund 1990’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Developmental Drilling Fund 1990. As indicated below, the number of shares of common stock issuable per each unit of Developmental Drilling Fund 1990 is 56.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Developmental Drilling Fund 1990
		Net Present Value of Reserves	$	515,404.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	18,434.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Developmental Drilling Fund 1990	$	533,838.00	calculated
(2)		Net Asset Value of Developmental Drilling Fund 1990	$	533,838.00	calculated
	less	GP % owned by Southwest in Developmental Drilling Fund 1990 (15%)	$	80,075.70	Partnership records
	less	LP % owned by Southwest in Developmental Drilling Fund 1990 (0%)	$	—	Partnership records
	equals	Net Asset Value of Developmental Drilling Fund 1990 owned by limited partners (excluding Southwest’s ownership %)	$	453,762.30	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value
			$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Developmental Drilling Fund 1990 (excluding Southwest’s ownership %)	$	453,762.30	calculated
	equals	The percentage of ownership of Developmental Drilling Fund 1990 (other than Southwest) to the total Net Asset Value		0.58%	calculated

4

				Document(s) from which information was obtained or calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Developmental Drilling Fund 1990 (other than Southwest)	0.58%	calculated
	equals	The number of shares of common stock attributable to Developmental Drilling Fund 1990 (other than to Southwest)	9,759.30	calculated
(7)		The number of shares of common stock attributable to Developmental Drilling Fund 1990 (other than to Southwest)	9,759	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 1990	174	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 1990	56	calculated
(8)		The number of shares of special stock attributable to Developmental Drilling Fund 1990 (other than to Southwest)	1,952	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 1990	174	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Developmental Drilling Fund 1990	11.25	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger in the prospectus/proxy statement.” The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Developmental Drilling Fund 1990 for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	12,000	$	12,000	$	12,000	$	6,000
Administrative Overhead per Operating Agreements	$	7,936	$	7,644	$	6,521	$	4,019
Cash Distributions Paid to General Partner as General Partner	$	5,400	$	9,225	$	3,225	$	2,700
Cash Distributions Paid to General Partner as Limited Partner	$	—	$	—	$	—	$	—

Set forth below is a table showing the cash distributions to Developmental Drilling Fund 1990’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	30,600	$	52,275	$	18,275	$	12,070	$	70,210	$	15,300
Return of Capital: 57%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

6

SUPPLEMENTAL INFORMATION TABLE FOR DEVELOPMENTAL DRILLING FUND 1990

Aggregate Initial Investment by the Limited Partners:	$	1,735	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	991	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	454	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	130.77	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		13.7	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	(25.24	)(2)(4)
—as of December 31, 2001:	$	(25.38	)(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	84.71	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	87.44	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	110.82	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Developmental Drilling Fund 1990 is equal to (1) the sum of (A) the present value of estimated future net revenues from Developmental Drilling Fund 1990’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Developmental Drilling Fund 1990 is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 limited partner interest sold to calculate the book value per $500 units of limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Developmental Drilling Fund 1990 is based upon (1) the sum of (A) the estimated net cash flow from the sale of Developmental Drilling Fund 1990’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Developmental Drilling Fund 1990’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the  12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Developmental Drilling Fund 1990 is based upon (1) the sum of (A) the sale of Developmental Drilling Fund 1990’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Developmental Drilling Fund 1990’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Developmental Drilling Fund 1990 and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Developmental Drilling Fund 1990 is based upon (1) the sum of (A) Developmental Drilling Fund 1990’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Developmental Drilling Fund 1990.

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DEVELOPMENTAL DRILLING FUND 1990

Set forth below is basic information about Developmental Drilling Fund 1990 and its business and operations. It does not contain all the information about Developmental Drilling Fund 1990 that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Developmental Drilling Fund 1990

General

Developmental Drilling Fund 1990 was organized as a Delaware limited partnership on July 18, 1990. The offering of limited partner and general partner interests began July 30, 1990, reached minimum capital requirements on November 29, 1990 and concluded December 31, 1990. Total limited partner contributions were $1,735,000. The managing general partner contribution was $195,999. Total capital contributions were $1,930,999.

Principal Products, Marketing and Distribution

Developmental Drilling Fund 1990 has acquired leasehold interests and drilled oil and gas properties located in Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	67%	33%
2000	71%	29%
1999	63%	37%

As the table indicates, the majority of Developmental Drilling Fund 1990’s revenue is from its oil production.

Customer Dependence

No material portion of Developmental Drilling Fund 1990’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Developmental Drilling Fund 1990. Two purchasers accounted for 100% of Developmental Drilling Fund 1990’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 67% and Duke Energy Transport and Trade for 33%. Two purchasers accounted for 100% of Developmental Drilling Fund 1990’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 70% and Duke Energy Transport and Trade for 30%. Three purchasers accounted for 97% of Developmental Drilling Fund 1990’s total oil and gas production during 1999: Scurlock Permian LLC for 60%, Duke Energy Transport and Trade for 26% and Sid Richardson Gasoline Company for 11%. All purchasers of Developmental Drilling Fund 1990’s oil and gas production are unrelated third parties. In the event these purchasers were to discontinue purchasing Developmental Drilling Fund 1990’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Developmental Drilling Fund 1990’s total oil and gas production.

Properties

As of December 31, 2001, Developmental Drilling Fund 1990 possessed an interest in oil and gas properties located in Ward and Winkler Counties, Texas. These properties consist of various interests in 3 wells.

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There have not been any significant changes in properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

Significant Properties

The following table reflects the significant properties in which Developmental Drilling Fund 1990 has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Oakland Hendricks B Winkler County Texas	1/91; 49.7% working interest	1	18,000	32,000
Carson D #1, Ward County, Texas	1/91; 59.3% working interest	1	24,000	62,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Developmental Drilling Fund 1990’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.69 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.22 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 1990,” oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Developmental Drilling Fund 1990. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Developmental Drilling Fund 1990 has reserves which are classified as proved developed producing. All of the proved reserves are included in the engineering reports which evaluate Developmental Drilling Fund 1990’s present reserves.

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Market Information for Developmental Drilling Fund 1990’s Partnership Interests and Related Partnership Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Developmental Drilling Fund 1990 should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by United Bank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. As of December 31, 2001, 2000 and 1999, no units of limited partner interest were purchased by the managing general partner. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 95 holders of limited partner interest in Developmental Drilling Fund 1990.

Distributions

Pursuant to Article IV, Section 4.01 of Developmental Drilling Fund 1990’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Developmental Drilling Fund 1990’s] drilling activities, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of [Developmental Drilling Fund 1990,] including, but not limited to, drilling cost overruns, as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $36,000, with $30,600 distributed to the investor partners and $5,400 to the managing general partner. For the year ended December 31, 2001, distributions of $176.37 per investor partner unit were made, based upon 173.5 investor partner units outstanding. During 2000, distributions were made totaling $61,500, with $52,275 distributed to the investor partners and $9,225 to the managing general partner. For the year ended December 31, 2000, distributions of $301.30 per investor partner unit were made, based upon 173.5 investor partner units outstanding. During 1999, distributions were made totaling $21,500, with $18,275 distributed to the investor partners and $3,225 to the managing general partner. For the year ended December 31, 1999, distributions of $105.33 per investor partner unit were made, based upon 173.5 investor partner units outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR  DEVELOPMENTAL DRILLING FUND 1990

The following tables present summary selected financial information and operating data for Developmental Drilling Fund 1990 for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 1990” found elsewhere in this prospectus supplement and the financial statements and related notes for Developmental Drilling Fund 1990 included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2000, 1999, 1998, 1997 and 1996 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	47,351		68,950		118,576		115,706		101,928		102,700		200,883
Net income (loss)	18,921		18,887		30,723		58,512		33,652		(88,932	)	44,790
Partners’ share of net income (loss):
Managing general partner	3,138		3,433		5,809		9,227		5,948		(826	)	10,018
Investor partners	15,783		15,454		24,914		49,285		27,704		(88,106	)	34,772
Investor partners’ net income (loss) per unit of limited partner interest	90.97		89.07		143.60		284.07		159.68		(507.82	)	200.41
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	17,624		16,027		36,715		69,847		22,619		17,730		78,540
Net cash provided by investing activities	—		(5,630	)	(5,630	)	—		—		—		—
Net cash used in financing activities	(18,039	)	(14,927	)	(35,959	)	(60,882	)	(21,515	)	(14,240	)	(82,544	)
Net increase (decrease) in cash and cash equivalents	(415	)	(4,530	)	(4,874	)	8,965		1,104		3,490		(4,004	)
EBITDA	20,921		22,887		38,723		61,512		39,652		(5,507	)	66,790
Cash distributions	18,000		15,000		36,000		61,500		21,500		14,200		82,600
Investor partners’ cash distributions per $500 investment	4.41		3.68		8.82		15.07		5.27		3.48		20.24
Balance Sheet Data:
Cash and cash equivalents	8,537		9,296		8,952		13,826		4,861		3,757		267
Oil and gas properties, net at book value	77,897		83,897		79,897		82,267		85,267		91,267		174,692
Total assets	96,331		104,647		95,449		100,685		103,673		95,627		194,653
Total liabilities	—		73		39		—		—		4,106		—
Investor partners’ equity	(87,591	)	(79,685	)	(88,074	)	(82,390	)	(79,400	)	(88,829	)	11,347

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	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Managing general partners’ equity	183,922		184,259		183,484		183,075		183,073		180,350		183,306
Investor partner’s book value per $500 investment	(25.24	)	(22.96	)	(25.38	)	(23.74	)	(22.88	)	(25.60	)	3.27
Production:
Oil production (Bbls)	1,640		1,570		3,220		3,140		3,530		5,800		8,700
Natural gas production (Mcf)	4,000		4,750		9,300		9,000		16,550		17,900		13,800
Equivalent production (Boe)	2,307		2,362		4,770		4,640		6,288		8,783		11,000
Average Sales Price:
Oil price (per/Bbl)	22.34		27.32		24.54		29.79		18.08		11.97		18.80
Natural gas price (per/Mcf)	2.68		5.49		4.25		4.18		2.30		1.86		2.71
Average sales price (per Boe)	20.52		29.20		24.86		24.94		16.21		11.69		18.26
Operating and Overhead Costs (per Boe)
Lease operating expense	6.84		14.43		12.00		6.88		6.30		9.03		9.73
Production taxes	1.04		1.68		1.38		1.29		.85		.63		.89
General and Administrative Expense (per Boe)	3.58		3.41		3.37		3.56		2.76		2.67		1.61
Total	11.46		19.76		16.75		11.73		9.91		12.33		12.23
Cash Operating Margin (per Boe)	9.06		9.81		8.11		13.21		6.30		(.64	)	6.03
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	.87		1.71		1.68		.65		.95		9.50		2.00
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	131,000		136,000		103,000		201,000		142,000		97,000		141,000
Oil (Bbls)	78,000		45,000		45,000		62,000		50,000		32,000		68,000
Total (Boe)	100,000		68,000		62,000		95,000		74,000		48,000		91,000

⁽¹⁾ Developmental Drilling Fund 1990 has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	534,000
Merger Value per $500 investment	$	130.77

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND RESULTS OF OPERATIONS OF DEVELOPMENTAL DRILLING FUND 1990

General

Developmental Drilling Fund 1990 was formed to engage primarily in the business of drilling developmental wells and to produce and market crude oil and natural gas produced from such properties, to distribute any net proceeds from operations to the general and limited partners and to the extent necessary, acquire leases, which contain drilling prospects. Net revenues will not be reinvested in other revenue producing assets except to the extent that performance of remedial work is needed to improve a well’s producing capabilities. The economic life of Developmental Drilling Fund 1990 thus depends on the period over which Developmental Drilling Fund 1990’s oil and gas reserves are economically recoverable.

Results of Operations—General Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.49	$	27.05	(9	%)
Average price per Mcf of gas	$	3.13	$	4.51	(31	%)
Oil production in barrels		875		680	29	%
Gas production in Mcf	$	2,130		2,250	(5	%)
Gross oil and gas revenue	$	28,109	$	32,786	(14	%)
Net oil and gas revenue	$	18,655	$	16,864	11	%
Developmental Drilling Fund 1990 distributions	$	9,000	$	15,000	(40	%)
Limited partner distributions	$	7,650	$	12,750	(40	%)
Number of limited partner interests		173.5		173.5

Revenues

Developmental Drilling Fund 1990’s oil and gas revenues decreased to $28,109 from $32,786 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 14%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1990 decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 9%, or $2.56 per barrel, resulting in a decrease of approximately $2,200 in revenues. Oil sales represented 76% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 64% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 1990 decreased during the same period by 31%, or $1.38 per Mcf, resulting in a decrease of approximately $2,900 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $5,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 200 barrels, or 29%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in an increase of approximately $5,300 in revenues.

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Gas production decreased approximately 120 Mcf, or 5%, during the same period, resulting in a decrease of approximately $500 in revenues.

The net total increase in revenues due to the change in production is approximately $4,800. The increase in oil production is primarily due to successful maintenance and repairs being performed during 2001 on one lease.

Costs and Expenses

Total costs and expenses decreased to $14,589 from $22,997 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 37%. The decrease is the result of lower lease operating costs and depletion expense, partially offset by an increase in general and administrative expense.

1.  Lease operating costs and production taxes decreased 41%, or approximately $6,500, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in lease operating expense is due to successful maintenance and other repairs being performed in 2001 on one lease, and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $1,000 for the quarter ended June 30, 2002, from $3,000 for the same period in 2001. This represents a decrease of 67%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1990’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 1990 during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.34	$	27.32	(18	%)
Average price per Mcf of gas	$	2.68	$	5.49	(51	%)
Oil production in barrels		1,640		1,570	4	%
Gas production in Mcf		4,000		4,570	(12	%)
Gross oil and gas revenue	$	47,351	$	68,950	(31	%)
Net oil and gas revenue	$	29,169	$	30,918	(6	%)
Developmental Drilling Fund 1990 distributions	$	18,000	$	15,000	20	%
Limited partner distributions	$	15,300	$	12,750	20	%
Number of limited partner interests		173.5		173.5

Revenues

Developmental Drilling Fund 1990’s oil and gas revenues decreased to $47,351 from $68,950 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 31%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

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1.  The average price for a barrel of oil received by Developmental Drilling Fund 1990 decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.98 per barrel, resulting in a decrease of approximately $8,200 in revenues. Oil sales represented 77% of total oil and gas sales during the six months ended June 30, 2002 as compared to 63% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 1990 decreased during the same period by 51%, or $2.81 per Mcf, resulting in a decrease of approximately $11,200 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $19,400. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 70 barrels, or 4%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in an increase of approximately $1,900 in revenues.

Gas production decreased approximately 570 Mcf, or 12%, during the same period, resulting in a decrease of approximately $3,100 in revenues.

The net total decrease in revenues due to the change in production is approximately $1,200.

Costs and Expenses

Total costs and expenses decreased to $28,438 from $50,075 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 43%. The decrease is the result of lower lease operating costs and depletion expense, partially offset by an increase in general and administrative expense.

1.  Lease operating costs and production taxes decreased 52%, or approximately $19,900, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001. The decrease in lease operating expense is due to workovers performed during 2001, and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $2,000 for the six months ended June 30, 2002 from $4,000 for the same period in 2001. This represents a decrease of 50%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1990’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 1990 during 2002 as compared to 2001.

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Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	24.54	$	29.79	(18	%)
Average price per Mcf of gas	$	4.25	$	4.18	2	%
Oil production in barrels		3,220		3,140	3	%
Gas production in Mcf		9,300		9,000	3	%
Gross oil and gas revenue	$	118,576	$	115,706	2	%
Net oil and gas revenue	$	54,741	$	77,800	(30	%)
Developmental Drilling Fund 1990 distributions	$	36,000	$	61,500	(41	%)
Limited partner distributions	$	30,600	$	52,275	(41	%)
Per unit distribution to limited partners	$	176.37	$	301.30	(41	%)
Number of limited partner interests		173.5		173.5

Revenues

Developmental Drilling Fund 1990’s oil and gas revenues increased to $118,576 from $115,707 for the years ended December 31, 2001 and 2000, respectively, an increase of 2%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1990 decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 18%, or $5.25 per barrel, resulting in a decrease of approximately $16,900 in revenues. Oil sales represented 67% of total oil and gas sales during the year ended December 31, 2001 as compared to 71% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Developmental Drilling Fund 1990 increased during the same period by 2%, or $.07 per Mcf, resulting in an increase of approximately $700 in revenues.

The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $16,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 80 barrels, or 3%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in an increase of approximately $2,400 in revenues.

Gas production increased approximately 300 Mcf, or 3%, during the same period, resulting in an increase of approximately $1,300 in revenues.

The total increase in revenues due to the change in production is approximately $3,700.

Costs and Expenses

Total costs and expenses increased to $87,913 from $57,438 for the years ended December 31, 2001 and 2000, respectively, an increase of 53%. The increase is the result of higher lease operating costs and depletion expense, partially offset by a decrease in general and administrative costs.

1.  Lease operating costs and production taxes increased 68%, or approximately $25,900, during the year ended December 31, 2001 as compared to the year ended December 31, 2000. The increase in lease operating costs is due in part to one well being shut in during 2000 and increase in major repairs and maintenance, such as pulling expense being performed on two leases.

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2.  General and administrative costs consist of independent accounting and engineering fees, computer   services, postage, and managing general partner personnel costs. General and administrative costs decreased 3%, or approximately $500, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $8,000 for the year ended December 31, 2001 from $3,000 for the same period in 2000. This represents an increase of 167%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1990’s independent petroleum consultants. The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Developmental Drilling Fund 1990’s reserves for January 1, 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	29.79	$	18.08	65	%
Average price per Mcf of gas	$	4.18	$	2.30	82	%
Oil production in barrels		3,140		3,530	(11	%)
Gas production in Mcf		9,000		16,550	(46	%)
Gross oil and gas revenue	$	115,706	$	101,928	14	%
Net oil and gas revenue	$	77,800	$	56,931	37	%
Developmental Drilling Fund 1990 distributions	$	61,500	$	21,500	186	%
Limited partner distributions	$	52,275	$	18,275	186	%
Per unit distribution to limited partners	$	301.30	$	105.33	186	%
Number of limited partner interests		173.5		173.5

Revenues

Developmental Drilling Fund 1990’s oil and gas revenues increased to $115,706 from $101,928 for the years ended December 31, 2000 and 1999, respectively, an increase of 14%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1990 increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 65%, or $11.71 per barrel, resulting in an increase of approximately $36,800 in revenues. Oil sales represented 71% of total oil and gas sales during the year ended December 31, 2000 as compared to 63% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Developmental Drilling Fund 1990 increased during the same period by 82%, or $1.88 per Mcf, resulting in an increase of approximately $16,900 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $53,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 390 barrels, or 11%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $7,100 in revenues.

17

Gas production decreased approximately 7,550 Mcf, or 46%, during the same period, resulting in a decrease of approximately $17,400 in revenues.

The total decrease in revenues due to the change in production is approximately $24,500. The decrease in gas production is due to a well that was shut down during part of 2000.

Costs and Expenses

Total costs and expenses decreased to $57,438 from $68,364 for the years ended December 31, 2000 and 1999, respectively, a decrease of 16%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative costs.

1.  Lease operating costs and production taxes decreased 16%, or approximately $7,100, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The decrease in lease operating costs is due in part to one well being shut in during 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 5%, or approximately $800, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $3,000 for the year ended December 31, 2000, from $6,000, for the same period in 2000. This represents a decrease of 50%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1990’s independent petroleum consultants.

The major factor to the decline in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Developmental Drilling Fund 1990’s reserves for January 1, 2001 as compared to 2000.

Revenue and Distribution Comparison

Developmental Drilling Fund 1990’s net income for the years ended December 31, 2001, 2000 and 1999 was $30,723, $58,512 and $33,652, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 was $38,723, $61,512 and $39,652, respectively. Correspondingly, Developmental Drilling Fund 1990’s distributions for the years ended December 31, 2001, 2000 and 1999 were $36,000, $61,500 and $21,500, respectively.

The sources for the 2001 distributions of $36,000 were oil and gas operations of approximately $36,700 and the change in oil and gas properties of approximately $(6,000), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $61,500 were oil and gas operations of approximately $69,800, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $21,500 were oil and gas operations of approximately $22,600, resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $36,000 of which $30,600 was distributed to the investor partners and $5,400 to the managing general partner. The per unit distribution to investor partners during the same period was $176.37. Total distributions during the year ended December 31, 2000 were $61,500 of which $52,275 was distributed to the investor partners and $9,225 to the managing general partner. The per unit distribution to investor partners during the same period was $301.30. Total distributions during the year ended December 31, 1999 were $21,500 of which $18,275 was distributed to the investor partners and $3,225 to the managing general partner. The per unit distribution to investor partners during the same period was $105.33.

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Liquidity and Capital Resources of Developmental Drilling Fund 1990

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Developmental Drilling Fund 1990 knows of no material change.

Cash flows provided by operating activities were approximately $17,600 in the six months ended June 30, 2002 as compared to approximately $16,000 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was operations.

No cash flows were used in investing activities in the six months ended June 30, 2002 as compared to approximately $5,600 in the six months ended June 30, 2001.

Cash flows used in financing activities were approximately $18,000 in the six months ended June 30, 2002 as compared to approximately $14,900 in the six months ended June 30, 2001. The use of the 2002 cash flow from financing activities was distributions to partners.

Total distributions during the six months ended June 30, 2002 were $18,000 of which $15,300 was distributed to the investor partners and $2,700 to the managing general partners. The per unit distribution to investor partners during the six months ended June 30, 2002 was $88.18. Total distributions during the six months ended June 30, 2001 were $15,000 of which $12,750 was distributed to the investor partners and $2,250 to the managing general partners. The per unit distribution to investor partners during the six months ended June 30, 2001 was $73.49.

The sources for the 2002 distributions of $18,000 were oil and gas operations of approximately $17,600, with the balance from available cash on hand at the beginning of the period. The sources for the 2001 distributions of $15,000 were oil and gas operations of approximately $16,000, and the change in oil and gas properties of approximately $(5,600), with the balance from available cash on hand at the beginning of the period.

Since inception of Developmental Drilling Fund 1990, cumulative monthly cash distributions of $1,125,907 have been made to the partners. As of June 30, 2002, $991,057 or $5,712.14 per limited partner unit has been distributed to the investor partners, representing a 57% return of the capital contributed.

As of June 30, 2002, Developmental Drilling Fund 1990 had approximately $18,400 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Developmental Drilling Fund 1990.

Cash flows provided by operating activities were approximately $36,700 in 2001 compared to $69,800 in 2000 and $22,600 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $5,600 in 2001. There were no cash flows from investing activities in 2000 and 1999. The principle use of the 2001 cash flows from investing activities is additions to oil and gas properties.

Cash flows used in financing activities were approximately $36,000 in 2001 compared to $60,900 in 2000 and $21,500 in 1999. The only use in the 2001 financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST DEVELOPMENTAL DRILLING FUND 91-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Developmental Drilling Fund 91-A, L.P., which we call Developmental Drilling Fund 91-A, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Developmental Drilling Fund 91-A. The purpose of the special meeting is for you to vote upon the merger of Developmental Drilling Fund 91-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Developmental Drilling Fund 91-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Developmental Drilling Fund 91-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Developmental Drilling Fund 91-A

• Compensation and distributions from Developmental Drilling Fund 91-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Developmental Drilling Fund 91-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Developmental Drilling Fund 91-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Developmental Drilling Fund 91-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Developmental Drilling Fund 91-A, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Developmental Drilling Fund 91-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on the Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be accepted or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Developmental Drilling Fund 91-A’s assets. The Merger Value of Developmental Drilling Fund 91-A is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves.

2

While we believe the Merger Value is a fair measure for allocating shares of our common to Developmental Drilling Fund 91-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Developmental Drilling Fund 91-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Developmental Drilling Fund 91-A. We believe, however, that Developmental Drilling Fund 91-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Developmental Drilling Fund 91-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Developmental Drilling Fund 91-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Developmental Drilling Fund 91-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Developmental Drilling Fund 91-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger”.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

3

MERGER VALUE FOR DEVELOPMENTAL DRILLING FUND 91-A

The Merger Value for Developmental Drilling Fund 91-A was determined by calculating its Net Asset Value and then dividing Developmental Drilling Fund 91-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Developmental Drilling Fund 91-A’s ownership percentage of Southwest and, thus, the number of shares of our common stock and special stock to be distributed to Developmental Drilling Fund 91-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Developmental Drilling Fund 91-A. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 91-A is 4.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Developmental Drilling Fund 91-A
		Net Present Value of Reserves	$	191,191.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	19,220.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Developmental Drilling Fund 91-A	$	210,411.00	calculated
(2)		Net Asset Value of Developmental Drilling Fund 91-A	$	210,411.00	calculated
	less	GP% owned by Southwest in Developmental Drilling Fund 91-A (11%)	$	23,145.21	Partnership records
	less	LP% owned by Southwest in Developmental Drilling Fund 91-A (1.71%)	$	3,598.03	Partnership records
	equals	Net Asset Value of Developmental Drilling Fund 91-A owned by limited partners (excluding Southwest’s ownership %)	$	183,667.76	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Developmental Drilling Fund 91-A (excluding Southwest’s ownership %)	$	183,667.76	calculated
	equals	The percentage of ownership of Developmental Drilling Fund 91-A (other than Southwest) to the total Net Asset Value		0.23%	calculated

4

				Document(s) from which information was obtained or calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding	1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity	59.23%	calculated
	equals	Total number of shares of common stock for combined entity	1,688,347	calculated
(6)		Total number of shares of common stock for combined entity	1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Developmental Drilling Fund 91-A (other than Southwest)	0.23%	calculated
	equals	The number of shares of common stock attributable to Developmental Drilling Fund 91-A (other than to Southwest)	3,950.24	calculated
(7)		The number of shares of common stock attributable to Developmental Drilling Fund 91-A (other than to Southwest)	3,950	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 91-A	1,123	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 91-A	4	Calculated
(8)		The number of shares of special stock attributable to Developmental Drilling Fund 91-A (other than to Southwest)	790	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Developmental Drilling Fund 91-A	1,123	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Developmental Drilling Fund 91-A	.70	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Developmental Drilling Fund 91-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	10,800	$	10,800	$	11,000	$	5,400
Administrative Overhead per Operating Agreements	$	11,841	$	11,405	$	13,024	$	6,110
Cash Distributions Paid to General Partner as General Partner	$	6,846	$	13,314	$	9,350	$	1,100
Cash Distributions Paid to General Partner as Limited Partner	$	1,815	$	463	$	328	$	171

Set forth below is a table showing the cash distributions to Developmental Drilling Fund 91-A’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	55,388	$	107,721	$	75,650	$	36,045	$	258,100	$	8,900
Return of Capital: 100%; Return on Capital: 9%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR DEVELOPMENTAL DRILLING FUND 91-A

Aggregate Initial Investment by the Limited Partners:	$	1,145	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	1,253	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	187	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	81.81	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		7.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	47.60	(2)(4)
—as of December 31, 2001:	$	48.35	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	4.49	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	46.46	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	64.99	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

6

⁽³⁾ The Merger Value for Developmental Drilling Fund 91-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Developmental Drilling Fund 91-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Developmental Drilling Fund 91-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Developmental Drilling Fund 91-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Developmental Drilling Fund 91-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Developmental Drilling Fund 91-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Developmental Drilling Fund 91-A is based upon (1) the sum of (A) the sale of Developmental Drilling Fund 91-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Developmental Drilling Fund 91-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Developmental Drilling Fund 91-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Developmental Drilling Fund 91-A is based upon (1) the sum of (A) Developmental Drilling Fund 91-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Developmental Drilling Fund 91-A.

DEVELOPMENTAL DRILLING FUND 91-A

Set forth below is basic information about Developmental Drilling Fund 91-A and its business and operations. It does not contain all the information about Developmental Drilling Fund 91-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Developmental Drilling Fund 91-A

General

Developmental Drilling Fund 91-A was organized as a Delaware limited partnership on January 7, 1991. The offering of limited partner and general partner interests began September 17, 1991 as part of a shelf offering registered under the name Southwest Developmental Drilling Program 1991-92, reached minimum capital requirements on April 22, 1992 and concluded April 30, 1992, with total investor partner contributions of $1,144,500. The managing general partner made a contribution to the capital of Developmental Drilling Fund 91-A at the conclusion of its offering period in an amount equal to 1% of its net capital contributions. The managing general partner contribution was $9,800. Total capital contributions were $1,154,300.

7

Principal Products, Marketing and Distribution

Developmental Drilling Fund 91-A has acquired leasehold interests and drilled oil and gas properties located in Texas and New Mexico.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	82%	18%
2000	85%	15%
1999	86%	14%

As the table indicates, the majority of Developmental Drilling Fund 91-A’s revenue is from its oil production.

Customer Dependence

No material portion of Developmental Drilling Fund 91-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Developmental Drilling Fund 91-A. Two purchasers accounted for 94% of Developmental Drilling Fund 91-A’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 76% and Duke Energy Field Services for 18%. Two purchasers accounted for 91% of Developmental Drilling Fund 91-A’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 78% and Duke Energy Transport for 13%. Two purchasers accounted for 85% of Developmental Drilling Fund 91-A’s total oil and gas production during 1999: Navajo Refining Company, Inc. for 52% and Scurlock Permian LLC for 33%. All purchasers of Developmental Drilling Fund 91-A’s oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing Developmental Drilling Fund 91-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Developmental Drilling Fund 91-A’s total oil and gas production.

Properties

As of December 31, 2001, Developmental Drilling Fund 91-A possessed an interest in oil and gas properties located in Eddy County, New Mexico; and Rains, Van Zandt and Ward Counties, Texas. These properties consist of various interests in 5 wells.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

Significant Properties

The following table reflects the significant properties in which Developmental Drilling Fund 91-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Carson F#1 Ward County, Texas	6/92—89% working interest	1	23,000	25,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Developmental Drilling Fund 91-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

8

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.98 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.28 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENT DRILLING FUND 91-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Developmental Drilling Fund 91-A. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Developmental Drilling Fund 91-A has reserves which are classified as proved developed producing and proved developed non-producing. All of the proved reserves are included in the engineering reports which evaluate Developmental Drilling Fund 91-A’s present reserves.

Market for Developmental Drilling Fund 91-A’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Developmental Drilling Fund 91-A should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 17 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $214.15 per unit. As of December 31, 2000, no units of limited partner interest were purchased by the managing general partner. In 1999, 5 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $78.06 per unit. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited and General Partner Interest Holders

As of December 31, 2001, there were 102 holders of limited partner interest and no holders of general partner units in Developmental Drilling Fund 91-A.

9

Distributions

Pursuant to Article IV, Section 4.01 of Developmental Drilling Fund 91-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Developmental Drilling Fund 91-A’s] drilling activities, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Developmental Drilling Fund 91-A], including, but not limited to, drilling cost overruns, as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $62,234, with $55,388 distributed to the limited partners and $6,846 to the managing general partner. For the year ended December 31, 2001, distributions of $48.39 per units of limited partner interest were made, based upon 1,144.50 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $121,035, with $107,721 distributed to the limited partners and $13,314 to the managing general partner. For the year ended December 31, 2000, distributions of $94.12 per unit of limited partner interest were made, based upon 1,144.50 units of limited partner interest outstanding. During 1999, distributions were made totaling $85,000, with $75,650 distributed to the limited partners and $9,350 to the managing general partner. For the year ended December 31, 1999, distributions of $66.10 per unit of limited partner interest were made, based upon 1,144.5 units of limited partner interest outstanding.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

DEVELOPMENTAL DRILLING FUND 91-A

The following tables present summary selected financial information and operating data for Developmental Drilling Fund 91-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION and Analysis of Financial Condition and Results of Operations for Developmental Drilling Fund 91-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Developmental Drilling Fund 91-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, and Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	50,218		79,022		139,132		162,628		251,484		172,545		304,617
Net income (loss)	8,810		23,688		30,325		58,242		119,990		(3,178	)	126,704
Partners’ share of net income (loss):
Managing general partner	1,629		3,596		5,536		7,617		17,159		5,480		20,529
Investor partners	7,181		20,092		24,789		50,625		102,831		(8,658	)	106,175
Investor partners’ net income (loss) per unit of limited partner interest	6.27		17.56		21.66		44.23		89.85		(7.57	)	92.77
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	6,351		37,169		60,443		78,711		134,597		67,283		229,507
Net cash provided by investing activities	—		—		(184	)	(151	)	(873	)	(21,824	)	(9,368	)
Net cash used in financing activities	(10,039	)	(42,252	)	(62,195	)	(120,418	)	(88,247	)	(38,217	)	(289,653	)
Net increase (decrease) in cash and cash equivalents	(3,688	)	(5,283	)	(1,936	)	(41,858	)	45,477		7,242		(69,514	)
EBITDA	14,810		32,688		50,325		69,242		155,990		49,822		186,627
Cash distributions	10,000		42,500		62,234		121,035		85,000		40,500		290,000
Investor partners’ cash distributions per $500 investment	3.89		16.52		24.20		47.06		33.05		15.75		112.76

11

	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Balance Sheet Data:
Cash and cash equivalents	8,714	9,055	12,402	14,338	56,196	10,719	3,477
Oil and gas properties, net at book value	112,776	129,592	118,776	138,592	149,441	184,568	215,744
Total assets	131,996	146,331	133,225	165,095	227,888	195,528	236,923
Total liabilities	—	48	39	—	—	2,630	347
Investor partners’ equity	108,954	123,539	110,673	141,272	198,368	171,187	215,890
Managing general partners’ equity	23,042	22,744	22,513	23,823	29,520	21,711	20,686
Investor partner’s book value per $500 investment	47.60	53.97	48.35	61.72	86.66	74.79	94.32
Production:
Oil production (Bbls)	2,040	2,260	4,440	4,600	12,800	11,300	12,900
Natural gas production (Mcf)	1,820	3,110	5,540	6,600	19,540	17,800	21,200
Equivalent production (Boe)	2,343	2,778	5,363	5,700	16,057	14,267	16,433
Average Sales Price:
Oil price (per/Bbl)	22.43	27.71	25.84	29.88	16.88	12.74	20.10
Natural gas price (per/Mcf)	2.45	5.27	4.41	3.82	1.81	1.60	2.14
Average sales price (per Boe)	21.43	28.45	25.94	28.53	15.66	12.09	18.54
Operating and Overhead Costs (per Boe)
Lease operating expense	10.70	12.32	12.35	12.31	3.90	6.19	5.00
Production taxes	1.07	1.64	1.38	1.52	1.05	.83	1.25
General and Administrative Expense (per Boe)	3.35	2.76	2.86	2.59	1.02	1.60	1.12
Total	15.12	16.72	16.59	16.42	5.97	8.62	7.37
Cash Operating Margin (per Boe)	6.31	11.73	9.35	12.11	9.69	3.47	11.17
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	2.56	3.24	3.73	1.93	2.24	3.71	3.65
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	42,000	47,000	31,000	69,000	61,000	68,000	70,000
Oil (Bbls)	28,000	40,000	25,000	49,000	44,000	46,000	55,000
Total (Boe)	35,000	48,000	30,000	60,000	54,000	57,000	67,000

⁽¹⁾ Developmental Drilling 91-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	210,000
Merger Value per $500 investment	$	81.81

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 91-A

General

Based on current conditions, management anticipates performing no workovers during 2002 to enhance production. Developmental Drilling Fund 91-A will likely experience the historical production decline of approximately 8% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,					Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.37	$	27.05		(10	%)
Average price per Mcf of gas	$	2.92	$	4.22		(31	%)
Oil production in barrels		1,180		1,110		6	%
Gar production in Mcf		1,020		1,340		(24	%)
Gross oil and gas revenue	$	31,743	$	23,540		35	%
Net oil and gas revenue	$	18,615	$	(969	)	2021	%
Developmental Drilling Fund 91-A distributions	$	10,000	$	12,500		(20	%)
Limited partner distributions	$	8,900	$	11,125		(20	%)
Per unit distribution to limited partners	$	7.78	$	9.72		(20	%)
Number of limited partner interests		1,144.5		1,144.5

Revenues

Developmental Drilling Fund 91-A’s oil and gas revenues increased to $31,743 from $23,540 for the quarters ended June 30, 2002 and 2001, respectively, an increase of 35%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 91-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 10%, or $2.68 per barrel, resulting in a decrease of approximately $3,200 in revenues. Oil sales represented 91% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 84% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 91-A decreased during the same period by 31%, or $1.30 per Mcf, resulting in a decrease of approximately $1,300 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $4,500. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 70 barrels, or 6%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in an increase of approximately $1,900 in revenues.

Gas production decreased approximately 320 Mcf, or 24%, during the same period, resulting in a decrease of approximately $1,400 in revenues.

The net total increase in revenues due to the change in production is approximately $500. The decrease in gas production is due primarily to downtime on one lease in addition to one lease that fluctuates levels of production.

13

Costs and Expenses

Total costs and expenses decreased to $21,068 from $32,338 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 35%. The decrease is the result of lower lease operating costs, partially offset by an increase in general and administrative expense.

1.  Lease operating costs and production taxes decreased 46%, or approximately $11,400, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in lease operating expense is due to one lease having successful repairs and maintenance performed in the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 3%, or approximately $100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense remained the same for the quarter ended June 30, 2002, from the same period in 2001. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 91-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.43	$	27.71	(19	%)
Average price per Mcf of gas	$	2.45	$	5.27	(54	%)
Oil production in barrels		2,040		2,260	(10	%)
Gas production in Mcf		1,820		3,110	(41	%)
Gross oil and gas revenue	$	50,218	$	79,022	(36	%)
Net oil and gas revenue	$	22,647	$	40,235	(44	%)
Developmental Drilling Fund 91-A distributions	$	10,000	$	42,500	(76	%)
Limited partner distributions	$	8,900	$	37,825	(76	%)
Per unit distribution to limited partners	$	7.78	$	33.05	(76	%)
Number of limited partner interests		1,144.5		1,144.5

Revenues

Developmental Drilling Fund 91-A’s oil and gas revenues decreased to $50,218 from $79,022 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 36%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 91-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 19%, or $5.28 per barrel, resulting in a decrease of approximately $10,800 in revenues. Oil sales represented 91% of total oil and gas sales during the six months ended June 30, 2002 as compared to 79% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 91-A decreased during the same period by 54%, or $2.82 per Mcf, resulting in a decrease of approximately $5,100 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $15,900. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

14

2.  Oil production decreased approximately 220 barrels, or 10%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $6,100 in revenues.

Gas production decreased approximately 1,290 Mcf, or 41%, during the same period, resulting in a decrease of approximately $6,800 in revenues.

The total decrease in revenues due to the change in production is approximately $12,900. The decrease in gas production is due primarily to downtime on one lease in addition to one lease that fluctuates levels of production.

Costs and Expenses

Total costs and expenses decreased to $41,411 from $55,446 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 25%. The decrease is primarily the result of lower lease operating costs and depletion expense partially offset by an increase in general and administrative expense.

1.  Lease operating costs and production taxes decreased 29%, or approximately $11,200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001. The decrease in lease operating expense is due to one lease having repairs and maintenance performed during 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $6,000 for the six months ended June 30, 2002 from $9,000 for the same period in 2001. This represents a decrease of 33%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 91-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 91-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	25.84	$	29.88	(14	%)
Average price per Mcf of gas	$	4.41	$	3.82	15	%
Oil production in barrels		4,440		4,600	(3	%)
Gas production in Mcf		5,540		6,600	(16	%)
Gross oil and gas revenue	$	139,132	$	162,628	(14	%)
Net oil and gas revenue	$	65,516	$	83,755	(22	%)
Developmental Drilling Fund 91-A distributions	$	62,234	$	121,035	(49	%)
Limited partner distributions	$	55,388	$	107,721	(49	%)
Per unit distribution to limited partners	$	48.39	$	94.12	(49	%)
Number of limited partner interests		1,144.5		1,144.5

15

Revenues

Developmental Drilling Fund 91-A’s oil and gas revenues decreased to $139,132 from $162,628 for the years ended December 31, 2001 and 2000, respectively, a decrease of 14%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 91-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 14%, or $4.04 per barrel, resulting in a decrease of approximately $17,900 in revenues. Oil sales represented 82% of total oil and gas sales during the year ended December 31, 2001 as compared to 85% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Developmental Drilling Fund 91-A increased during the same period by 15%, or $.59 per Mcf, resulting in an increase of approximately $3,300 in revenues.

The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $14,600. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 160 barrels, or 3%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $4,800 in revenues.

Gas production decreased approximately 1,060 Mcf, or 16%, during the same period, resulting in a decrease of approximately $4,000 in revenues.

The total decrease in revenues due to the change in production is approximately $8,800. Gas production is down due to workovers being performed on one lease.

Costs and Expenses

Total costs and expenses increased to $108,961 from $104,642 for the years ended December 31, 2001 and 2000, respectively, an increase of 4%. The increase is the result of higher depletion expense and general and administrative costs, partially offset by a decrease in lease operating costs.

1.  Lease operating costs and production taxes decreased 7%, or approximately $5,300, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 4%, or approximately $600, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $20,000 for the year ended December 31, 2001 from $11,000 for the same period in 2000. This represents an increase of 82%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 91-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in oil and gas prices of the 2002 reserves as compared to 2001, and the decrease in oil and gas revenues received by Developmental Drilling Fund 91-A during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $10,000 as of December 31, 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	29.88	$	16.88	77	%
Average price per Mcf of gas	$	3.82	$	1.81	111	%
Oil production in barrels		4,600		12,800	(64	%)
Gas production in Mcf		6,600		19,540	(66	%)
Gross oil and gas revenue	$	162,628	$	251,484	(35	%)
Net oil and gas revenue	$	83,755	$	171,878	(51	%)
Developmental Drilling Fund 91-A distributions	$	121,035	$	85,000	42	%
Limited partner distributions	$	107,721	$	75,650	42	%
Per unit distributions to limited partners	$	94.12	$	66.10	42	%
Number of limited partner interests		1,144.5		1,144.5

Revenues

Developmental Drilling Fund 91-A’s oil and gas revenues decreased to $162,628 from $251,484 for the years ended December 31, 2000 and 1999, respectively, a decrease of 35%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 91-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 77%, or $13.00 per barrel, resulting in an increase of approximately $59,800 in revenues. Oil sales represented 85% of total oil and gas sales during the year ended December 31, 2000 as compared to 86% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Developmental Drilling Fund 91-A increased during the same period by 111%, or $2.01 per Mcf, resulting in an increase of approximately $13,300 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $73,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 8,200 barrels, or 64%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $138,400 in revenues.

Gas production decreased approximately 12,940 Mcf, or 66%, during the same period, resulting in a decrease of approximately $23,400 in revenues.

The total decrease in revenues due to the change in production is approximately $161,800. The sharp decrease in oil and gas production is in relation to a settlement of royalty on the Dagger Draw Lease. Production interest of approximately 5,000 barrels and 7,230 Mcfs were held in suspense from 1993 through 1999. These dollars were received and recorded in Developmental Drilling Fund 91-A during the third quarter of 1999. Production without the settlement would be a decrease of 25% for oil and 29% for gas. This decrease was due to the occurrence of payout on the Dagger Draw. Upon occurrence of payout the percentage of ownership for Developmental Drilling Fund 91-A decreased significantly.

17

Costs and Expenses

Total costs and expenses decreased to $104,642 from $132,036 for the years ended December 31, 2000 and 1999, respectively, a decrease of 21%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative costs.

1.  Lease operating costs and production taxes decreased 1%, or approximately $700, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 10%, or approximately $1,700, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $11,000 for the year ended December 31, 2000 from $36,000 for the same period in 2000. This represents a decrease of 69%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 91-A’s independent petroleum consultants.

The major factor to the decline in depletion expense between the comparative periods was the increase in oil and gas prices of the 2001 reserves as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $4,000 as of December 31, 1999.

Revenue and Distribution Comparison

Developmental Drilling Fund 91-A net income for the years ended December 31, 2001, 2000 and 1999 was $30,325, $58,242 and $119,990, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 was $50,325, $69,242 and $155,990, respectively. Correspondingly, Developmental Drilling Fund 91-A distributions for the years ended December 31, 2001, 2000 and 1999 were $62,234, $121,035 and $85,000, respectively.

The sources for the 2001 distributions of $62,234 were oil and gas operations of approximately $60,400 and the change in oil and gas properties of approximately $(200), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $121,035 were oil and gas operations of approximately $78,700 and the change in oil and gas properties of approximately $(200), with the balance from available cash on hand at the beginning of the period. The sources for the 1999 distributions of $85,000 were oil and gas operations of approximately $134,600 and the change in oil and gas properties of approximately $(900), resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $62,234 of which $55,388 was distributed to the investor partners and $6,846 to the managing general partner. The per unit distribution to investor partners during the same period was $48.39. Total distributions during the year ended December 31, 2000 were $121,035 of which $107,721 was distributed to the investor partners and $13,314 to the managing general partner. The per unit distribution to investor partners during the same period was $94.12. Total distributions during the year ended December 31, 1999 were $85,000 of which $75,650 was distributed to the investor partners and $9,350 to the managing general partner. The per unit distribution to investor partners during the same period was $66.10.

Liquidity and Capital Resources of Developmental Drilling Fund 91-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Developmental Drilling Fund 91-A knows of no material change, nor does it anticipate any such change.

18

Cash flows provided by operating activities were approximately $6,400 in the six months ended June 30, 2002 as compared to approximately $37,200 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in financing activities were approximately $10,000 in the six months ended June 30, 2002 as compared to approximately $42,500 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $10,000 of which $8,900 was distributed to the investor partners and $1,100 to the managing general partner. The per unit distribution to investor partners during the six months ended June 30, 2002 was $7.78. Total distributions during the six months ended June 30, 2001 were $42,500 of which $37,825 was distributed to the investor partners and $4,675 to the managing general partner. The per unit distribution to investor partners during the six months ended June 30, 2001 was $33.05.

The source for the 2002 distributions of $10,000 was oil and gas operations of approximately $6,400, with the balance from available cash on hand at the beginning of the period. The source for the 2001 distributions of $42,500 was oil and gas operations of approximately $37,200, with the balance from available cash on hand at the beginning of the period.

Since inception of Developmental Drilling Fund 91-A, cumulative monthly cash distributions of $1,406,009 have been made to the partners. As of June 30, 2002, $1,253,259 or $1,095.03 per investor partner unit has been distributed to the investor partners, representing a 110% return of the capital contributed.

As of June 30, 2002, Developmental Drilling Fund 91-A had approximately $19,200 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Developmental Drilling Fund 91-A.

Cash flows provided by operating activities were approximately $60,400 in 2001 compared to $78,700 in 2000 and approximately $134,600 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows used in investing activities were approximately $200 in 2001 compared to $200 in 2000 and approximately $900 in 1999. The principal use of the 2001 cash flow from investing activities was additions to oil and gas properties.

Cash flows used in financing activities were approximately $62,200 in 2001 compared to $120,400 in 2000 and approximately $88,200 in 1999. The only use in the 2001 financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST DEVELOPMENTAL DRILLING FUND 92-A, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Developmental Drilling Fund 92-A, L.P., which we call Developmental Drilling Fund 92-A, and supplements the prospectus/proxy statement dated                             , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Developmental Drilling Fund 92-A. The purpose of the special meeting is for you to vote upon the merger of Developmental Drilling Fund 92-A with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Developmental Drilling Fund 92-A is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                                                      .

This document contains the following information concerning Developmental Drilling Fund 92-A:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Developmental Drilling Fund 92-A

• Compensation and distributions from Developmental Drilling Fund 92-A

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Developmental Drilling Fund 92-A for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Developmental Drilling Fund 92-A’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Developmental Drilling Fund 92-A as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Developmental Drilling Fund 92-A, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Developmental Drilling Fund 92-A in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Developmental Drilling Fund 92-A’s assets. The Merger Value for Developmental Drilling Fund 92-A is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Developmental Drilling Fund 92-A, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Developmental Drilling Fund 92-A by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Developmental Drilling Fund 92-A. We believe, however, that Developmental Drilling Fund 92-A will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Developmental Drilling Fund 92-A. Our decision is based on the following factors in order of significance:

• Our method of valuation for Developmental Drilling Fund 92-A uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Developmental Drilling Fund 92-A, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Developmental Drilling Fund 92-A. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR DEVELOPMENTAL DRILLING FUND 92-A

The Merger Value for Developmental Drilling Fund 92-A was determined by calculating its Net Asset Value and then dividing Developmental Drilling Fund 92-A’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Developmental Drilling Fund 92-A’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Developmental Drilling Fund 92-A’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Developmental Drilling Fund 92-A. The number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 92-A is 11.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Developmental Drilling Fund 92-A
		Net Present Value of Reserves	$	763,747.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	45,981.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Developmental Drilling Fund 92-A	$	809,728.00	calculated

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					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Developmental Drilling Fund 92-A	$	809,728.00	calculated
	less	GP % owned by Southwest in Developmental Drilling Fund 92-A (11%)	$	89,070.08	Partnership records
	less	LP % owned by Southwest in Developmental Drilling Fund 92-A (.32%)	$	2,591.13	Partnership records
	equals	Net Asset Value of Developmental Drilling Fund 92-A owned by limited partners (excluding Southwest’s ownership %)	$	718,066.79	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Developmental Drilling Fund 92-A (excluding Southwest’s ownership %)	$	718,066.79	calculated
	equals	The percentage of ownership of Developmental Drilling Fund 92-A (other than Southwest) to the total Net Asset Value		.91%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Developmental Drilling Fund 92-A (other than Southwest)		.91%	calculated
	equals	The number of shares of common stock attributable to Developmental Drilling Fund 92-A (other than to Southwest)		15,443.83	calculated
(7)		The number of shares of common stock attributable to Developmental Drilling Fund 92-A (other than to Southwest)		15,444	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 92-A		1,402	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 92-A		11	calculated

4

				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Developmental Drilling Fund 92-A (other than to Southwest)	3,089	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Developmental Drilling Fund 92-A	1,402	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Developmental Drilling Fund 92-A	2.20	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Developmental Drilling Fund 92-A for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	12,000	$	12,000	$	12,000	$	6,000
Administrative Overhead per Operating Agreements	$	23,564	$	22,696	$	22,356	$	11,933
Cash Distributions Paid to General Partner as General Partner	$	22,968	$	24,710	$	9,350	$	6,600
Cash Distributions Paid to General Partner as Limited Partner	$	—	$	—	$	—	$	—

Set forth below is a table showing the cash distributions to Developmental Drilling Fund 92-A limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	185,830	$	199,930	$	75,650	$	82,058	$	182,895	$	53,400

Return of Capital: 100%;  Return on Capital: 4%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR DEVELOPMENTAL DRILLING FUND 92-A

Aggregate Initial Investment by the Limited Partners:	$	1,407	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	1,466	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	721	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	256.10	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		5.8	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	69.96	(2)(4)
—as of December 31, 2001:	$	72.27	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	147.82	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	170.51	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	208.72	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

6

⁽³⁾ The Merger Value for Developmental Drilling Fund 92-A is equal to (1) the sum of (A) the present value of estimated future net revenues from Developmental Drilling Fund 92-A’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Developmental Drilling Fund 92-A is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Developmental Drilling Fund 92-A is based upon (1) the sum of (A) the estimated net cash flow from the sale of Developmental Drilling Fund 92-A’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Developmental Drilling Fund 92-A’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Developmental Drilling Fund 92-A is based upon (1) the sum of (A) the sale of Developmental Drilling Fund 92-A’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Developmental Drilling Fund 92-A’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Developmental Drilling Fund 92-A and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Developmental Drilling Fund 92-A is based upon (1) the sum of (A) Developmental Drilling Fund 92-A’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Developmental Drilling Fund 92-A.

DEVELOPMENTAL DRILLING FUND 92-A

Set forth below is basic information about Developmental Drilling Fund 92-A and its business and operations. It does not contain all the information about Developmental Drilling Fund 92-A that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Developmental Drilling Fund 92-A

General

Developmental Drilling Fund 92-A was organized as a Delaware limited partnership on May 5, 1992. The offering of limited partner and general partner interests began August 11, 1992 as part of a shelf offering registered under the name Southwest Developmental Drilling Program 1991-92. Minimum capital requirements for Developmental Drilling Fund 92-A were met on December 28, 1992, with the offering of limited partner and general partner interests concluding December 31, 1992, with total limited partner contributions of $1,407,000. The managing general partner made a contribution to the capital of Developmental Drilling Fund 92-A at the conclusion of the offering period in an amount equal to 1% of its net capital contributions. The managing general partner contribution was $12,030, for total capital contributions of $1,419,030.

7

Principal Products, Marketing and Distribution

Developmental Drilling Fund 92-A has acquired undeveloped leasehold interests and drilled oil and gas properties located in Texas and New Mexico.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	72%	28%
2000	78%	22%
1999	77%	23%

As the table indicates, the majority of Developmental Drilling Fund 92-A’s revenue is from its oil production.

Customer Dependence

No material portion of Developmental Drilling Fund 92-A’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Developmental Drilling Fund 92-A. Three purchasers accounted for 93% of Developmental Drilling Fund 92-A’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 58%, Duke Energy Field Services for 21% and Navajo Refining Company, Inc. for 14%. Three purchasers accounted for 94% of Developmental Drilling Fund 92-A’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 63%, Navajo Refining Company, Inc. for 16% and Duke Energy Transport and Trad. for 15%. Three purchasers accounted for 95% of Developmental Drilling Fund 92-A’s total oil and gas production during 1999: Scurlock Permian LLC for 59%, Duke Energy Transport and Trade. for 20% and Navajo Refining Company, Inc. for 16%. All purchasers of Developmental Drilling Fund 92-A’s oil and gas production are unrelated third parties. In the event this purchasers were to discontinue purchasing Developmental Drilling Fund 92-A’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Developmental Drilling Fund 92-A’s total oil and gas production.

Properties

As of December 31, 2001, Developmental Drilling Fund 92-A possessed an interest in oil and gas properties located in Ward County, Texas and Lea and Eddy Counties, New Mexico. These properties consist of various interests in 9 wells.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

Significant Properties

The following table reflects the properties in which Developmental Drilling Fund 92-A has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Mobil Fee H #1 Ward County, Texas	12/92 at 100% working interest	1	46,000	189,000

* Ryder Scott Company, L.P. audited prepared the reserve and present value data for Developmental Drilling Fund 92-A’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed reserves (PDP) only.

8

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.90 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.34 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 92-A” of this prospectus supplement, oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Developmental Drilling Fund 92-A. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Developmental Drilling Fund 92-A has reserves which are classified as proved developed producing. All of the proved reserves are included in the engineering reports which evaluate Developmental Drilling Fund 92-A’s present reserves.

Market for Developmental Drilling Fund 92-A’s Limited Partnership Interests and Related Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Developmental Drilling Fund 92-A should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas, plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. As of December 31, 2001, no units of limited partner interest were purchased by the managing general partner. In 2000, 5 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $181.86 per unit. As of December 31, 1999, no units of limited partner interest were purchased by the managing general partner. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 105 holders of limited partner interest.

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Distributions

Pursuant to Article IV, Section 4.01 of Developmental Drilling Fund 92-A’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Developmental Drilling Fund 92-A’s] drilling activities, less (i) general and administrative costs, (ii) operating costs, and (iii) any reserves necessary to meet current and anticipated needs of [Developmental Drilling Fund 92-A], including, but not limited to, drilling cost overruns, as determined in the sole discretion of the managing general partner.”

During 2001, quarterly distributions were made totaling $208,798, with $185,830 distributed to the limited partners and $22,968 to the managing general partners. For the year ended December 31, 2001, distributions of $132.08 per unit of limited partner interest were made, based upon 1,407 units of limited partner interest outstanding. During 2000, quarterly distributions were made totaling $224,640, with $199,930 distributed to the limited partners and $24,710 to the managing general partners. For the year ended December 31, 2000, distributions of $142.10 per unit of limited partner interest were made, based upon 1,407 units of limited partner interest outstanding. During 1999, distributions were made totaling $85,000, with $75,650 distributed to the limited partners and $9,350 to the managing general partners. For the year ended December 31, 1999, distributions of $53.77 per unit of limited partner interest were made, based upon 1,407 units of limited partner interest outstanding.

10

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA  FOR DEVELOPMENTAL DRILLING FUND 92-A

The following tables present summary selected financial information and operating data for Developmental Drilling Fund 92-A for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 92-A” found elsewhere in this prospectus supplement and the financial statements and related notes for Developmental Drilling Fund 92-A included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe), Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	124,415		200,270		332,643		371,824		249,636		200,761		334,355
Net income (loss)	53,575		107,590		160,893		217,640		112,767		(331,847	)	93,437
Partners’ share of net income (loss):
Managing general partners	6,663		13,155		20,338		25,590		14,274		6,863		19,601
Investor partners	46,912		94,435		140,555		192,050		98,493		(338,710	)	73,836
Investor partners’ net income (loss) per unit of limited partner interest	33.34		67.12		99.90		136.50		70.00		(240.73	)	52.48
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	61,318		123,079		196,969		228,837		100,331		90,913		195,379
Net cash provided by investing activities	—		—		1,393		(75	)	(20	)	930		180
Net cash used in financing activities	(59,984	)	(130,000	)	(208,719	)	(224,640	)	(85,080	)	(92,218	)	(205,402	)
Net increase (decrease) in cash and cash equivalents	1,334		(6,921	)	(10,357	)	4,122		15,231		(375	)	(9,843	)
EBITDA	60,575		119,590		184,893		232,640		129,767		62,393		178,193
Cash distributions	60,000		130,000		208,798		224,640		85,000		92,200		205,500
Investor partners’ cash distributions per $500 investment	18.98		41.12		66.04		71.05		26.88		29.16		64.99
Balance Sheet Data:
Cash and cash equivalents	17,842		19,944		16,508		26,865		22,743		7,512		7,887
Oil and gas properties, net at book value	178,884		199,277		185,884		211,277		226,202		243,182		638,352
Total assets	224,960		256,785		231,369		279,195		286,195		258,508		682,573
Total liabilities	95		—		79		—		—		80		98

11

	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Investor partners’ equity	196,878	227,376	203,366	248,641	256,521	233,678	654,446
Managing general partners’ equity	27,987	29,409	27,924	30,554	29,674	24,750	28,029
Investor partner’s book value per $500 investment	69.97	80.80	72.27	88.36	91.16	83.04	232.57
Production:
Oil production (Bbls)	4,390	4,910	9,460	9,800	10,770	11,700	12,700
Natural gas production (Mcf)	10,600	11,800	23,000	20,200	24,940	26,800	30,000
Equivalent production (Boe)	6,157	6,877	13,293	13,167	14,927	16,167	17,700
Average Sales Price:
Oil price (per/Bbl)	22.02	27.68	25.25	29.73	17.74	12.75	20.06
Natural gas price (per/Mcf)	2.62	5.45	4.08	3.98	2.35	1.93	2.65
Average sales price (per Boe)	20.21	29.12	25.02	28.24	16.72	12.42	18.89
Operating and Overhead Costs (per Boe)
Lease operating expense	7.82	8.74	8.39	7.78	5.96	6.35	6.80
Production taxes	1.19	1.84	1.52	1.64	.92	.74	1.07
General and Administrative Expense (per Boe)	1.37	1.21	1.24	1.21	1.17	1.50	1.04
Total	10.38	11.79	11.15	10.63	8.05	8.59	8.91
Cash Operating Margin (per Boe)	9.83	17.33	13.87	17.61	8.67	3.83	9.98
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.14	1.74	1.81	1.14	1.14	24.39	4.79
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	293,000	260,000	245,000	242,000	309,000	168,000	288,000
Oil (Bbls)	94,000	100,000	79,000	110,000	109,000	76,000	118,000
Total (Boe)	143,000	143,000	120,000	150,000	161,000	104,000	166,000

⁽¹⁾ Developmental Drilling Fund 92-A has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$810,000
Merger Value per $500 investment	$256.10

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION  AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 92-A

General

Based on current conditions, management anticipates performing no workovers to enhance production. Developmental Drilling Fund 92-A will likely experience the historical production decline of approximately 6% per year from the prior year’s production.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.91	$	27.20	(12	%)
Average price per Mcf of gas	$	3.05	$	4.48	(32	%)
Oil production in barrels		2,290		2,570	(11	%)
Gas production in Mcf		5,300		4,700	13	%
Gross oil and gas revenue	$	70,916	$	75,451	(6	%)
Net oil and gas revenue	$	45,037	$	34,787	29	%
Developmental Drilling Fund 92-A distributions	$	30,000	$	50,000	(40	%)
Limited partner distributions	$	26,700	$	44,500	(40	%)
Per unit distribution to limited partners	$	18.98	$	31.63	(40	%)
Number of limited partner interests		1,407		1,407

Revenues

Developmental Drilling Fund 92-A’s oil and gas revenues decreased to $70,916 from $75,451 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 6%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 92-A decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 12%, or $3.29 per barrel, resulting in a decrease of approximately $7,500 in revenues. Oil sales represented 77% of total oil and gas sales during the quarter ended June 30, 2002 and 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 92-A decreased during the same period by 32%, or $1.43 per Mcf, resulting in a decrease of approximately $7,600 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $15,100. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 280 barrels, or 11%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $7,600 in revenues.

Gas production increased approximately 600 Mcf, or 13%, during the same period, resulting in an increase of approximately $2,700 in revenues.

The net total decrease in revenues due to the change in production is approximately $4,900.

13

Costs and Expenses

Total costs and expenses decreased to $34,294 from $50,019 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 31%. The decrease is primarily the result of lower lease operating costs and depletion expense, partially offset by an increase in general and administrative expenses.

1.  Lease operating costs and production taxes were 36% lower, or approximately $14,800 less during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in lease operating expense is due to maintenance and repairs being performed in 2001, and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $60, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $4,000 for the quarter ended June 30, 2002 from $5,000 for the same period in 2001. This represents a decrease of 20%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 92-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 92-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.02	$	27.68	(20	%)
Average price per Mcf of gas	$	2.62	$	5.45	(52	%)
Oil production in barrels		4,390		4,910	(11	%)
Gas production in Mcf		10,600		11,800	(10	%)
Gross oil and gas revenue	$	124,415	$	200,270	(38	%)
Net oil and gas revenue	$	68,965	$	127,535	(46	%)
Developmental Drilling Fund 92-A distributions	$	60,000	$	130,000	(54	%)
Limited partner distributions	$	53,400	$	115,700	(54	%)
Per unit distribution to limited partners	$	37.95	$	82.23	(54	%)
Number of limited partner interests		1,407		1,407

Revenues

Developmental Drilling Fund 92-A’s oil and gas revenues decreased to $124,415 from $200,270 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 38%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 92-A decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 20%, or $5.66 per barrel, resulting in a decrease of approximately $24,800 in revenues. Oil sales represented 78% of the total oil and gas sales during the six months ended June 30, 2002 as compared to 68% during the six months ended June 30, 2001.

14

The average price for an Mcf of gas received by Developmental Drilling Fund 92-A decreased during the same period by 52%, or $2.83 per Mcf, resulting in a decrease of approximately $30,000 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $54,800. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 520 barrels, or 11%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $14,400 in revenues.

Gas production decreased approximately 1,200 Mcf, or 10%, during the same period, resulting in a decrease of approximately $6,500 in revenues.

The total decrease in revenues due to the change in production is approximately $20,900.

Costs and Expenses

Total costs and expenses decreased to $70,877 from $93,033 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 24%. The decrease is primarily the result of lower lease operating costs and depletion expense, partially offset by an increase in general and administrative expense.

1.  Lease operating costs and production taxes decreased 24%, or approximately $17,300, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001. The decrease in lease operating expense is due to maintenance and repairs being performed in 2001, and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $7,000 for the six months ended June 30, 2002, from $12,000 for the same period in 2001. This represents a decrease of 42%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 92-A’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. The contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 92-A during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	25.25	$	29.73	(15	%)
Average price per Mcf of gas	$	4.08	$	3.98	3	%
Oil production in barrels		9,460		9,800	(3	%)
Gas production in Mcf		23,000		20,200	14	%
Gross oil and gas revenue	$	332,643	$	371,824	(11	%)
Net oil and gas revenue	$	200,862	$	247,853	(19	%)
Developmental Drilling Fund 92-A distributions	$	208,798	$	224,640	(7	%)
Limited partner distributions	$	185,830	$	199,930	(7	%)
Per unit distribution to limited partners	$	132.08	$	142.10	(7	%)
Number of limited partner interests		1,407		1,407

15

Revenues

Developmental Drilling Fund 92-A’s oil and gas revenues decreased to $332,643 from $371,824 for the years ended December 31, 2001 and 2000, respectively, a decrease of 11%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 92-A decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 15%, or $4.48 per barrel, resulting in a decrease of approximately $42,400 in revenues. Oil sales represented 72% of total oil and gas sales during the year ended December 31, 2001 as compared to 78% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Developmental Drilling Fund 92-A increased during the same period by 3%, or $.10 per Mcf, resulting in an increase of approximately $2,300 in revenues.

The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $40,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 340 barrels, or 3%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $10,100 in revenues.

Gas production increased approximately 2,800 Mcf, or 14%, during the same period, resulting in an increase of approximately $11,100 in revenues.

The net total increase in revenues due to the change in production is approximately $1,000.

Costs and Expenses

Total costs and expenses increased to $172,299 from $154,913 for the years ended December 31, 2001 and 2000, respectively, an increase of 11%. The increase is the result of higher lease operating costs, depletion expense and general and administrative expense.

1.  Lease operating costs and production taxes increased 6%, or approximately $7,800, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 4%, or approximately $600, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $24,000 for the year ended December 31, 2001 from $15,000 for the same period in 2000. This represents an increase of 60%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 92-A’s independent petroleum consultants.

The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Developmental Drilling Fund 92-A’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Developmental Drilling Fund 92-A during 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $6,000 as of December 31, 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	29.73	$	17.74	68	%
Average price per Mcf of gas	$	3.98	$	2.35	69	%
Oil production in barrels		9,800		10,770	(9	%)
Gas production in Mcf		20,200		24,940	(19	%)
Gross oil and gas revenue	$	371,824	$	249,636	49	%
Net oil and gas revenue	$	247,853	$	146,852	69	%
Developmental Drilling Fund 92-A distributions	$	224,640	$	85,000	164	%
Limited partner distributions	$	199,930	$	75,650	164	%
Per unit distribution to limited partners	$	142.10	$	53.77	164	%
Number of limited partner interests		1,407		1,407

Revenues

Developmental Drilling Fund 92-A’s oil and gas revenues increased to $371,824 from $249,636 for the years ended December 31, 2000 and 1999, respectively, an increase of 49%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 92-A increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 68%, or $11.99 per barrel, resulting in an increase of approximately $117,500 in revenues. Oil sales represented 78% of total oil and gas sales during the year ended December 31, 2000 as compared to 77% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Developmental Drilling Fund 92-A increased during the same period by 69%, or $1.63 per Mcf, resulting in an increase of approximately $32,900 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $150,400. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 970 barrels, or 9%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $17,200 in revenues.

Gas production decreased approximately 4,470 Mcf, or 19%, during the same period, resulting in a decrease of approximately $11,100 in revenues.

The total decrease in revenues due to the change in production is approximately $28,300.

Costs and Expenses

Total costs and expenses increased to $154,913 from $137,198 for the years ended December 31, 2000 and 1999, respectively, an increase of 13%. The increase is the result of higher lease operating costs, partially offset by a decrease in depletion expense and general and administrative expense.

1.  Lease operating costs and production taxes increased 21%, or approximately $21,200, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating

17

costs and production taxes is due in part to an increase in major repairs and maintenance, such as overhead and electrical repairs on two leases, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Developmental Drilling Fund 92-A to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 8%, or approximately $1,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $15,000 for the year ended December 31, 2000 from $17,000 for the same period in 1999. This represents a decrease of 12%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 92-A’s independent petroleum consultants.

The major factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Developmental Drilling Fund 92-A’s reserves for January 1, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $3,000 as of December 31, 1999.

Revenue and Distribution Comparison

Developmental Drilling Fund 92-A’s net income for the years ended December 31, 2001, 2000 and 1999 was $160,893, $217,640 and $112,767, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999, would have been $184,893, $232,640 and $129,767, respectively. Correspondingly, Developmental Drilling Fund 92-A’s distributions for the years ended December 31, 2001, 2000 and 1999 were $208,798, $224,640 and $85,000, respectively. These differences are indicative of the changes in oil and gas prices, production and property during 2001, 2000 and 1999.

The sources for the 2001 distributions of $208,798 were oil and gas operations of approximately $197,000 and the change in oil and gas properties of approximately $1,400, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $224,640 were oil and gas operations of approximately $228,800 and the change in oil and gas properties of approximately $(75), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $85,000 were oil and gas operations of approximately $100,300 and the change in oil and gas properties of approximately $(20), resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $208,798 of which $185,830 was distributed to the investor partners and $22,968 to the managing general partners. The per unit distribution to investor partners during the same period was $132.08. Total distributions during the year ended December 31, 2000 were $224,640 of which $199,930 was distributed to the investor partners and $24,710 to the managing general partners. The per unit distribution to investor partners during the same period was $142.10. Total distributions during the year ended December 31, 1999 were $85,000 of which $75,650 was distributed to the investor partners and $9,350 to the managing general partners. The per unit distribution to investor partners during the same period was $53.77.

Liquidity and Capital Resources of Developmental Drilling Fund 92-A

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Developmental Drilling Fund 92-A knows of no material change, nor does it anticipate any such change.

18

Cash flows provided by operating activities were approximately $61,300 in the six months ended June 30, 2002 as compared to approximately $123,100 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was profitable operations.

Cash flows used in financing activities were $60,000 in the six months ended June 30, 2002 as compared to $130,000 in the six months ended June 30, 2001. The only use in financing activities was the distributions to partners.

Total distributions during the six months ended June 30, 2002 were $60,000 of which $53,400 was distributed to the investor partners and $6,600 to the managing general partner. The per unit distribution to investor partners during the six months ended June 30, 2002 was $37.95. Total distributions during the six months ended June 30, 2001 were $130,000 of which $115,700 was distributed to the investor partners and $14,300 to the managing general partner. The per unit distribution to investor partners during the six months ended June 30, 2001 was $82.23.

The source for the 2002 distributions of $60,000 was oil and gas operations of approximately $61,300, resulting in excess cash for contingencies or subsequent distributions. The source for the 2001 distributions of $130,000 was oil and gas operations of approximately $123,100, with the balance from available cash on hand at the beginning of the period.

Since inception of Developmental Drilling Fund 92-A, cumulative monthly cash distributions of $1,646,353 have been made to the partners. As of June 30, 2002, $1,465,630 or $1,041.67 per investor partner unit has been distributed to the investor partners, representing a 104% return of the capital contributed.

As of June 30, 2002, Developmental Drilling Fund 92-A had approximately $46,000 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Developmental Drilling Fund 92-A.

Cash flows provided by operating activities were approximately $197,000 in 2001 compared to $228,800 in 2000 and approximately $100,300 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows provided by (used in) investing activities were approximately $1,400 in 2001 compared to $(75) in 2000 and approximately $(20) in 1999. The principal source of the 2001 cash flow from investing activities was the sale of equipment.

Cash flows used in financing activities were approximately $208,700 in 2001 compared to $224,600 in 2000 and approximately $85,100 in 1999. The only use in the 2001 financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1993, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Developmental Drilling Fund 1993, L.P., which we call Developmental Drilling Fund 1993, and supplements the prospectus/proxy statement dated                     , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of partners of Developmental Drilling Fund 1993. The purpose of the special meeting is for you to vote upon the merger of Developmental Drilling Fund 1993 with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Developmental Drilling Fund 1993 is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Developmental Drilling Fund 1993:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Developmental Drilling Fund 1993

• Compensation and distributions from Developmental Drilling Fund 1993

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to limited partnership interests of partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Developmental Drilling Fund 1993 for the five years ended December 31, 2000 and for the six months ended June 30, 2002 and 2001

• Developmental Drilling Fund 1993’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Developmental Drilling Fund 1993 as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Developmental Drilling Fund 1993, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Developmental Drilling Fund 1993 in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you the at the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Developmental Drilling Fund 1993’s assets. The Merger Value of Developmental Drilling Fund 1993 is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Developmental Drilling Fund 1993, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

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The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Developmental Drilling Fund 1993 by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Developmental Drilling Fund 1993. We believe, however, that Developmental Drilling Fund 1993 will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Developmental Drilling Fund 1993. Our decision is based on the following factors in order of significance:

• Our method of valuation for Developmental Drilling Fund 1993 uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Developmental Drilling Fund 1993, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Developmental Drilling Fund 1993. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR DEVELOPMENTAL DRILLING FUND 1993

The Merger Value for Developmental Drilling Fund 1993 was determined by calculating its Net Asset Value and then dividing Developmental Drilling Fund 1993’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Developmental Drilling Fund 1993’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Developmental Drilling Fund 1993’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Developmental Drilling Fund 1993. As indicated below, the number of shares of common stock issuable per unit of limited partner interest in Developmental Drilling Fund 1993 is 12.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Developmental Drilling Fund 1993
		Net Present Value of Reserves	$	1,185,850.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	77,083.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Developmental Drilling Fund 1993	$	1,262,933.00	calculated

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					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Developmental Drilling Fund 1993	$	1,262,933.00	calculated
	less	GP% owned by Southwest in Developmental Drilling Fund 1993 (11%)	$	138,922.63	Partnership records
	less	LP% owned by Southwest in Developmental Drilling Fund 1993 (0.13%)	$	1,641.81	Partnership records
	equals	Net Asset Value of Developmental Drilling Fund 1993 owned by limited partners (excluding Southwest’s ownership %)	$	1,122,368.56	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners Developmental Drilling Fund 1993 (excluding Southwest’s ownership %)	$	1,122,368.56	calculated
	equals	The percentage of ownership of Developmental Drilling Fund 1993 (other than Southwest) to the total Net Asset Value		1.43%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Developmental Drilling Fund 1993 (other than Southwest)		1.43%	calculated
	equals	The number of shares of common stock attributable to Developmental Drilling Fund 1993 (other than to Southwest)		24,139.35	calculated
(7)		The number of shares of common stock attributable to Developmental Drilling Fund 1993 (other than to Southwest)		24,139	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 1993		2,075	Partnership records
	equals	The number of shares of common stock issuable per each units of limited partner interest in Developmental Drilling Fund 1993		12	calculated

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				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Developmental Drilling Fund 1993 (other than to Southwest)	4,828	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 1993	2,075	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Developmental Drilling Fund 1993	2.33	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

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COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Developmental Drilling Fund 1993 for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	12,000	$	12,000	$	12,000	$	6,000
Administrative Overhead per Operating Agreements	$	26,705	$	25,721	$	25,335	$	13,523
Cash Distributions Paid to General Partner as General Partner	$	36,514	$	38,096	$	15,730	$	11,000
Cash Distributions Paid to General Partner as Limited Partner	$	257	$	—	$	—	$	129

Set forth below is a table showing the cash distributions to Developmental Drilling Fund 1993’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	295,435	$	308,227	$	127,270	$	132,165	$	256,320	$	89,000
Return of Capital: 100%; Return on Capital: 5%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR DEVELOPMENTAL DRILLING FUND 1993

Aggregate Initial Investment by the Limited Partners:	$	2,078	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	2,179	(1)
Aggregate Merger Value Attributable to Limited Partnership Interests of Limited Partners, Including Southwest:	$	1,124	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	270.45	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		5.3	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	144.58	(2)(4)
—as of December 31, 2001:	$	149.48	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	185.11	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	166.21	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:	$	229.22	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

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⁽³⁾ The Merger Value for Developmental Drilling Fund 1993 is equal to (1) the sum of (A) the present value of estimated future net revenues from Developmental Drilling Fund 1993’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Developmental Drilling Fund 1993 is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Developmental Drilling Fund 1993 is based upon (1) the sum of (A) the estimated net cash flow from the sale of Developmental Drilling Fund 1993’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Developmental Drilling Fund 1993’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the  12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Developmental Drilling Fund 1993 is based upon (1) the sum of (A) the sale of Developmental Drilling Fund 1993’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Developmental Drilling Fund 1993’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Developmental Drilling Fund 1993 and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ The final presentment value for Developmental Drilling Fund 1993 is based upon (1) the sum of (A) Developmental Drilling Fund 1993’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) +1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate +1% and the 33% discount are as indicated in the limited partnership agreement for Developmental Drilling Fund 1993.

DEVELOPMENTAL DRILLING FUND 1993

Set forth below is basic information about Developmental Drilling Fund 1993 and its business and operations. It does not contain all the information about Developmental Drilling Fund 1993 that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Developmental Drilling Fund 1993

General

Developmental Drilling Fund 1993 was organized as a Delaware limited partnership on August 27, 1993. The offering of limited partner and general partner interests began September 30, 1993, reached minimum capital requirements on December 22, 1993 and concluded December 27, 1993. Developmental Drilling Fund 1993 has no subsidiaries. Total limited partner contributions were $2,078,000. The managing general partner contributions was $195,999. Total contributions were $1,930,999.

Principal Products, Marketing and Distribution

Developmental Drilling Fund 1993 has acquired leasehold interests and drilled oil and gas properties located in Texas and New Mexico.

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Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	75%	25%
2000	78%	22%
1999	78%	22%

As the table indicates, the majority of Developmental Drilling Fund 1993’s revenue is from its oil production.

Customer Dependence

No material portion of Developmental Drilling Fund 1993’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Developmental Drilling Fund 1993. Three purchasers accounted for 98% of Developmental Drilling Fund 1993’s total oil and gas production during 2001: Navajo Refining Company for 49%, Plains All American Pipeline, L.P. for 25% and Duke Energy Transport and Trade for 24%. Four purchasers accounted for 99% of Developmental Drilling Fund 1993’s total oil and gas production during 2000: Phillips Petroleum Company for 38%, Plains All American Pipeline, L.P. for 25%, Navajo Refining Company for 24%, and Duke Energy Transport and Trade for 13%. Three purchasers accounted for 91% of Developmental Drilling Fund 1993’s total oil and gas production during 1999: Phillips Petroleum Company for 54% and Scurlock Permian LLC for 25% and Duke Energy Transport and Trade for 12%. All purchasers of Developmental Drilling Fund 1993’s oil and gas production are unrelated third parties. In the event these purchasers were to discontinue purchasing Developmental Drilling Fund 1993’s production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Developmental Drilling Fund 1993’s total oil and gas production.

Properties

As of December 31, 2001, Developmental Drilling Fund 1993 possessed an interest in oil and gas properties located in Lea County, New Mexico and Ward County, Texas. These properties consist of various interests in 7 wells.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

Significant Properties

The following table reflects the significant properties in which Developmental Drilling Fund 1993 has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Mobil Fee I Ward County, Texas	12/93 100% working interest	1	51,000	195,000
Phillips Wyatt Fed #14 Lea County, New Mexico	12/93 100% working interest	1	35,000	18,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Developmental Drilling Fund 1993’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed reserves (PDP) only.

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Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $17.84 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.48 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 1993,” oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Developmental Drilling Fund 1993. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Developmental Drilling Fund 1993 has reserves, which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate Developmental Drilling Fund 1993’s present reserves.

Market Information for Developmental Drilling Fund 1993’s Partnerships Interests and Related Partnership Matters

Market Information

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Developmental Drilling Fund 1993 should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank of Texas, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. In 2001, 3 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $406.90 per unit. In 2000 and 1999, no units of limited partner interest were purchased by the managing general partner. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 102 holders of limited partner interest in Developmental Drilling Fund 1993.

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Distributions

Pursuant to Article IV, Section 4.01 of Developmental Drilling Fund 1993’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Developmental Drilling Fund 1993’s] drilling activities, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of [Developmental Drilling Fund 1993,] including, but not limited to, drilling cost overruns, as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $331,949, with $295,435 distributed to the investor partners and $36,514 to the managing general partner. For the year ended December 31, 2001, distributions of $142.17 per investor partner unit were made, based upon 2,078 investor partner units outstanding. During 2000, distributions were made totaling $346,323, with $308,227 distributed to the investor partners and $38,096 to the managing general partner. For the year ended December 31, 2000, distributions of $148.33 per investor partner unit were made based upon 2,078 investor partner units outstanding. During 1999, distributions were made totaling $143,000, with $127,270 distributed to the investor partners and $15,730 to the managing general partner. For the year ended December 31, 1999, distributions of $61.25 per investor partner unit were made, based upon 2,078 investor partner units outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

DEVELOPMENTAL DRILLING FUND 1993

The following tables present summary selected financial information and operating data for Developmental Drilling Fund 1993 for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 1993” found elsewhere in this prospectus supplement and the financial statements and related notes for Developmental Drilling Fund 1993 included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Balance Sheet Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expenses (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002, are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	185,651		252,671		442,640		563,680		367,811		334,658		466,810
Net income (loss)	79,711		140,448		211,868		336,155		178,865		(359,655	)	132,098
Partners’ share of net income (loss):
Managing general partner	11,068		18,449		30,305		41,077		24,013		13,602		27,545
Investor partners	68,643		121,999		181,563		295,078		154,852		(373,257	)	104,553
Investor partners’ net income (loss) per unit of limited partner interest	33.03		58.71		87.37		142.00		74.52		(179.62	)	50.31
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	74,826		173,263		315,010		368,946		180,161		163,986		313,795
Net cash provided by investing activities	—		—		—		(2,432	)	(2,588	)	(17,420	)	(28,171	)
Net cash used in financing activities	(100,000	)	(195,000	)	(331,949	)	(346,152	)	(143,000	)	(148,671	)	(288,000	)
Net increase (decrease) in cash and cash equivalents	(25,174	)	(21,737	)	(16,939	)	20,362		34,573		(2,105	)	(2,376	)
EBITDA	102,711		170,448		281,868		377,155		222,213		171,556		261,778
Cash distributions	100,000		195,000		331,949		346,323		143,000		148,500		288,000
Investor partners’ cash distributions per $500 investment	21.42		41.76		71.09		74.16		30.62		31.80		61.67

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	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Balance Sheet Data:
Cash and cash equivalents	19,523	39,899	44,697	61,636	41,274	6,701	8,806
Oil and gas properties, net at book value	551,690	614,690	574,690	644,690	683,258	723,670	1,233,171
Total assets	628,773	714,591	649,062	769,143	779,311	743,446	1,251,601
Total liabilities	—	—	—	—	—	—	—
Investor partners’ equity	600,871	683,549	621,228	735,100	748,249	720,667	1,226,090
Managing general partners’ equity	27,902	31,042	27,834	34,043	31,062	22,779	25,511
Investor partner’s book value per $500 investment	144.58	164.47	149.48	176.88	180.04	173.41	295.02
Production:
Oil production (Bbls)	7,300	7,180	14,500	15,500	17,120	22,700	20,400
Natural gas production (Mcf)	11,500	13,150	26,000	30,700	32,530	31,900	30,600
Equivalent production (Boe)	9,217	9,372	18,833	20,617	22,542	28,017	25,500
Average Sales Price:
Oil price (per/Bbl)	21.24	25.27	23.02	28.28	16.74	11.82	18.72
Natural gas price (per/Mcf)	2.66	5.42	4.18	4.08	2.50	2.08	2.77
Average sales price (per Boe)	20.14	26.96	23.50	27.34	16.32	11.94	18.30
Operating and Overhead Costs (per Boe)
Lease operating expense	6.56	5.90	5.97	6.32	4.54	4.12	6.10
Production taxes	1.55	2.07	1.76	2.01	1.18	.92	1.31
General and Administrative Expense (per Boe)	.89	.87	.85	.77	.78	.83	.73
Total	9.00	8.84	8.58	9.10	6.50	5.87	8.14
Cash Operating Margin (per Boe)	11.14	18.12	14.92	18.24	9.82	6.07	10.16
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	2.50	3.20	3.72	1.99	1.93	18.96	5.09
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	284,000	297,000	275,000	420,000	589,000	378,000	306,000
Oil (Bbls)	154,000	178,000	133,000	185,000	191,000	183,000	206,000
Total (Boe)	201,000	228,000	179,000	255,000	289,000	246,000	257,000

⁽¹⁾ Developmental Drilling Fund 1993 has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	1,263,000
Merger Value per $500 investment	$	270.45

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

12

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS OF DEVELOPMENTAL DRILLING FUND 1993

General

Developmental Drilling Fund 1993 was formed to engage primarily in the business of drilling developmental wells, to produce and market crude oil and natural gas produced from such properties, to distribute any net proceeds from operations to the general and partners and to the extent necessary, acquire leases which contain drilling prospects. Net revenues will not be reinvested in other revenue producing assets except to the extent that performance of remedial work is needed to improve a well’s producing capabilities. The economic life of Developmental Drilling Fund 1993 thus depends on the period over which Developmental Drilling Fund 1993’s oil and gas reserves are economically recoverable.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	23.36	$	24.85	(6	%)
Average price per Mcf of gas	$	3.04	$	4.29	(29	%)
Oil production in barrels		3,960		3,940	1	%
Gas production in Mcf		6,500		6,150	6	%
Gross oil and gas revenue	$	112,273	$	97,300	15	%
Net oil and gas revenue	$	76,239	$	58,151	31	%
Developmental Drilling Fund 1993 distributions	$	50,000	$	75,000	(33	%)
Limited Partner distributions	$	44,500	$	66,750	(33	%)
Number of limited partner interests		2,078		2,078

Revenues

Developmental Drilling Fund 1993’s oil and gas revenues increased to $112,273 from $97,300 for the quarters ended June 30, 2002 and 2001, respectively, an increase of 15%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1993 decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 6%, or $1.49 per barrel, resulting in a decrease of approximately $5,900 in revenues. Oil sales represented 82% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 79% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 1993 decreased during the same period by 29%, or $1.25 per Mcf, resulting in a decrease of approximately $8,100 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $14,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production increased approximately 20 barrels, or 1%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in an increase of approximately $500 in revenues.

Gas production increased approximately 350 Mcf, or 6%, during the same period, resulting in an increase of approximately $1,500 in revenues.

The total increase in revenues due to the change in production is approximately $2,000.

13

Costs and Expenses

Total costs and expenses decreased to $54,125 from $57,321 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 6%. The decrease is the result of lower lease operating costs and general and administrative expense.

1.  Lease operating costs and production taxes decreased 8%, or approximately $3,100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense remained the same for the quarter ended June 30, 2002, from the same period in 2001. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1993’s independent petroleum consultants and updated by Southwest’s internal staff of engineers.

Results of Operations—Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	21.24	$	25.27	(16	%)
Average price per Mcf of gas	$	2.66	$	5.42	(51	%)
Oil production in barrels		7,300		7,180	2	%
Gas production in Mcf		11,500		13,150	(13	%)
Gross oil and gas revenue	$	185,651	$	252,671	(27	%)
Net oil and gas revenue	$	110,905	$	178,014	(38	%)
Developmental Drilling Fund 1993 distributions	$	100,000	$	195,000	(49	%)
Limited Partner distributions	$	89,000	$	173,550	(49	%)
Number of limited partner interests		2,078		2,078

Revenues

Developmental Drilling Fund 1993’s oil and gas revenues decreased to $185,651 from $252,671 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 27%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1993 decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 16%, or $4.03 per barrel, resulting in a decrease of approximately $29,400 in revenues. Oil sales represented 84% of total oil and gas sales during the six months ended June 30, 2002 as compared to 72% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 1993 decreased during the same period by 51%, or $2.76 per Mcf, resulting in a decrease of approximately $31,700 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $61,100. The market price for oil and gas has been extremely volatile over the past decade, and management expects a certain amount of volatility to continue in the foreseeable future.

14

2.  Oil production increased approximately 100 barrels, or 2%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in an increase of approximately $3,000 in revenues.

Gas production decreased approximately 1,650 Mcf, or 13%, during the same period, resulting in a decrease of approximately $8,900 in revenues.

The net total decrease in revenues due to the change in production is approximately $5,900.

Costs and Expenses

Total costs and expenses decreased to $105,987 from $112,772 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 6%. The decrease is the result of lower depletion expense, partially offset by an increase in lease operating costs and general and administrative expense.

1.  Lease operating costs and production taxes increased less than 1%, or approximately $100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $100, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $23,000 for the six months ended June 30, 2002 from $30,000 for the same period in 2001. This represents a decrease of 23%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1993’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. A contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 1993 during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	23.02	$	28.28	(19	%)
Average price per Mcf of gas	$	4.18	$	4.08	2	%
Oil production in barrels		14,500		15,500	(6	%)
Gas production in Mcf		26,000		30,700	(15	%)
Gross oil and gas revenue	$	442,640	$	563,680	(21	%)
Net oil and gas revenue	$	297,040	$	391,934	(24	%)
Developmental Drilling Fund 1993 distributions	$	331,949	$	346,323	(4	%)
Limited partner distributions	$	295,435	$	308,227	(4	%)
Per unit distribution to limited partners	$	142.17	$	148.33	(4	%)
Number of limited partner interests		2,078		2,078

Revenues

Developmental Drilling Fund 1993’s oil and gas revenues decreased to $442,640 from $563,680 for the years ended December 31, 2001 and 2000, respectively, a decrease of 21%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

15

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1993 decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 19%, or $5.26 per barrel, resulting in a decrease of approximately $76,300 in revenues. Oil sales represented 75% of total oil and gas sales during the year ended December 31, 2001. Oil sales represented 78% of total oil and gas sales during the year ended December 31, 2000.

The average price for an Mcf of gas received by Developmental Drilling Fund 1993 increased during the same period by 2%, or $.10 per Mcf, resulting in an increase of approximately $2,600 in revenues.

The total net decrease in revenues due to the change in prices received from oil and gas production is approximately $73,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,000 barrels, or 6%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $28,300 in revenues.

Gas production decreased approximately 4,700 Mcf, or 15%, during the same period, resulting in a decrease of approximately $19,200 in revenues.

The total decrease in revenues due to the change in production is approximately $47,500.

Costs and Expenses

Total costs and expenses increased to $231,628 from $228,640 for the years ended December 31, 2001 and 2000, respectively, an increase of 1%. The increase is the result of higher depletion expense and general and administrative costs, partially offset by a decrease in lease operating costs.

1.  Lease operating costs and production taxes decreased 15%, or approximately $26,100, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $100, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $70,000 for the year ended December 31, 2001 from $41,000 for the same period in 2000. This represents an increase of 71%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1993’s independent petroleum consultants. The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Developmental Drilling Fund 1993’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Developmental Drilling Fund 1993 during 2001 as compared to 2000.

16

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percent Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.28	$	16.74	69	%
Average price per Mcf of gas	$	4.08	$	2.50	63	%
Oil production in barrels		15,500		17,120	(9	%)
Gas production in Mcf		30,700		32,530	(6	%)
Gross oil and gas revenue	$	563,680	$	367,811	53	%
Net oil and gas revenue	$	391,934	$	238,854	64	%
Developmental Drilling Fund 1993 distributions	$	346,323	$	143,000	142	%
Limited partner distributions	$	308,227	$	127,270	142	%
Per unit distribution to limited partners	$	148.33	$	61.25	142	%
Number of limited partner interests		2,078		2,078

Revenues

Developmental Drilling Fund 1993’s oil and gas revenues increased to $563,680 from $367,811 for the years ended December 31, 2000 and 1999, respectively, an increase of 53%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1993 increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 69%, or $11.54 per barrel, resulting in an increase of approximately $178,900 in revenues. Oil sales represented 78% of total oil and gas sales during the year ended December 31, 2000 and 1999.

The average price for an Mcf of gas received by Developmental Drilling Fund 1993 increased during the same period by 63%, or $1.58 per Mcf, resulting in an increase of approximately $48,500 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $227,400. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,620 barrels, or 9%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $27,100 in revenues.

Gas production decreased approximately 1,830 Mcf, or 6%, during the same period, resulting in a decrease of approximately $4,600 in revenues.

The total net decrease in revenues due to the change in production is approximately $31,700.

Costs and Expenses

Total costs and expenses increased to $228,640 from $189,561 for the years ended December 31, 2000 and 1999, respectively, an increase of 21%. The increase is the result of higher lease operating costs partially offset by a decrease in depletion expense and general and administrative costs.

1.  Lease operating costs and production taxes increased 33%, or approximately $42,800, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as pulling expense on one lease, and in part to the rise in production taxes directly associated with the rise in oil and gas prices

17

received during the past year. The rise in oil and gas prices for 2000 has allowed Developmental Drilling Fund 1993 to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 8%, or approximately $1,400, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $41,000 for the year ended December 31, 2000 from $43,000 for the same period in 1999. This represents a decrease of 5%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1993’s independent petroleum consultants.

Revenue and Distribution Comparison

Developmental Drilling Fund 1993’s net income for the years ended December 31, 2001, 2000 and 1999 was $211,868, $336,155 and $178,865, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 was $281,868, $377,155 and $222,213, respectively. Correspondingly, Developmental Drilling Fund 1993’s distributions for the years ended December 31, 2001, 2000 and 1999 were $331,949, $346,323 and $143,000, respectively.

The sources for the 2001 distributions of $331,949 were oil and gas operations of approximately $315,000, with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $346,323 were oil and gas operations of approximately $368,900 net of the change in oil and gas properties of approximately $(2,400), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $143,000 were oil and gas operations of approximately $180,200 net of the change in oil and gas properties of approximately $(2,600), resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $331,949 of which $295,435 was distributed to the investor partners and $36,514 to the managing general partner. The per unit distribution to investor partners during the same period was $142.17. Total distributions during the year ended December 31, 2000 were $346,323 of which $308,227 was distributed to the investor partners and $38,096 to the managing general partner. The per unit distribution to investor partners during the same period was $148.33. Total distributions during the year ended December 31, 1999 were $143,000 of which $127,270 was distributed to the investor partners and $15,730 to the managing general partner. The per unit distribution to investor partners during the same period was $61.25.

Liquidity and Capital Resources of Developmental Drilling Fund 1993

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Developmental Drilling Fund 1993 knows of no material change.

Cash flows provided by operating activities were approximately $74,800 in the six months ended June 30, 2002 as compared to approximately $173,300 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was operations.

Cash flows used in financing activities were approximately $100,000 in the six months ended June 30, 2002 as compared to approximately $195,000 in the six months ended June 30, 2001. The use of the 2002 cash flow from financing activities was distributions to partners.

18

Total distributions during the six months ended June 30, 2002 were $100,000 of which $89,000 was distributed to the investor partners and $11,000 to the managing general partners. The per unit distribution to investor partners during the six months ended June 30, 2002 was $42.83. Total distributions during the six months ended June 30, 2001 were $195,000 of which $173,550 was distributed to the investor partners and $21,450 to the managing general partners. The per unit distribution to investor partners during the six months ended June 30, 2001 was $83.52.

The sources for the 2002 distributions of $100,000 were oil and gas operations of approximately $74,800, with the balance from available cash on hand at the beginning of the period. The sources for the 2001 distributions of $195,000 were oil and gas operations of approximately $173,300, with the balance from available cash on hand at the beginning of the period.

Since inception of Developmental Drilling Fund 1993, cumulative monthly cash distributions of $2,447,473 have been made to the partners. As of June 30, 2002, $2,178,603 or $1,048.41 per investor partner unit has been distributed to the investor partners, representing a 105% return of the capital contributed.

As of June 30, 2002, Developmental Drilling Fund 1993 had approximately $77,100 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Developmental Drilling Fund 1993.

Cash flows provided by operating activities were approximately $315,000 in 2001 compared to $368,900 in 2000 and $180,200 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

There were no cash flows used by investing activities in 2001 as compared to $2,400 in 2000 and $2,600 in 1999.

Cash flows used in financing activities were approximately $331,900 in 2001 compared to $346,200 in 2000 and $143,000 in 1999. The only use in the 2001 financing activities was the distributions to partners.

19

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST DEVELOPMENTAL DRILLING FUND 1994, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED             , 2002

THE DATE OF THIS SUPPLEMENT IS             , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Developmental Drilling Fund 1994, L.P., which we call Developmental Drilling Fund 1994, and supplements the prospectus/proxy statement dated             , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of Developmental Drilling Fund 1994. The purpose of the special meeting is for you to vote upon the merger of Developmental Drilling Fund 1994 with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Developmental Drilling Fund 1994 is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on             .

This document contains the following information concerning Developmental Drilling Fund 1994:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Developmental Drilling Fund 1994

• Compensation and distributions from Developmental Drilling Fund 1994

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Developmental Drilling Fund 1994 for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Developmental Drilling Fund 1994’s management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Developmental Drilling Fund 1994 as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Developmental Drilling Fund 1994, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Developmental Drilling Fund 1994 in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Developmental Drilling Fund 1994’s assets. The Merger Value of Developmental Drilling Fund 1994 is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common stock to Developmental Drilling Fund 1994, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

2

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Developmental Drilling Fund 1994 by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Developmental Drilling Fund 1994. We believe, however, that Developmental Drilling Fund 1994 will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Developmental Drilling Fund 1994. Our decision is based on the following factors in order of significance:

• Our method of valuation for Developmental Drilling Fund 1994 uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Developmental Drilling Fund 1994, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value, the liquidation value and the final presentment value of Developmental Drilling Fund 1994. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger in the prospectus/proxy statement.”

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR DEVELOPMENTAL DRILLING FUND 1994

The Merger Value for Developmental Drilling Fund 1994 was determined by calculating its Net Asset Value and then dividing Developmental Drilling Fund 1994’s Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Developmental Drilling Fund 1994’s ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Developmental Drilling Fund 1994’s limited partners. Set forth below is a table showing the calculation of the Merger Value for Developmental Drilling Fund 1994. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 1994 is 5.

					Document(s) from which information was obtained or calculated
(1)	Determine the Net Asset Value of Developmental Drilling Fund 1994
		Net Present Value of Reserves	$	553,226.00	July 1, 2002 reserve report
	plus	Net Working Capital	$	25,161.00	June 30, 2002 Financials
	less	Long-Term Debt	$	—	June 30, 2002 Financials
	plus	Additional Net Assets	$	—	June 30, 2002 Financials
	equals	Net Asset Value of Developmental Drilling Fund 1994	$	578,387.00	calculated

3

					Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Developmental Drilling Fund 1994	$	578,387.00	calculated
	less	GP% owned by Southwest in Developmental Drilling Fund 1994 (11%)	$	63,622.57	Partnership records
	less	LP% owned by Southwest in Developmental Drilling Fund 1994 (0.00%)	$	—	Partnership records
	equals	Net Asset Value of Developmental Drilling Fund 1994 owned by limited partners (excluding Southwest’s ownership %)	$	514,764.43	calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00	July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58	calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58	calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,80.42	calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00	calculated
	divided into	The Net Asset Value owned by limited partners of Developmental Drilling Fund 1994 (excluding Southwest’s ownership %)	$	514,764.43	calculated
	equals	The percentage of ownership of Developmental Drilling Fund 1994 (other than Southwest) to the total Net Asset Value		0.66%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000	June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347	calculated
(6)		Total number of shares of common stock for combined entity		1,688,347	calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Developmental Drilling Fund 1994 (other than Southwest)		0.66%	calculated
	equals	The number of shares of common stock attributable to Developmental Drilling Fund 1994 (other than to Southwest)		11,071.30	calculated
(7)		The number of shares of common stock attributable to Developmental Drilling Fund 1994 (other than to Southwest)		11,071	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Developmental Drilling Fund 1994		2,235	Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Developmental Drilling Fund 1994		5	calculated

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				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Developmental Drilling Fund 1994 (other than to Southwest)	2,214	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Developmental Drilling Fund 1994	2,235	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Developmental Drilling Fund 1994	.99	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Developmental Drilling Fund 1994 for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

	Year Ended December 31,						Six Months Ended June 30, 2002
Historical	2001		2000		1999
Management Fees per Partnership Agreement	$	24,000	$	24,000	$	24,000	$	12,000
Administrative Overhead per Operating Agreements	$	11,617	$	11,189	$	11,021	$	5,883
Cash Distributions Paid to General Partner as General Partner	$	13,787	$	16,445	$	4,290	$	3,740
Cash Distributions Paid to General Partner as Limited Partner	$	—	$	—	$	—	$	—

Set forth below is a table showing the cash distributions to Developmental Drilling Fund 1994’s limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,										Six Months Ended June 30, 2002
	2001		2000		1999		1998		1997
Cash distributions(1)	$	111,547	$	133,057	$	41,985	$	57,227	$	134,823	$	30,260
Return of Capital: 26%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a

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limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR DEVELOPMENTAL DRILLING FUND 1994

Aggregate Initial Investment by the Limited Partners:	$	2,235	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	574	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	515	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	115.16	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		8.1	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	28.42	(2)(4)
—as of December 31, 2001:	$	30.53	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	69.54	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	65.42	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002	$	93.22	(2)(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

⁽³⁾ The Merger Value for Developmental Drilling Fund 1994 is equal to (1) the sum of (A) the present value of estimated future net revenues from Developmental Drilling Fund 1994’s estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Developmental Drilling Fund 1994 is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interest sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Developmental Drilling Fund 1994 is based upon (1) the sum of (A) the estimated net cash flow from the sale of Developmental Drilling Fund 1994’s reserves during a 12-year operating period and (B) the estimated residual value from the sale of Developmental Drilling Fund 1994’s remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Developmental Drilling Fund 1994 is based upon (1) the sum of (A) the sale of Developmental Drilling Fund 1994’s reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Developmental Drilling Fund 1994’s liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Developmental Drilling Fund 1994 and the costs, including legal and otherwise, of winding down the partnership.

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⁽⁷⁾ The final presentment value for Developmental Drilling Fund 1994 is based upon (1) the sum of (A) Developmental Drilling Fund 1994’s total proved reserve value valued at a discount factor of 5.75%, which reflects Prime Rate (4.75% on September 20, 2002) + 1%, less a 33% discount, (B) its net working capital and (C) any other non-oil and gas assets, (2) less any long-term debt. The discount factor of Prime Rate + 1% and the 33% discount are as indicated in the limited partnership agreement for Developmental Drilling Fund 1994.

DEVELOPMENTAL DRILLING FUND 1994

Set forth below is basic information about Developmental Drilling Fund 1994 and its business and operations. It does not contain all the information about Developmental Drilling Fund 1994 that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Developmental Drilling Fund 1994

General

Developmental Drilling Fund 1994 was organized as a Delaware limited partnership on July 13, 1994. The offering of limited partner and general partner interests began September 1, 1994, reached minimum capital requirements on December 27, 1994 and concluded December 27, 1994, with total investor partner contributions $2,235,000. The managing general partner contribution was $19,109. Total capital contributions were $2,254,109.

Principal Products, Marketing and Distribution

Developmental Drilling Fund 1994 has acquired leasehold interests and drilled oil and gas properties located in Texas and New Mexico.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil	Gas
2001	80%	20%
2000	79%	21%
1999	80%	20%

As the table indicates, the majority of Developmental Drilling Fund 1994’s revenue is from its oil production.

Customer Dependence

No material portion of Developmental Drilling Fund 1994’s business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Developmental Drilling Fund 1994. Three purchasers accounted for 97% of Developmental Drilling Fund 1994’s total oil and gas production during 2001: Plains All American Pipeline, L.P. for 53%, Navajo Refining Company, Inc. for 28%, and Duke Energy Transport and Trade for 16%. Three purchasers accounted for 97% of Developmental Drilling Fund 1994’s total oil and gas production during 2000: Plains All American Pipeline, L.P. for 50%, Navajo Refining Company, Inc. for 29% and Duke Energy Transport and Trade for 18%. Three purchasers accounted for 98% of Developmental Drilling Fund 1994’s total oil and gas production during 1999: Scurlock Permian LLC for 55%, Navajo Refining Company, Inc. for 24% and Duke Energy Transport and Trade for 19%. All purchasers of Developmental Drilling Fund 1994’s oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing Developmental Drilling Fund 1994’s production, the managing general

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partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Developmental Drilling Fund 1994’s total oil and gas production.

Properties

As of December 31, 2001, Developmental Drilling Fund 1994 possessed an interest in oil and gas properties located in Eddy County, New Mexico and Ward County, Texas. These properties consist of various interests in 2 wells.

There have not been any significant changes in these properties during 2001, 2000 and 1999, other than ordinary production declines and reserve depletion.

Significant Properties

The following table reflects the significant properties in which Developmental Drilling Fund 1994 has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
Mobile Fee J	1/95	1	46,000	114,000
Ward County, Texas	97% working interest

* Ryder Scott Company, L.P. audited the reserve and present value data for Developmental Drilling Fund 1994’s existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $18.91 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $2.34 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 1994,” oil and gas prices were subject to frequent changes in 2001.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Developmental Drilling Fund 1994. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous

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estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Developmental Drilling Fund 1994 has reserves which are classified as proved developed producing. All of the proved reserves are included in the engineering reports which evaluate Developmental Drilling Fund 1994’s present reserves.

Market Information for Developmental Drilling Fund 1994’s Partnership Interests and Related Partnership Matters

Market Information

Investor partner interests in Developmental Drilling Fund 1994 were initially offered and sold for a price of $1,000.

The managing general partner has the right, but not the obligation, to purchase limited partner interests in Developmental Drilling Fund 1994 should an investor desire to sell. The value of the interest is determined by adding the sum of (1) current assets less liabilities and (2) the net present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank of Midland, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third ( ¹/3) to be determined by the managing general partner in its sole and absolute discretion. As of December 31, 2001, 2000 and 1999, no units of limited partner interest were purchased by the managing general partner. Generally, the price of oil and gas in a given year, which directly impacts the purchase price per unit, dictates the level of interest of the limited partners in tendering their interests.

Number of Limited and General Partner Interest Holders

As of December 31, 2001, there were 114 holders of limited partner interest and no holders of general partner interests in Developmental Drilling Fund 1994.

Distributions

Pursuant to Article IV, Section 4.01 of Developmental Drilling Fund 1994’s Certificate and Agreement of Limited Partnership, Net Cash Flow is distributed to the partners on a quarterly basis. “Net Cash Flow” is defined as “the cash generated by [Developmental Drilling Fund 1994’s] drilling activities, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of [Developmental Drilling Fund 1994], including, but not limited to, drilling cost overruns, as determined in the sole discretion of the managing general partner.”

During 2001, distributions were made totaling $125,334, with $111,547 distributed to the investor partners and $13,787 to the managing general partner. For the year ended December 31, 2001, distributions of $49.91 per investor partner unit were made, based upon 2,235 investor partner units outstanding. During 2000, distributions were made totaling $149,502, with $133,057 distributed to the investor partners and $16,445 to the managing general partner. For the year ended December 31, 2000, distributions of $59.53 per investor partner unit were made, based upon 2,235 investor partner units outstanding. During 1999, distributions were made totaling $46,275, with $41,985 distributed to the investor partners and $4,290 to the managing general partner. For the year ended December 31, 1999, distributions of $18.79 per investor partner unit were made, based upon 2,235 investor partner units outstanding.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

DEVELOPMENTAL DRILLING FUND 1994

The following tables present summary selected financial information and operating data for Developmental Drilling Fund 1994 for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR DEVELOPMENTAL DRILLING FUND 1994” found elsewhere in this prospectus supplement and the financial statements and related notes for Developmental Drilling Fund 1994 included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, Operating and Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001		2001		2000		1999		1998		1997
Statement of Operations Data:
Oil and gas revenues	73,062		125,827		209,021		262,882		182,630		149,702		293,794
Net income (loss)	23,865		72,808		94,436		148,142		64,128		(394,724	)	(148,413	)
Partners’ share of net income (loss):
Managing general partner	3,025		8,809		11,988		17,196		8,765		(950	)	12,507
Investor partners	20,840		63,999		82,448		130,946		55,363		(393,774	)	(160,920	)
Investor partners’ net income (loss) per unit of limited partner interest	9.32		28.63		36.89		58.59		24.77		(176.19	)	(72.00	)
Ratio of earnings to fixed charges(1)	—		—		—		—		—		—		—
Statement of Cash Flows Data:
Net cash provided by operating activities	24,959		78,304		123,411		160,390		52,428		62,794		143,000
Net cash provided by investing activities	—		—		(320	)	649		(1,161	)	7,584		2,549
Net cash used in financing activities	(34,000	)	(87,500	)	(125,334	)	(149,502	)	(46,275	)	(64,300	)	(151,487	)
Net increase (decrease) in cash and cash equivalents	(9,041	)	(9,196	)	(2,243	)	11,537		4,992		6,078		(5,938	)
EBITDA	27,865		80,808		110,436		157,142		80,770		29,444		139,386
Cash distributions	34,000		87,500		125,334		149,502		46,275		64,300		151,487
Investor partners’ cash distributions per $500 investment	6.77		17.42		24.96		29.77		9.39		12.80		30.16
Balance Sheet Data:
Cash and cash equivalents	9,695		11,783		18,736		20,979		9,442		4,450		(1,628	)
Oil and gas properties, net at book value	114,889		126,569		118,889		134,569		144,218		155,057		581,529
Total assets	140,050		166,391		150,185		181,083		182,443		164,590		625,242
Total liabilities	—		—		—		—		—		—		1,628
Investor partners’ equity	127,048		151,691		136,468		165,567		167,678		154,300		605,301

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	Six months ended June 30,		Years ended December 31,
	2002	2001	2001	2000	1999	1998	1997
Managing general partners’ equity	13,002	14,700	13,717	15,516	14,765	10,290	18,313
Investor partner’s book value per $500 investment	28.42	33.94	30.53	37.04	37.51	34.52	135.41
Production:
Oil production (Bbls)	2,850	3,660	6,750	7,060	7,850	9,000	11,300
Natural gas production (Mcf)	3,830	4,700	10,100	13,200	14,940	19,100	23,800
Equivalent production (Boe)	3,488	4,443	8,433	9,260	10,340	12,183	15,267
Average Sales Price:
Oil price (per/Bbl)	22.02	27.56	24.87	29.50	18.65	12.53	20.35
Natural gas price (per/Mcf)	2.69	5.31	4.07	4.13	2.42	1.93	2.68
Average sales price (per Boe)	20.95	28.32	24.79	28.39	17.66	12.29	19.24
Operating and Overhead Costs (per Boe)
Lease operating expense	7.63	5.29	6.91	6.68	5.98	6.25	7.73
Production taxes	1.23	1.74	1.50	1.78	1.06	.76	1.10
General and Administrative Expense (per Boe)	4.10	3.15	3.32	3.02	2.83	2.89	1.35
Total	12.96	10.18	11.73	11.48	9.87	9.90	10.18
Cash Operating Margin (per Boe)	7.99	18.14	13.06	16.91	7.79	2.39	9.06
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	1.15	1.80	1.90	.97	1.61	34.82	18.86
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	137,000	97,000	121,000	195,000	191,000	109,000	270,000
Oil (Bbls)	69,000	67,000	56,000	81,000	72,000	42,000	80,000
Total (Boe)	92,000	83,000	76,000	113,000	104,000	60,000	125,000

⁽¹⁾ Developmental Drilling Fund 1994 has no debt-related fixed charges.

Merger Data:
Total assets for purposes of Merger Value	$	578,000
Merger Value per $500 investment	$	115.16

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

General

Developmental Drilling Fund 1994 was formed to engage primarily in the business of drilling developmental wells, to produce and market crude oil and natural gas produced from such properties, to distribute any net proceeds from operations to the general and limited partners and to the extent necessary, acquire leases which contain drilling prospects. Net revenues will not be reinvested in other revenue producing assets except to the extent that performance of remedial work is needed to improve a well’s producing capabilities. The economic life of Developmental Drilling Fund 1994 thus depends on the period over which Developmental Drilling Fund 1994’s oil and gas reserves are economically recoverable.

Results of Operations—Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	24.64	$	26.99	(9	%)
Average price per Mcf of gas	$	3.17	$	4.51	(30	%)
Oil production in barrels		1,325		1,800	(26	%)
Gas production in Mcf		1,900		2,850	(33	%)
Gross oil and gas revenue	$	38,672	$	56,156	(31	%)
Net oil and gas revenue	$	20,421	$	39,880	(49	%)
Developmental Drilling Fund 1994 distributions	$	14,000	$	37,500	(63	%)
Limited partner distributions	$	12,460	$	33,375	(63	%)
Number of limited partner interests		2,235		2,235

Revenues

Developmental Drilling Fund 1994’s oil and gas revenues decreased to $38,672 from $56,156 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 31%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1994 decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 9%, or $2.35 per barrel, resulting in a decrease of approximately $3,100 in revenues. Oil sales represented 84% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 79% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 1994 decreased during the same period by 30%, or $1.34 per Mcf, resulting in a decrease of approximately $2,500 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $5,600. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 500 barrels, or 26%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in a decrease of approximately $12,800 in revenues.

Gas production decreased approximately 950 Mcf, or 33%, during the same period, resulting in a decrease of approximately $4,300 in revenues.

The total decrease in revenues due to the change in production is approximately $17,100. The decrease in oil production is due to one lease that fluctuates levels of production. The decrease in gas production is due to down time on two leases during the quarter ended June 30, 2002.

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Costs and Expenses

Total costs and expenses decreased to $27,416 from $28,336 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 3%. The decrease is the result of lower depletion expense, partially offset by an increase in lease operating costs and general and administrative expense.

1.  Lease operating costs and production taxes increased 12%, or approximately $2,000, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 1%, or approximately $100, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001.

3.  Depletion expense decreased to $2,000 for the quarter ended June 30, 2002 from $5,000 for the same period in 2001. This represents a decrease of 60%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1994’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. Contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 1994 during 2002 as compared to 2001.

Results of Operations—General Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.02	$	27.56	(20	%)
Average price per Mcf of gas	$	2.69	$	5.31	(49	%)
Oil production in barrels		2,850		3,660	(22	%)
Gas production in Mcf		3,830		4,700	(19	%)
Gross oil and gas revenue	$	73,062	$	125,827	(42	%)
Net oil and gas revenue	$	42,143	$	94,596	(55	%)
Developmental Drilling Fund 1994 distributions	$	34,000	$	87,500	(61	%)
Limited partner distributions	$	30,260	$	77,875	(61	%)
Number of limited partner interests		2,235		2,235

Revenues

Developmental Drilling Fund 1994’s oil and gas revenues decreased to $73,062 from $125,827 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 42%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1994 decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 20%, or $5.54 per barrel, resulting in a decrease of approximately $15,800 in revenues. Oil sales represented 86% of total oil and gas sales during the six months ended June 30, 2002 as compared to 80% during the six months ended June 30, 2001.

The average price for an Mcf of gas received by Developmental Drilling Fund 1994 decreased during the same period by 49%, or $2.62 per Mcf, resulting in a decrease of approximately $10,000 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $25,800. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

13

2.  Oil production decreased approximately 800 barrels, or 22%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $22,300 in revenues.

Gas production decreased approximately 900 Mcf, or 19%, during the same period, resulting in a decrease of approximately $4,600 in revenues.

The total decrease in revenues due to the change in production is approximately $26,900. The decrease in oil production is due to two leases that fluctuates levels of production. The decrease in gas production is due to down time on two leases during the six months ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $49,217 from $53,239 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 8%. The decrease is the result of lower lease operating costs and depletion expense, partially offset by an increase in general and administrative expense.

1.  Lease operating costs and production taxes decreased 1%, or approximately $300, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 2%, or approximately $300, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $4,000 for the six months ended June 30, 2002, from $8,000 for the same period in 2001. This represents a decrease of 50%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1994’s independent petroleum consultants and updated by Southwest’s internal staff of engineers. Contributing to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Developmental Drilling Fund 1994 during 2002 as compared to 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	24.87	$	29.50	(16	%)
Average price per Mcf of gas	$	4.07	$	4.13	(1	%)
Oil production in barrels		6,750		7,060	(4	%)
Gas production in Mcf		10,100		13,200	(23	%)
Gross oil and gas revenue	$	209,021	$	262,882	(20	%)
Net oil and gas revenue	$	138,097	$	184,587	(25	%)
Developmental Drilling Fund 1994 distributions	$	125,334	$	149,502	(16	%)
Limited partner distributions	$	111,547	$	133,057	(16	%)
Per unit distribution to limited partners	$	49.91		59.53	(16	%)
Number of limited partner interests		2,235		2,235

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Revenues

Developmental Drilling Fund 1994’s oil and gas revenues decreased to $209,021 from $262,882 for the years ended December 31, 2001 and 2000, respectively, a decrease of 20%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1994 decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 16%, or $4.63 per barrel, resulting in a decrease of approximately $31,300 in revenues. Oil sales represented 80% of total oil and gas sales during the year ended December 31, 2001 as compared to 79% during the year ended December 31, 2000.

The average price for an Mcf of gas received by Developmental Drilling Fund 1994 decreased during the same period by 1%, or $.06 per Mcf, resulting in a decrease of approximately $600 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $31,900. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 310 barrels, or 4%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $9,100 in revenues.

Gas production decreased approximately 3,100 Mcf, or 23%, during the same period, resulting in a decrease of approximately $12,800 in revenues.

The total decrease in revenues due to the change in production is approximately $21,900. The decrease in gas production is due to one of two Partnership properties, which is in the Delaware Sands formation, which is a multi-layer non-homogenous reservoir that results in sporadic variances in production.

Costs and Expenses

Total costs and expenses decreased to $114,912 from $115,249 for the years ended December 31, 2001 and 2000, respectively, a decrease of less than 1%. The decrease is the result of lower lease operating expenses and production taxes offset partially by an increase in general and administrative costs and depletion expense.

1.  Lease operating costs and production taxes decreased 9%, or approximately $7,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased less than 1%, or approximately $30, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $16,000 for the year ended December 31, 2001 from $9,000 for the same period in 2000. This represents an increase of 78%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1994’s independent petroleum consultants. The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Developmental Drilling Fund 1994’s reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Developmental Drilling Fund 1994 during 2001 as compared to 2000.

15

Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	29.50	$	18.65	58	%
Average price per Mcf of gas	$	4.13	$	2.42	71	%
Oil production in barrels		7,060		7,850	(10	%)
Gas production in Mcf		13,200		14,940	(12	%)
Gross oil and gas revenue	$	262,882	$	182,630	44	%
Net oil and gas revenue	$	184,587	$	109,848	68	%
Developmental Drilling Fund 1994 distributions	$	149,502	$	46,275	223	%
Limited partner distributions	$	133,057	$	41,985	217	%
Per unit distribution to limited partners	$	59.53	$	18.79	217	%
Number of limited partner interests		2,235		2,235

Revenues

Developmental Drilling Fund 1994’s oil and gas revenues increased to $262,882 from $182,630 for the years ended December 31, 2000 and 1999, respectively, an increase of 44%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Developmental Drilling Fund 1994 increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 58%, or $10.85 per barrel, resulting in an increase of approximately $76,600 in revenues. Oil sales represented 79% of total oil and gas sales during the year ended December 31, 2000 as compared to 80% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Developmental Drilling Fund 1994 increased during the same period by 71%, or $1.71 per Mcf, resulting in an increase of approximately $22,600 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $99,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 790 barrels, or 10%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $14,700 in revenues.

Gas production decreased approximately 1,740 Mcf, or 12%, during the same period, resulting in a decrease of approximately $4,200 in revenues.

The total decrease in revenues due to the change in production is approximately $18,900.

Costs and Expenses

Total costs and expenses decreased to $115,249 from $118,691 for the years ended December 31, 2000 and 1999, respectively, a decrease of 3%. The decrease is the result of lower general and administrative costs and depletion expense offset partially by an increase in lease operating expenses and production taxes.

1.  Lease operating costs and production taxes increased 8%, or approximately $5,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

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2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 4% or approximately $1,300 during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $9,000 for the year ended December 31, 2000 from $12,000 for the same period in 1999. This represents a decrease of 25%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Developmental Drilling Fund 1994’s independent petroleum consultants.

A contributing factor to the decline in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Developmental Drilling Fund 1994’s reserves for January 1, 2001 as compared to 2000.

Revenue and Distribution Comparison

Developmental Drilling Fund 1994 net income for the years ended December 31, 2001, 2000 and 1999 was $94,436, $148,142 and $64,128, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 was $110,436, $157,142 and $80,770, respectively. Correspondingly, Developmental Drilling Fund 1994 distributions for the years ended December 31, 2001, 2000 and 1999 were $125,334, $149,502 and $46,275, respectively.

The sources for the 2001 distributions of $125,334 were oil and gas operations of approximately $123,400 and the change in oil and gas properties of approximately $(320) with the balance from available cash on hand at the beginning of the period. The source for the 2000 distributions of $149,502 were oil and gas operations of approximately $160,400 resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $46,275 were oil and gas operations of approximately $52,400 net of the change in oil and gas properties of approximately $(1,160), resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $125,334 of which $111,547 was distributed to the investor partners and $13,787 to the managing general partner. The per unit distribution to investor partners during the same period was $49.91. Total distributions during the year ended December 31, 2000 were $149,502 of which $133,057 was distributed to the investor partners and $16,445 to the managing general partner. The per unit distribution to investor partners during the same period was $59.53. Total distributions during the year ended December 31, 1999 were $46,275 of which $41,985 was distributed to the investor partners and $4,290 to the managing general partner. The per unit distribution to investor partners during the same period was $18.79.

Liquidity and Capital Resources of Developmental Drilling Fund 1994

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Developmental Drilling Fund 1994 knows of no material change.

Cash flows provided by operating activities were approximately $25,000 in the six months ended June 30, 2002 as compared to approximately $78,300 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was operations.

Cash flows used in financing activities were approximately $34,000 in the six months ended June 30, 2002 as compared to approximately $87,500 in the six months ended June 30, 2001. The use of the 2002 cash flow from financing activities was distributions to partners.

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Total distributions during the six months ended June 30, 2002 were $34,000 of which $30,260 was distributed to the investor partners and $3,740 to the managing general partners. The per unit distribution to investor partners during the six months ended June 30, 2002 was $13.54. Total distributions during the six months ended June 30, 2001 were $87,500 of which $77,875 was distributed to the investor partners and $9,625 to the managing general partners. The per unit distribution to investor partners during the six months ended June 30, 2001 was $34.84.

The sources for the 2002 distributions of $34,000 were oil and gas operations of approximately $25,000, with the balance from available cash on hand at the beginning of the period. The sources for the 2001 distributions of $87,500 were oil and gas operations of approximately $78,300, with the balance from available cash on hand at the beginning of the period.

Since inception of Developmental Drilling Fund 1994, cumulative monthly cash distributions of $643,398 have been made to the partners. As of June 30, 2002, $573,974 or $256.81 per investor partner unit has been distributed to the investor partners, representing a 26% return of the capital contributed.

As of June 30, 2002, Developmental Drilling Fund 1994 had approximately $25,200 in working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Developmental Drilling Fund 1994.

Cash flows provided by operating activities were approximately $123,400 in 2001 compared to $160,400 in 2000 and $52,400 in 1999. The primary source of the 2001 cash flow from operating activities was profitable operations.

Cash flows (used in) provided by investing activities were approximately $(320) in 2001 compared to $650 in 2000 and $(1,160) in 1999. The principal source of the 2001 cash flow from investing activities was the addition of oil and gas properties.

Cash flows used in financing activities were approximately $125,300 in 2001 compared to $149,500 in 2000 and $46,300 in 1999. The only use in the 2001 financing activities was the distributions to partners.

18

SOUTHWEST ROYALTIES, INC.

407 North Big Spring

Suite 300

Midland, Texas 79701

SUPPLEMENTAL INFORMATION

OF

SOUTHWEST PARTNERS, L.P.

TO

PROSPECTUS/PROXY STATEMENT DATED                         , 2002

THE DATE OF THIS SUPPLEMENT IS                         , 2002

The effects of the merger may be different for limited partners in the various partnerships; accordingly, we have prepared prospectus supplements for each partnership. This document contains important information specific to Southwest Partners, L.P., which we call Southwest Partners, and supplements the prospectus/proxy statement dated                         , 2002, of Southwest Royalties, Inc., by which Southwest Royalties is soliciting proxies to be voted at a special meeting of limited partners of Southwest Partners. The purpose of the special meeting is for you to vote upon the merger of Southwest Partners with and into Southwest Consolidated Partnerships, a wholly-owned subsidiary of Southwest Royalties, and, immediately thereafter, the merger of Southwest Consolidated Partnerships into Southwest Managed Assets, a wholly-owned subsidiary of Southwest. We collectively and generally refer to the foregoing transactions as the “merger.” If the merger of Southwest Partners is completed, you will ultimately receive shares of common stock of Southwest Royalties in exchange for your limited partner interests.

Southwest will promptly mail a copy of the prospectus supplement of any of the 21 partnerships Southwest proposes to include in the merger without charge upon request by a limited partner or his representative who has been so designated in writing, addressed to Southwest Royalties, Inc., 407 North Big Spring, Suite 300, Midland, Texas 79701, Attention: B.J. Parrish. You may also request a copy of any prospectus supplement by visiting our website at http://www.swrpartners.com and clicking on                         .

This document contains the following information concerning Southwest Partners:

• Material risks associated with the merger

• Fairness of the merger

• Merger Value for Southwest Partners

• Compensation and distributions from Southwest Partners

• A supplemental information table containing:

—the aggregate initial investment by the limited partners

—the aggregate historical limited partner distributions through June 30, 2002

—the aggregate Merger Value attributable to partnership interests of limited partners, including Southwest

—the Merger Value per $500 limited partner investment as of June 30, 2002

—the Merger Value per $500 limited partner investment as a multiple of distributions for the 12 months ended June 30, 2002

—the book value per $500 limited partner investment as of June 30, 2002 and as of December 31, 2001

—the going concern value per $500 limited partner investment as of June 30, 2002

—the liquidation value per $500 limited partner investment as of June 30, 2002

—the final presentment value per $500 limited partner investment as of June 30, 2002

• Selected historical financial and operating data for Southwest Partners for the five years ended December 31, 2001 and for the six months ended June 30, 2002 and 2001

• Southwest Partners’ management’s discussion and analysis of financial condition and results of operations for the quarters ended June 30, 2002 and 2001, for the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999

RISK FACTORS

Before voting on the merger, you should carefully consider the following factors in addition to the other information included in this prospectus supplement and in the prospectus/proxy statement. Certain risk factors associated with the merger are briefly described below and are described in more detail elsewhere in the prospectus/proxy statement under the heading “RISK FACTORS.”

Determining merger values involves inherent risks which cannot be fully eliminated.    Ryder Scott Company, L.P., has audited the volumes of the oil and gas reserves of Southwest Partners as of December 31, 2001, and our internal staff of engineers has updated the reserve report to July 1, 2002. The properties of Southwest Partners, however, may have oil or gas reserves, or both, that are not now apparent, or, if known, cannot be accurately valued. If that is the case, you will not receive full credit for the value of those property interests in the merger. In addition, future events may show that the Merger Value formula operated to the disadvantage of Southwest Partners in relation to other partnerships participating in the merger. The assumptions and estimates used in the formula for valuing the assets for purposes of the merger may turn out to have operated to the disadvantage of certain parties to the merger or to have been incorrect, and even if they were not, factors beyond our control may intervene to upset those assumptions and the calculations based on them. For example, after a period of production, certain reserves may be found to have been over- or under-estimated in the engineering studies. Price and cost estimates for particular periods and the rate employed to discount future net revenues to present value may be too high or too low. A particular mix of oil and gas properties may benefit more from price increases than another mix; gas may benefit more from price increases than crude oil, or vice versa. Taxes may favor one product over another. Historical distributions and cash flows of the partnerships have varied significantly relative to price fluctuations in commodities. Significant assumptions have been made in calculating the Merger Values of partnership properties, and we can give no assurance that these assumptions will prove to be correct. See “METHOD OF DETERMINING MERGER VALUE FOR EACH PARTNERSHIP AND AMOUNT OF SOUTHWEST COMMON STOCK TO BE ISSUED,” in the prospectus/proxy statement.

There is currently no public market for our common stock, and we cannot assure you that a market will develop.    Prior to the consummation of the merger, there has been no public market for our common stock. Although we plan to register our common stock under the Securities Act and have applied to list our common stock on Nasdaq (National Market), we cannot assure you that our listing application to Nasdaq (National Market) will be approved or that an active trading market for our common stock will develop. Future trading prices of our common stock will depend on many factors including, among other things, our operating results and financial condition and the market for similar securities. We cannot offer you any assurances as to the future market price for our common stock. In addition, we cannot assure you that the aggregate market value of our common stock which you will hold following consummation of the merger will equal or exceed the aggregate market value of your pro rata portion of Southwest Partners’ assets. The Merger Value of Southwest Partners is based upon a formula to allocate shares of common stock and does not constitute a market value of our common stock or our reserves. While we believe the Merger Value is a fair measure for allocating shares of our common to Southwest

2

Partners, it should not be considered an appraisal or representative of the value which may be ascribed to our common stock in a trading market.

The IRS may successfully challenge the tax treatment of the merger.    Although we believe that the merger will be treated as described in the section titled “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement, the IRS may successfully challenge the characterization. We have not requested a ruling from the IRS on the tax consequences of the proposed merger and the IRS may disagree with the opinion of our counsel on the tax consequences. See “MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES” in the prospectus/proxy statement.

FAIRNESS OF THE MERGER

We considered, as alternatives to the merger, (i) dissolving Southwest Partners by liquidating its assets in accordance with its partnership agreement and (ii) continuing to manage Southwest Partners. We believe, however, that Southwest Partners will realize greater value from its properties over the long term by operating them on a combined basis and achieving substantial cost savings. Our Board of Directors has unanimously approved the proposed merger. We reasonably believe that the merger is fair and in the best interests of the limited partners of Southwest Partners. Our decision is based on the following factors in order of significance:

• Our method of valuation for Southwest Partners uses a standardized price in the calculation of Net Asset Value that is the same for all the partnerships and Southwest, with adjustments only for individual characteristics of properties of the individual partnerships and Southwest.

• The allocation of shares of our common stock is based on a standardized method of calculating the Merger Value for all partnerships and Southwest.

• Our calculation of the Net Asset Value of Southwest Partners, the other partnerships and Southwest uses a method to value the assets (reserves) of oil and gas properties that we believe is generally accepted in the industry.

• The Merger Value is greater than the net book value, the going concern value and the liquidation value of Southwest Partners. The final presentment value is not available to the limited partners of Southwest Partners. See “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

For a discussion on the fairness of the merger to the limited partners in each of the partnerships, see “BACKGROUND AND REASONS FOR THE MERGER—Fairness of the Merger” in the prospectus/proxy statement.

MERGER VALUE FOR SOUTHWEST PARTNERS

The Merger Value for Southwest Partners was determined by calculating its Net Asset Value and then dividing Southwest Partners’ Net Asset Value by a total combined Net Asset Value of all the partnerships and Southwest in order to determine Southwest Partners’ ownership percentage of Southwest and, thus, the number of shares of our common stock to be distributed to Southwest Partners’ limited partners. Set forth below is a table showing the calculation of the Merger Value for Southwest Partners. As indicated below, the number of shares of common stock issuable per each unit of limited partner interest in Southwest Partners is 4,201.

						Document(s) from which information was obtained or calculated
(1)		Determine the Net Asset Value of Southwest Partners
		Net Present Value of Reserves	$	10,550,519.00		July 1, 2002 reserve report
	plus	Net Working Capital	$	(95,160.00	)	June 30, 2002 Financials
	less	Long-Term Debt	$	(459,128.00	)	June 30, 2002 Financials
	plus	Additional Net Assets	$	—		June 30, 2002 Financials
	equals	Net Asset Value of Southwest Partners	$	9,996,231.00		calculated

3

						Document(s) from which information was obtained or calculated
(2)		Net Asset Value of Southwest Partners	$	9,996,231.00		calculated
	less	GP% owned by Southwest in Southwest Partners (15%)	$	1,499,434.65		Partnership records
	less	LP% owned by Southwest in Southwest Partners (4.40%)	$	439,834.16		Partnership records
	equals	Net Asset Value of Southwest Partners owned by limited partners (excluding Southwest’s ownership %)	$	8,056,962.19		calculated
(3)		Net Asset Value of Southwest	$	36,078,810.00		July 1, 2002 reserves and June 30, 2002 Financials
	plus	Southwest’s GP and LP % of all Partnerships’ Net Asset Value	$	10,416,577.58		calculated
	equals	Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58		calculated
(4)		Southwest’s Final and Adjusted Net Asset Value	$	46,495,387.58		calculated
	plus	Net Asset Value owned by limited partners (other than Southwest) of all partnerships	$	32,004,980.42		calculated
	equals	Total Net Asset Value of combined entity	$	78,500,368.00		calculated
	divided into	The Net Asset Value owned by limited partners of Southwest Partners (excluding Southwest’s ownership %)	$	8,056,962.19		calculated
	equals	The percentage of ownership of Southwest Partners (other than Southwest) to the total Net Asset Value		10.26	%	calculated
(5)		Total shares of Southwest Class A common stock and common stock issued and outstanding		1,000,000		June 30, 2002 Financials
	divided by	Percentage of ownership for Southwest of total Net Asset Value of combined entity		59.23	%	calculated
	equals	Total number of shares of common stock for combined entity		1,688,347		calculated
(6)		Total number of shares of common stock for combined entity		1,688,347		calculated
	multiplied by	The percentage of ownership to the total Net Asset Value for Southwest Partners (other than Southwest)		10.26	%	calculated
	equals	The number of shares of common stock attributable to Southwest Partners (other than to Southwest)		173,285.19		calculated
(7)		The number of shares of common stock attributable to Southwest Partners (other than to Southwest)		173,285		calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) of Southwest Partners		41		Partnership records
	equals	The number of shares of common stock issuable per each unit of limited partner interest in Southwest Partners		4,201		calculated

4

				Document(s) from which information was obtained or calculated
(8)		The number of shares of special stock attributable to Southwest Partners (other than to Southwest)	34,657	calculated
	divided by	The number of units of limited partner interest (less the GP and Southwest LP interests) in Southwest Partners	41	Partnership records
	equals	The number of shares of special stock issuable per each unit of limited partner interest in Southwest Partners	845.29	calculated

As indicated above, shares of our special stock will be issued into escrow by Southwest to be held for the benefit of each limited partner in the event the limited partners become entitled to receive additional shares of common stock under the circumstances described in “DESCRIPTION OF OUR CAPITAL STOCK—Series B Special Stock to be Issued in the Merger” in the prospectus/proxy statement. The issuance of 137,669 shares of our special stock will prevent the former limited partners’ stock ownership from being diluted under certain circumstances. Each limited partner will receive a number of shares of special stock calculated by (a) multiplying the total number of shares of special stock to be issued to the partnerships and by (b) the percentage of ownership of a particular partnership to the total Net Asset Value for each partnership. We will then divide the resulting number of shares of special stock by the number of units of limited partner interest in each partnership to obtain the number of shares of special stock issuable per each unit of limited partner interest in each partnership.

5

COMPENSATION AND DISTRIBUTIONS

Set forth below is a table showing our compensation (consisting of management fees and administrative overhead) and distribution history (as general partner and as a limited partner) from Southwest Partners for the three most recent fiscal years and the six months ended June 30, 2002. We received no money for reimbursement of expenses during the periods indicated. If our compensation and distribution structure that will be in effect after the merger had been in effect during such periods, the compensation and distributions set forth in the table would be $0.

Historical	Year Ended December 31,						Six Months Ended June 30, 2002
	2001		2000		1999
Management Fees per Partnership Agreement	$	54,000	$	54,000	$	54,000	$	27,000
Administrative Overhead per Operating Agreements	$	389,850	$	379,305	$	389,684	$	204,626
Cash Distributions Paid to General Partner as General Partner	$	19,086	$	38,353	$	—	$	—
Cash Distributions Paid to General Partner as Limited Partner	$	4,885	$	9,770	$	—	$	—

Set forth below is a table showing the cash distributions to Southwest Partners’ limited partners for the five most recent fiscal years and the six months ended June 30, 2002.

	Year Ended December 31,								Six Months Ended June 30, 2002
	2001		2000		1999	1998	1997
Cash distributions(1)	$	108,155	$	217,336	$—	$—	$	—	$—
Return of Capital: 8%

⁽¹⁾ Because of depletion (which is usually higher in the early years of production), a portion of every distribution of revenues from properties represents a return of a limited partner’s original investment. Until a limited partner receives cash distributions equal to his original investment, 100% of such distribution may be deemed to be a return of capital.

SUPPLEMENTAL INFORMATION TABLE FOR SOUTHWEST PARTNERS

Aggregate Initial Investment by the Limited Partners:	$	4,350	(1)
Aggregate Historical Limited Partner Distributions through June 30, 2002:	$	332	(1)
Aggregate Merger Value Attributable to Partnership Interests of Limited Partners, Including Southwest:	$	8,497	(1)
Merger Value per $500 Limited Partner Investment as of June 30, 2002:	$	976.64	(2)(3)
Merger Value per $500 Limited Partner Investment as a Multiple of Distributions for 12 months ended June 30, 2002:		4,460.3	(2)(3)
Book Value per $500 Limited Partner Investment:
—as of June 30, 2002:	$	340.22	(2)(4)
—as of December 31, 2001:	$	348.67	(2)(4)
Going Concern Value per $500 Limited Partner Investment as of June 30, 2002:	$	909.19	(2)(5)
Liquidation Value per $500 Limited Partner Investment as of June 30, 2002:	$	706.12	(2)(6)
Final Presentment Value per $500 Limited Partner Investment as of June 30, 2002:		N/A	(7)

⁽¹⁾ Stated in thousands.

⁽²⁾ Interests in some partnerships were sold at prices other than $500. We have presented this information based on a $500 initial investment for ease of use and comparison among the partnerships. You should not assume that the amount shown per $500 investment is the same as the value or amount attributable to a single unit investment.

6

⁽³⁾ The Merger Value for Southwest Partners is equal to (1) the sum of (A) the present value of estimated future net revenues from Southwest Partners’ estimated oil and gas reserves, (B) its net working capital and (C) any other non-oil and gas assets, in each case as of June 30, 2002, (2) less any long-term debt.

⁽⁴⁾ The book value for Southwest Partners is based upon the limited partner’s equity as reported in the audited December 31, 2001 and unaudited June 30, 2002 financial statements. This amount has then been divided by the total number of $500 units of limited partner interests sold to calculate the book value per $500 limited partner investment for both of these periods.

⁽⁵⁾ The going concern value for Southwest Partners is based upon (1) the sum of (A) the estimated net cash flow from the sale of Southwest Partners’ reserves during a 12-year operating period and (B) the estimated residual value from the sale of Southwest Partners’ remaining reserves at a price of $3.85 per Boe at the end of the operating period, in each case using the same pricing and discount rate as in the Merger Value calculation, (2) less (A) the present value of the annual general and administrative expenses for the 12-year period discounted at 7%, and (B) any long-term debt. In the event the present value of the annual general and administrative expenses for a partnership for the 12-year term is greater than its present value of the projected cash flows, the partnership is deemed uneconomic for that term and shorter terms are analyzed until such partnerships are economic.

⁽⁶⁾ The liquidation value for Southwest Partners is based upon (1) the sum of (A) the sale of Southwest Partners’ reserves at a liquidation price of $3.85 per Boe, (B) its net working capital and (C) any other non-oil and gas assets, (2) less (A) liquidation expenses which are estimated to be the sum of (i) broker or agent fees of 3% of Southwest Partners’ liquidation value and (ii) partnership wind-down costs of $20,000 per partnership, and (B) any long-term debt. The liquidation expenses represent the estimated costs to retain an investment banker or broker to sell the assets of Southwest Partners and the costs, including legal and otherwise, of winding down the partnership.

⁽⁷⁾ There is no right of presentment in the limited partnership agreement for Southwest Partners and, thus, no discernible final presentment value.

SOUTHWEST PARTNERS

Set forth below is basic information about Southwest Partners and its business and operations. It does not contain all the information about Southwest Partners that is important to you. We encourage you to read this information in conjunction with “THE PARTNERSHIPS” found in the prospectus/proxy statement.

Business of Southwest Partners

General

Southwest Partners was organized as a Delaware limited partnership on March 31, 1993. The offering of limited partner interests began March 31, 1993, minimum capital requirements were met August 3, 1993 and the offering concluded November 19, 1993. Southwest Partners has a wholly-owned subsidiary, Tex-Hal Partners, Inc.

Principal Products, Marketing and Distribution

Southwest Partners has acquired and holds working interests in oil and gas properties located in New Mexico and Texas.

Following is a table of the ratios of revenues received from oil and gas production for the last three years:

Year	Oil		Gas
2001	34	%	66	%
2000	35	%	65	%
1999	37	%	63	%

As the table indicates, the majority of Southwest Partners’ 2001 revenue is from its gas production.

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Customer Dependence

No material portion of Southwest Partners’ business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on Southwest Partners. Two purchasers accounted for 96% of Southwest Partners’ total oil and gas production during 2001: Duke Energy Field Services for 63% and Navajo Refining Company, Inc. for 33%. Two purchasers accounted for 97% of Southwest Partners’ total oil and gas production during 2000: Navajo Refining Company, Inc. for 54% and Phillips Natural Gas Company for 43%. Three purchasers accounted for 88% of Southwest Partners’ total oil and gas production during 1999: Sid Richardson Gasoline Co. for 47%, Equiva Trading Co. for 31% and American Processing for 10%. All purchasers of Southwest Partners’ oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing Southwest Partners’ production, the managing general partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of Southwest Partners’ sales of oil and gas production.

Properties

As of December 31, 2001, Southwest Partners possessed an interest in oil and gas properties located in Eddy County, New Mexico and Upton and Winkler County, Texas. These properties consist of various interests in approximately 173 wells and units.

Southwest Partners’ wholly-owned subsidiary drilled and completed 6 wells during 2001, 7 wells during 2000 and 2 gas wells during 1999.

During 2001 and 2000 no leases were sold. During 1999, 13 leases were sold for approximately $112,500.

Significant Properties

The following table reflects the significant properties in which Southwest Partners has an interest:

Name and Location	Date Purchased and Interest	No. of Wells	Proved Developed Producing Reserves*
			Oil (Bbls)	Gas (Mcf)
McElroy Ranch Upton County, Texas	8/98 at 18.0% working interest	2	2,000	459,000
Halley Acquisition Winkler County, Texas	9/94 at 66.67% working interest	114	26,000	305,000

* Ryder Scott Company, L.P. audited the reserve and present value data for Southwest Partners’ existing properties as of January 1, 2002. The reserve estimates were made in accordance with guidelines established by the SEC pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. The reserve volumes presented in the preceding table are proved developed producing reserves (PDP) only.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The reserve report as of January 1, 2002 reflects an average price of $19.16 per barrel.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The reserve report as of January 1, 2002 reflects an average price of $1.97 per Mcf.

As also discussed in “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR SOUTHWEST PARTNERS,” oil and gas prices were subject to frequent changes in 2001.

8

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus, a lower return for Southwest Partners. Basic changes in past reserve estimates occur annually. As new data is gathered

during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

Southwest Partners has reserves, which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate Southwest Partners’ present reserves.

Market Information for Southwest Partners’ Partnership Interests and Related Partnership Matters

Market Information

Limited partner interests, in Southwest Partners were initially offered and sold for a price of $100,000. Limited partner interests are not traded on any exchange, and there is no public or organized trading market for them. No limited partner may sell, assign, transfer, pledge, encumber, grant a security interest in, or otherwise dispose of all or any part of his interest in Southwest Partners to any person, trust, association, company, firm, partnership, corporation or other entity without first giving written notice of such intended transfer to the general partner of the number of units of limited partner interest he proposes to dispose of and the nature and terms of the proposed disposition. The notice is deemed to constitute an offer to sell the offered units to the general partner on the terms set forth in the notice. The general partner shall have 15 days from the date the offer is deemed to have been given by the selling holder to indicate in writing to the selling holder its decision as to whether it will purchase all or any of the offered units. In 2001, .25 units of limited partner interest were tendered to and purchased by the managing general partner at an average base price of $185,092 per unit. There were no units purchased during 2000 and 1999.

Number of Limited Partner Interest Holders

As of December 31, 2001, there were 84 holders of limited partner interest in Southwest Partners.

Distributions

Pursuant to Section 4.1 of Southwest Partners’ Agreement of Limited Partnership, “Net Cash from Operations” and Net Cash from Sales or Refinancings shall be distributed, at such times as the general partner may determine in its sole discretion. “Net Cash From Operations” means the gross cash proceeds from Southwest Partners operations less the portion thereof used to pay or establish reserves for all Southwest Partners expenses, debt payments, capital improvements, replacements, and contingencies, all as determined by the general partner. “Net Cash from Sales or Refinancings” means the net cash proceeds from all sales and other dispositions (other than in the ordinary course of business) and all refinancings of Partnership Property, less any portion thereof used to establish reserves, all as determined by the general partner.

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Total distributions during the year ended December 31, 2001 were $127,241 of which $108,155 was distributed to the limited partners and $19,086 to the general partners. The per unit distribution to limited partners during the same period was $2,486.32. Total distributions during the year ended December 31, 2000 were $255,689 of which $217,336 was distributed to the limited partners and $38,353 to the general partners. The per unit distribution to limited partners during the same period was $4,996.23. There were no distributions during 1999.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA FOR

SOUTHWEST PARTNERS

The following tables present summary selected financial information and operating data for Southwest Partners for the periods indicated. It should be read in conjunction with “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FOR SOUTHWEST PARTNERS” found elsewhere in this prospectus supplement and the financial statements and related notes for Southwest Partners included in the prospectus/proxy statement. The information contained under the headings Statement of Operations Data, Statement of Cash Flows Data, Production, Average Sales Price, and Operating Overhead Costs (per Boe), General and Administrative Expense (per Boe) Cash Operations Margin (per Boe) and Other for the years ending December 31, 2001, 2000, 1999, 1998 and 1997 and Balance Sheet Data as of December 31, 2001, 2000, 1999, 1998 and 1997 were derived from audited financial statements. All other information is unaudited. The results for the six months ended June 30, 2002 are not necessarily indicative of the results to be expected for a full year.

	Six months ended June 30,				Years ended December 31,
	2002		2001(1)		2001		2000(1)		1999(1)		1998		1997
Statement of Operations Data:
Oil and gas revenues	791,290		1,792,494		2,711,350		3,732,728		2,133,633		1,865,162		2,605,181
Net income (loss)	(86,448	)	340,092		104,943		1,544,534		599,454		(3,642,954	)	(5,835	)
Partners’ share of net income (loss):
General partners	(12,967	)	51,014		15,741		231,680		89,918		(546,443	)	(875	)
Partners	(73,481	)	289,078		89,202		1,312,854		509,536		(3,096,511	)	(4,960	)
Partners’ net income (loss) per unit of limited partner interest	(1,689	)	6,645		2,051		30,181		11,713		(71,184	)	(114	)
Ratio of earnings to fixed charges	(20.6x	)	86.7x		24.3x		38.1x		6.4x		(111.1x	)	5.5x
Statement of Cash Flows Data:
Net cash provided by operating activities	113,488		1,900,898		1,243,203		1,936,741		751,768		41,763		1,379,348
Net cash used in investing activities	(500,997	)	(1,078,714	)	(1,241,945	)	(1,231,030	)	(150,150	)	(849,539	)	(1,765,620	)
Net cash provided by used in financing activities	443,890		(363,451	)	(365,692	)	(670,571	)	(345,000	)	800,000		(140,000	)

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	Six months ended June 30,		Years ended December 31,
	2002	2001(1)	2001		2000(1)	1999(1)	1998		1997
Net increase (decrease) in cash and cash equivalents	56,381	458,733	(364,434	)	35,140	256,618	(7,776	)	(526,272	)
EBITDA	77,557	897,042	1,003,708		2,183,390	897,924	360,558		1,247,755
Cash distributions	—	125,000	127,241		255,689	—	—		—
Partners’ cash distributions per $500 investment	—	12.21	12.43		24.98	—	—		—
Balance Sheet Data:
Cash and cash equivalents	69,879	836,665	13,498		377,932	342,792	86,174		93,950
Oil and gas properties, net at book value	3,747,355	3,721,127	3,406,358		3,023,413	2,047,383	2,315,233		5,664,392
Total assets	3,817,234	3,824,918	3,577,656		3,678,277	2,666,301	2,411,847		5,765,382
Total liabilities	876,137	308,013	298,141		376,464	653,333	345,000		414,172
Partners’ equity	2,745,745	3,235,182	3,033,401		3,052,354	1,956,836	1,447,300		4,543,811
General partners’ equity	195,352	281,723	246,114		249,459	56,132	(33,786	)	512,657
Partner’s book value per $500 investment	315.60	371.86	348.67		350.85	224.92	166.36		522.28
Production:
Oil production (Bbls)	18,730	20,500	41,980		43,000	50,360	68,200		96,500
Natural gas production (Mcf)	146,100	246,000	429,300		616,100	664,240	672,200		362,000
Equivalent production (Boe)	43,080	61,500	113,530		145,683	161,067	180,233		156,833
Average Sales Price:
Oil price (per/Bbl)	20.68	25.20	21.87		28.55	16.20	11.69		18.37
Natural gas price (per/Mcf)	2.76	5.19	4.18		3.69	1.98	1.59		2.30
Average sales price (per Boe)	18.37	29.15	23.88		24.01	13.24	10.34		16.61
Operating and Overhead Costs (per Boe)
Lease operating expense	14.73	12.30	13.13		8.72	6.63	7.37		7.48
Production taxes	.99	1.68	1.34		1.52	.66	.55		.83

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	Six months ended June 30,		Years ended December 31,
	2002	2001(1)	2001	2000(1)	1999(1)	1998	1997
General and Administrative Expense (per Boe)	.86	.65	.62	.45	.41	.45	.43
Total	16.58	14.63	15.09	10.69	7.70	8.37	8.74
Cash Operating Margin (per Boe)	1.79	14.52	8.79	13.32	5.54	1.97	7.87
Other:
Depreciation, depletion and amortization—oil and gas properties (per Boe)	3.71	6.20	7.57	1.75	2.60	23.31	7.05
Estimated Net Proved Reserves (as of period end):
Natural gas (Mcf)	7,929,000	9,593,000	7,868,000	10,938,000	13,419,000	11,458,000	7,647,000
Oil (Bbls)	763,000	751,000	657,000	904,000	901,000	784,000	1,400,000
Total (Boe)	2,085,000	2,350,000	1,968,000	2,727,000	3,138,000	2,694,000	2,675,000

⁽¹⁾ Retained earnings as of December 31, 1999 has been restated to reflect an adjustment related to statutory depletion carryforwards which had not previously been considered in the calculation of deferred income taxes of subsidiary. See “Consolidated Financial Statements for Southwest Partners” in the prospectus/proxy statement.

Merger Data:
Total assets for purposes of Merger Value	$	8,996,000
Merger Value per $500 investment	$	976.64

See “UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS” found in the prospectus/proxy statement for pro forma financial information.

13

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS FOR SOUTHWEST PARTNERS

General

Southwest Partners was formed to acquire an investment in an oil and gas company and acquire interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. Net revenues from producing oil and gas properties are reinvested. The economic life of Southwest Partners thus depends on the period over which Southwest Partners’ oil and gas reserves are economically recoverable.

Increases or decreases in Southwest Partners’ revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, lease operating expenses, enhanced recovery projects, drilling activities and on the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.

Well operating costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately. Net income available for distribution to the limited partners is therefore expected to fluctuate in later years based on these factors.

Results of Operations—General Comparison of the Quarters Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the quarters ended June 30, 2002 and 2001:

	Three Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	22.74	$	24.68	(8	%)
Average price per Mcf of gas	$	3.25	$	4.10	(21	%)
Oil production in barrels		9,730		9,300	5	%
Gas production in Mcf		73,600		112,500	(35	%)
Gross oil and gas revenue	$	460,448	$	647,971	(29	%)
Net oil and gas revenue	$	160,647	$	204,510	(21	%)
Number of limited partner interests		43.5		43.5

Revenues

Southwest Partners’ oil and gas revenues decreased to $460,448 from $647,971 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 29%. The principal factors affecting the comparison of the quarters ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Southwest Partners decreased during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001 by 8%, or $1.94 per barrel, resulting in a decrease of approximately $18,900 in revenues. Oil sales represented 48% of total oil and gas sales during the quarter ended June 30, 2002 as compared to 33% during the quarter ended June 30, 2001.

The average price for an Mcf of gas received by Southwest Partners decreased during the same period by 21%, or $.85 per Mcf, resulting in a decrease of approximately $62,600 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $81,500. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

14

2.  Oil production increased approximately 430 barrels, or 5%, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001, resulting in an increase of approximately $10,600 in revenues.

Gas production decreased approximately 38,900 Mcf, or 35%, during the same period, resulting in a decrease of approximately $159,500 in revenues.

The net total decrease in revenues due to the change in production is approximately $148,900. The decrease in gas production is due to several tight gas sand wells that have a very steep initial decline rate. In addition to two gas wells that were converted to oil wells during the quarter ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $427,274 from $693,778 for the quarters ended June 30, 2002 and 2001, respectively, a decrease of 38%. The decrease is the result of lower lease operating costs, general and administrative expense and depletion expense, partially offset by an increase in interest expense.

1.  Lease operating costs and production taxes decreased 32%, or approximately $143,700, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in lease operating expense is due to successful maintenance and other repairs being performed in 2001 and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 15%, or approximately $3,600, during the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001. The decrease in general and administrative expense is due primarily to a decrease in the state franchise tax expense.

3.  Depletion expense decreased to $102,000 for the quarter ended June 30, 2002, from $224,000 for the same period in 2001. This represents a decrease of 54%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Southwest Partners’ independent petroleum consultants and updated by Southwest’s internal staff of engineers. A contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Southwest Partners during 2002 as compared to 2001.

4.  Interest expense in relation to the note payable recorded on Southwest Partners’ books was $4,005 for the quarter ended June 30, 2002 as compared to $1,206 for the quarter ended June 30, 2001. On April 19, 2002, Southwest Partners signed a new note thus interest is greater than 2001, which only represented one month of interest due to the fact that the old note was paid off in its entirety as of May 31, 2001.

15

Results of Operations—General Comparison of the Six Month Periods Ended June 30, 2002 and 2001

The following table provides certain information regarding performance factors for the six month periods ended June 30, 2002 and 2001:

	Six Months Ended June 30,				Percentage Increase (Decrease)
	2002		2001
Average price per barrel of oil	$	20.68	$	25.20	(18	%)
Average price per Mcf of gas	$	2.76	$	5.19	(47	%)
Oil production in barrels		18,730		20,500	(9	%)
Gas production in Mcf		146,100		246,000	(41	%)
Gross oil and gas revenue	$	791,290	$	1,792,494	(56	%)
Net oil and gas revenue	$	114,211	$	932,892	(88	%)
Southwest Partners distributions	$	—	$	125,000	(100	%)
Limited partner distributions	$	—	$	106,250	(100	%)
Per unit distribution to limited partners	$	—	$	2,442.53	(100	%)
Number of limited partner interests		43.5		43.5

Revenues

Southwest Partners’ oil and gas revenues decreased to $791,290 from $1,792,494 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 56%. The principal factors affecting the comparison of the six months ended June 30, 2002 and 2001 are as follows:

1.  The average price for a barrel of oil received by Southwest Partners decreased during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001 by 18%, or $4.52 per barrel, resulting in a decrease of approximately $84,700 in revenues. Oil sales represented 49% of total oil and gas sales during the six months ended June 30, 2002 and 29% for the six months ended June 30, 2001.

The average price for an Mcf of gas received by Southwest Partners decreased during the same period by 47%, or $2.43 per Mcf, resulting in a decrease of approximately $355,000 in revenues.

The total decrease in revenues due to the change in prices received from oil and gas production is approximately $439,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,800 barrels, or 9%, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001, resulting in a decrease of approximately $44,600 in revenues.

Gas production decreased approximately 99,900 Mcf, or 41%, during the same period, resulting in a decrease of approximately $518,500 in revenues.

The total decrease in revenues due to the change in production is approximately $563,100. The decrease in gas production is due to several tight gas sand wells that have a very steep initial decline rate. In addition to two gas wells that were converted to oil wells during the six months ended June 30, 2002.

Costs and Expenses

Total costs and expenses decreased to $877,919 from $1,286,576 for the six months ended June 30, 2002 and 2001, respectively, a decrease of 32%. The decrease is the result of lower lease operating costs, depletion expense, general and administrative expense and interest expense.

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1.  Lease operating costs and production taxes decreased 21%, or approximately $182,500, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001. The decrease in lease operating expense is due to successful maintenance and other repairs being performed in 2001 on one lease, and the decrease in production taxes in relation to the decrease in gross revenues received in 2002.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 8%, or approximately $3,200, during the six months ended June 30, 2002 as compared to the six months ended June 30, 2001.

3.  Depletion expense decreased to $160,000 for the six months ended June 30, 2002 from $381,000 for the same period in 2001. This represents a decrease of 58%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Southwest Partners’ independent petroleum consultants and updated by Southwest’s internal staff of engineers. Contributing factor to the decrease in depletion expense between the comparative periods was the decrease in oil and gas revenues received by Southwest Partners during 2002 as compared to 2001.

4.  Interest expense in relation to the note payable recorded on Southwest Partners’ books was $4,005 for the six months ended June 30, 2002 as compared to $5,950 for the six months ended June 30, 2001. On April 19, 2002, Southwest Partners signed a new note thus interest is greater than 2001, which only represented one onth of interest due to the fact that the old note was paid off in its entirety as of May 31, 2001.

Results of Operations—Comparison of the Years Ended December 31, 2001 and 2000

The following table provides certain information regarding performance factors for the years ended December 31, 2001 and 2000:

	Year Ended December 31,				Percentage Increase (Decrease)
	2001		2000
Average price per barrel of oil	$	21.87	$	28.55	(23	%)
Average price per Mcf of gas	$	4.18	$	3.69	13	%
Oil production in barrels		41,980		43,000	(2	%)
Gas production in Mcf		429,300		616,100	(30	%)
Gross oil and gas revenue	$	2,711,350	$	3,498,128	(22	%)
Net oil and gas revenue	$	1,067,591	$	2,005,781	(47	%)
Southwest Partners distributions	$	127,241	$	255,689	(50	%)
Limited partner distributions	$	108,155	$	217,336	(50	%)
Per unit distribution to limited partners	$	2,486	$	4,996	(50	%)
Number of limited partner interests		43.5		43.5

Revenues

Southwest Partners’ oil and gas revenues decreased to $2,711,350 from $3,498,128 for the years ended December 31, 2001 and 2000, respectively, a decrease of 22%. The principal factors affecting the comparison of the years ended December 31, 2001 and 2000 are as follows:

1.  The average price for a barrel of oil received by Southwest Partners decreased during the year ended December 31, 2001 as compared to the year ended December 31, 2000 by 23%, or $6.68 per barrel, resulting in a decrease of approximately $280,400 in revenues. Oil sales represented 34% of total oil and gas sales during the year ended December 31, 2001 as compared to 35% during the year ended December 31, 2000.

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The average price for an Mcf of gas received by Southwest Partners increased during the same period by 13%, or $.49 per Mcf, resulting in an increase of approximately $210,400 in revenues.

The total net decrease in revenues due to the change in prices received from oil and gas production is approximately $70,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 1,000 barrels, or 2%, during the year ended December 31, 2001 as compared to the year ended December 31, 2000, resulting in a decrease of approximately $29,100 in revenues.

Gas production decreased approximately 186,800 Mcf, or 30%, during the same period, resulting in a decrease of approximately $689,300 in revenues.

The total decrease in revenues due to the change in production is approximately $718,400. The decrease in gas production is due to four tight gas sand wells that have a very steep initial decline rate.

Costs and Expenses

Total costs and expenses increased to $2,578,801 from $1,862,262 for the years ended December 31, 2001 and 2000, respectively, an increase of 38%. The increase is the result of higher lease operating expense and production taxes, depletion, and general and administrative costs, partially offset by a decrease in interest expense.

1.  Lease operating costs and production taxes increased 10%, or approximately $151,400, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs increased 9%, or approximately $5,800, during the year ended December 31, 2001 as compared to the year ended December 31, 2000.

3.  Depletion expense increased to $859,000 for the year ended December 31, 2001 from $255,000 for the same period in 2000. This represents an increase of 237%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Southwest Partners’ independent petroleum consultants. The major factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine Southwest Partners’ reserves for January 1, 2002 as compared to 2001, and the decrease in oil and gas revenues received by Southwest Partners during 2001 as compared to 2000.

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Results of Operations—Comparison of the Years Ended December 31, 2000 and 1999

The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:

	Year Ended December 31,				Percentage Increase (Decrease)
	2000		1999
Average price per barrel of oil	$	28.55	$	16.20	76	%
Average price per Mcf of gas	$	3.69	$	1.98	86	%
Oil production in barrels		43,000		50,360	(15	%)
Gas production in Mcf		616,100		664,240	(7	%)
Gross oil and gas revenue	$	3,498,128	$	2,133,633	64	%
Net oil and gas revenue	$	2,005,781	$	959,136	109	%
Southwest Partners distributions	$	255,689	$	—	100	%
Limited partner distributions	$	217,336	$	—	100	%
Per unit distribution to limited partners	$	4,996	$	—	100	%
Number of limited partner interests		43.5		43.5

Revenues

Southwest Partners’ oil and gas revenues increased to $3,498,128 from $2,133,633 for the years ended December 31, 2000 and 1999, respectively, an increase of 64%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:

1.  The average price for a barrel of oil received by Southwest Partners increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 76%, or $12.35 per barrel, resulting in an increase of approximately $531,050 in revenues. Oil sales represented 35% of total oil and gas sales during the year ended December 31, 2000 as compared to 38% during the year ended December 31, 1999.

The average price for an Mcf of gas received by Southwest Partners increased during the same period by 86%, or $1.71 per Mcf, resulting in an increase of approximately $1,053,500 in revenues.

The total increase in revenues due to the change in prices received from oil and gas production is approximately $1,584,550. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.

2.  Oil production decreased approximately 7,400 barrels, or 15%, during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $119,200 in revenues.

Gas production decreased approximately 48,100 Mcf, or 7%, during the same period, resulting in a decrease of approximately $95,300 in revenues.

The total decrease in revenues due to the change in production is approximately $214,500. The decrease in production was due to the need for gas compressors on wells drilled during 2000, which were not producing at optimal levels and also to property sales during 1999.

Costs and Expenses

Total costs and expenses increased to $1,862,262 from $1,734,000 for the years ended December 31, 2000 and 1999, respectively, an increase of 7%. The increase is the result of higher lease operating expense and production taxes, partially offset by a decrease in interest expense, depletion, and general and administrative costs.

19

1.  Lease operating costs and production taxes increased 27%, or approximately $317,900, during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed Southwest Partners to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.

2.  General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and managing general partner personnel costs. General and administrative costs decreased 2%, or approximately $1,500, during the year ended December 31, 2000 as compared to the year ended December 31, 1999.

3.  Depletion expense decreased to $255,000 for the year ended December 31, 2000 from $418,000 for the same period in 1999. This represents a decrease of 39%. Depletion is calculated using the units of revenue method of amortization based on the percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by Southwest Partners’ independent petroleum consultants.

The contributing factor to the decrease in depletion expense between the comparative periods was the increase in the price of oil and gas used to determine Southwest Partners’ reserves for January 1, 2001 as compared to 2000.

Revenue and Distribution Comparison

Southwest Partners’ net income for the years ended December 31, 2001, 2000 and 1999 was $104,943, $1,544,534 and $599,454, respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2001, 2000 and 1999 would have been $963,943, $1,799,534 and $1,017,828, respectively. Correspondingly, Southwest Partners’ distributions for the years ended December 31, 2001, 2000 and 1999 were $127,241, $255,689 and none, respectively.

The sources for the 2001 distributions of $127,241 were oil and gas operations of approximately $1,243,200 net of the change in oil and gas properties of approximately $(1,241,900), with the balance from available cash on hand at the beginning of the period. The sources for the 2000 distributions of $255,689 were oil and gas operations of approximately $1,936,700 net of the change in oil and gas properties of approximately $(1,231,000), resulting in excess cash for contingencies or subsequent distributions.

Total distributions during the year ended December 31, 2001 were $127,241 of which $108,155 was distributed to the limited partners and $19,086 to the general partner. The per unit distribution to limited partners during the same period was $2,486.32. Total distributions during the year ended December 31, 2000 were $255,689 of which $217,336 was distributed to the limited partners and $38,353 to the general partner. The per unit distribution to limited partners during the same period was $4,996.23. There were no distributions during the year ended December 31, 1999.

Liquidity and Capital Resources of Southwest Partners

The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. Southwest Partners knows of no material change.

Cash flows provided by operating activities were approximately $113,500 in the six months ended June 30, 2002 as compared to approximately $1,900,900 in the six months ended June 30, 2001. The primary source of the 2002 cash flow from operating activities was operations.

20

Cash flows used in investing activities were approximately $501,000 in the six months ended June 30, 2002 as compared to approximately $1,078,700 in the six months ended June 30, 2001. The principle use of the 2002 cash flow from investing activities was additions to oil and gas properties.

Cash flows provided by (used in) financing activities were approximately $443,900 in the six months ended June 30, 2002 as compared to approximately $(363,500) in the six months ended June 30, 2001. The primary source of the 2002 cash flow from financing activities was proceeds from debt.

There were no distributions during the six months ended June 30, 2002. Total distributions during the six months ended June 30, 2001 were $125,000 of which $106,250 was distributed to the limited partners and $18,750 to the general partners. The per unit distribution to limited partners during the six months ended June 30, 2001 was $2,442.53.

Since inception of Southwest Partners, cumulative cash distributions of $389,112 have been made to the partners. As of June 30, 2002, $331,673 or $7,625 per unit of limited partner interest, has been distributed to the limited partners.

As of June 30, 2002, Southwest Partners had approximately $95,200 in negative working capital. The managing general partner knows of no unusual contractual commitments and believes the revenues generated from operations are adequate to meet the needs of Southwest Partners.

Cash flows used in investing activities were approximately $1,241,900 in 2001 compared to approximately $1,231,000 in 2000 and $150,150 in 1999. The principal use of the 2001 cash flow from investing activities was the addition to oil and gas properties.

Cash flows used in financing activities were approximately $365,700 in 2001 compared to approximately $670,600 in 2000 and approximately $345,000 in 1999. The primary use in financing activities was the payment of debt and distributions.

21

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20.    Indemnification of Officers and Directors.

The Delaware General Corporation Law permits a corporation formed in Delaware to include in its certificate of incorporation a provision eliminating or limiting the personal liability of its director to the corporation and its stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (2) for acts or omissions not in good faith or which involve intentional misconduct or knowing violation of law, (3) under Section 174 of the Delaware General Corporation Law or (4) for any transaction from which a director derived an improper personal benefit. Our Amended and Restated Certificate of Incorporation contains a provision that limits the liability of our directors to the fullest extent permitted by the Delaware General Corporation Law.

Article TWELFTH of our Amended and Restated Certificate of Incorporation provides:

The Corporation shall indemnify, to the fullest extent now or hereafter permitted by Delaware law, each officer, director or controlling person of the Corporation (any of the foregoing, an “indemnified person”), who was or is a party or is threatened to be made a party to, or is involved in, any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (any of the foregoing, a “proceeding”), by reason of the fact that the indemnified person, or a person of whom such indemnified person is the legal representative, is or was an officer, director or controlling person of the Corporation, or is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is alleged action in an official capacity as a director, officer, partner, trustee, employee or agent or in any other capacity while serving as a director, officer, partner, trustee, employee or agent, against all expense, liability or loss (including attorneys’ fees, judgments, fines, excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by the indemnified person in connection therewith, and such indemnification shall continue as to an officer, director, employee, agent or controlling person of the Corporation, and shall inure to the benefit of his or her heirs, executors and administrators.

Expenses, including attorneys’ fees incurred by an officer, director or controlling person of the Corporation, in defending any proceeding referred to in Article TWELFTH shall be paid by the Corporation, in advance of the final disposition of such proceeding, without requiring a preliminary determination of the ultimate entitlement to indemnification, upon the receipt of an undertaking by or on behalf of such indemnified person to repay such amount if it shall ultimately be determined that he or she is not entitled to be indemnified by the Corporation as authorized in this Article TWELFTH.

This indemnification and advancement of expense provided under this Article TWELFTH shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled under any law, this Amended and Restated Certificate of Incorporation, any agreement, or otherwise, both as to action in their official capacity and as to action in another capacity while holding such office.

This Article TWELFTH shall be interpreted to allow indemnification, at the discretion of the Board of Directors, of employees and agents to the fullest extent allowable under Delaware law, as amended from time to time.

The Corporation may maintain insurance, at its expense, to protect itself and each officer, director, employee, agent or controlling person of the Corporation, or any person serving at the request of the Corporation as the director, officer, partner, trustee, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against any such expense, liability or loss, whether or not the Corporation would have the power to indemnify such person against such expense, liability or loss under Delaware law.

II-1

Neither the amendment nor repeal of this Article TWELFTH, nor the adoption or amendment of any other provision of this Certificate of Incorporation or the Bylaws of the Corporation inconsistent with this Article TWELFTH, shall apply to or affect in any respect the applicability of the preceding paragraph with respect to any act or failure to act which occurred prior to such amendment, repeal or adoption.

Any amendment to this Article TWELFTH shall be valid only if approved by the unanimous vote of all of the members of the Board of Directors and by the affirmative vote of two-thirds of all of the votes entitled to be cast on the matter by stockholders.

The preceding discussion of our Amended and Restated Certificate of Incorporation and Section 145 of the Delaware General Corporation Law is not intended to be exhaustive and is qualified in its entirety by such Amended and Restated Certificate of Incorporation and Section 145 of the Delaware General Corporation Law.

Item 21.    Exhibits and Financial Statement Schedules

The following exhibits are filed with the registration statement:

Exhibit Number		Description
2.1		Form of Merger Agreement by and among Southwest Consolidated Partnerships, Inc., Southwest Royalties, Inc. and the limited partnerships named therein, dated as of                         , 2002 (included as Appendix C to the prospectus/proxy statement forming a part of this Registration Statement)
2.2		Form of Merger Agreement by and among Southwest Consolidated Partnerships, Inc., Southwest Managed Assets, Inc. and Southwest Royalties, Inc., dated as of                                     , 2002 (included as Appendix D to the prospectus/proxy statement forming a part of this Registration Statement)
3.1		Amended and Restated Certificate of Incorporation of Southwest Royalties, Inc., as filed with the Delaware Secretary of State on April 19, 2002.
*3.1	(a)	Form of Amendment to the Amended and Restated Certificate of Incorporation of Southwest Royalties, Inc.
3.2		Amended and Restated Bylaws of Southwest Royalties, Inc.
4.1		Indenture, by and among Southwest Royalties, Inc., as issuer, Southwest Royalties Holdings, Inc., Blue Heel Company and MRO Holdings, Inc., each as a guarantor, and Wilmington Trust Company, as trustee, dated April 19, 2002.
4.1	(a)	First Supplemental Indenture, by and among Southwest Royalties, Inc., as issuer, Southwest Royalties Holdings, Inc., as guarantor, MRO Holdings, Inc., as guarantor, and Wilmington Trust Company, as trustee, dated June 26, 2002.
4.2		Indenture by and among Southwest Royalties, Inc., as issuer, Southwest Royalties Holdings, Inc., as guarantor, and State Street Bank and Trust Company, as trustee, dated October 14, 1997.
4.2	(a)	First Supplemental Indenture, by and among Southwest Royalties, Inc., State Street Bank and Trust Company, and Southwest Royalties Holdings, Inc., dated April 19, 2002.
4.3		Note Exchange Agreement, by and among Southwest Royalties, Inc. and Certain Holders of the Company’s 10½% Senior Notes due 2004, dated April 19, 2002.
4.4		Stockholders Agreement by and among Southwest Royalties, Inc., Southwest Royalties Holdings, Inc., H.H. Wommack III, and Certain Other Stockholders of Southwest Royalties, Inc., dated April 19, 2002.
*4.5		Form of Certificate of Common Stock, par value $.01 per share, of Southwest Royalties, Inc.

II-2

Exhibit Number		Description
*5.1		Opinion of Baker, Donelson, Bearman & Caldwell, P.C., regarding the legality of the securities being registered
*8.1		Opinion of Baker, Donelson, Bearman & Caldwell, P.C., regarding tax matters
10.1		Senior Credit Agreement, by and among Southwest Royalties, Inc., as Borrower, and Union Bank of California, N.A. and the Institutions named within, as Lenders, Union Bank of California, N.A., as Administrative Agent, FBR Asset Investment Corporation, as Syndication Agent, Union Bank of California, N.A., as Documentation Agent, and Friedman, Billings, Ramsey & Co., Inc. as Lead Arranger and Bookrunner, dated April 19, 2002.
10.1	(a)	Collateral Trust and Intercreditor Agreement, dated as of April 19, 2002, made and entered into by and among Southwest Royalties, Inc., Blue Heel Company, Wilmington Trust Company, as Trustee for itself and the holders from time to time of those certain notes issued by the Company pursuant to the Indenture of even date herewith, Union Bank of California, N.A. as Agent for itself and the lenders signatory to the Credit Agreement from time to time and Union Bank of California, N.A., as Collateral Trustee thereunder.
10.2		Employment Agreement, dated October 1, 2002 by and between Southwest Royalties, Inc. and Bill E. Coggin, Executive Vice President and Chief Financial Officer
10.3		Employment Agreement, dated October 1, 2002 by and between Southwest Royalties, Inc. and H.H. Wommack, III, President and Chief Executive Officer
10.4		Employment Agreement, dated October 1, 2002 by and between Southwest Royalties, Inc. and J. Steven Person, Vice President-Marketing
10.5		Severance Compensation Agreement, dated December 7, 1999, by and between Southwest Royalties, Inc. and R. Douglas Keathley, Vice President, Operations
10.6		Severance Compensation Agreement, dated December 7, 1999, by and between Southwest Royalties, Inc. and Jon P. Tate, Vice President, Land
21		List of Subsidiaries of Southwest Royalties, Inc.
*23.1		Consent of Baker, Donelson, Bearman & Caldwell, P.C. (included in the opinions filed as Exhibits 5.1 and 8.1 to this Registration Statement)
23.2		Consent of KPMG, LLP, independent accountants
23.3		Consent of Friedman, Billings, Ramsey & Co., Inc.
23.4		Consent of Ryder Scott & Co., P.E.
99.1		Form of Opinion of Friedman, Billings, Ramsey & Co., Inc. (included as Appendix E to the prospectus/proxy statement forming a part of this Registration Statement)
*99.2		Form of Proxy for Special Meeting of Limited Partners of each of 21 Limited Partnerships
*99.3		Form of Written Consent of Stockholders of Southwest Consolidated Partnerships, Inc.

* To be filed by amendment.

II-3

Item 22.    Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of Southwest pursuant to the foregoing provisions, or otherwise, Southwest has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities, other than the payment by Southwest of expenses incurred or paid by a director, officer or controlling person of Southwest in the successful defense of any action, suit or proceeding, is asserted by such director, officer or controlling person in connection with the securities being registered, Southwest will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

Southwest hereby undertakes:

(1) That, for purposes of determining any liability under the Securities Act of 1933, each filing of Southwest’s annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(2) That prior to any public reoffering of the securities registered hereunder through use of a prospectus which is a part of this registration statement by any person or party who is deemed to be an underwriter within the meaning of Rule 145(c), Southwest undertakes that such reoffering prospectus will contain the information called for by the applicable registration form with respect to reofferings by persons who may be deemed underwriters, in addition to the information called for by the other items of the applicable form;

(3) That every prospectus: (a) that is filed pursuant to paragraph (3) immediately preceding, or (b) that purports to meet the requirements of Section 10(a)(3) of the Securities Exchange Act of 1934 and is used in connection with an offering of securities subject to Rule 15, will be filed as a part of an amendment to the registration statement and will not be used until such amendment is effective, and that, for purposes of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof;

(4) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11 or 13 of this Form S-4, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request; and

(5) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Southwest Royalties, Inc. has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, State of Texas, on October 16, 2002.

SOUTHWEST ROYALTIES, INC.
By:	/s/    H.H. WOMMACK, III
	H.H. Wommack, III Chairman of the Board of Directors, President, Chief Executive Officer

POWER OF ATTORNEY FOR SOUTHWEST ROYALTIES, INC.

Each person whose signature appears below hereby appoints H. H. Wommack, III and Bill E. Coggin or either of them, as his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to execute in the name of each such person who is then an officer or director of Southwest Royalties, Inc. and to file any amendments (including post-effective amendments) to this registration statement and any registration statement for the same offering filed pursuant to Rule 462 under the Securities Act of 1933, and to file the same, with all exhibits thereto and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing appropriate or necessary to be done, as fully and for all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/    H.H. WOMMACK, III H.H. Wommack, III	Chairman of the Board of Directors, President and Chief Executive Officer and Director (principal executive officer)	October 16, 2002
/s/    BILL E. COGGIN Bill E. Coggin	Chief Financial Officer and Vice President (principal financial officer)	October 16, 2002
/s/    JAMES N. CHAPMAN James N. Chapman	Director	October 16, 2002
/s/    WILLIAM P. NICOLETTI William P. Nicoletti	Director	October 16, 2002
/s/    JOSEPH J. RADECKI, JR. Joseph J. Radecki, Jr.	Director	October 16, 2002
/s/    RICHARD D. RINEHART Richard D. Rinehart	Director	October 16, 2002
/s/    JOHN M. WHITE John M. White	Director	October 16, 2002
/s/    HERBERT C. WILLIAMSON, III Herbert C. Williamson, III	Director	October 16, 2002

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, Southwest Royalties, Inc. has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, State of Texas, on October 16, 2002.

SOUTHWEST CONSOLIDATED PARTNERSHIPS, INC.
By:	/s/    H.H. WOMMACK, III
	H.H. Wommack, III

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/    H.H. WOMMACK, III H.H. Wommack, III	President and Chief Executive Officer and Director (principal executive officer)	October 16, 2002
/s/    BILL E. COGGIN Bill E. Coggin	Chief Financial Officer and Vice President and Director (principal financial officer)	October 16, 2002

INDEX TO EXHIBITS

Exhibit Number		Description
2.1		Form of Merger Agreement by and among Southwest Consolidated Partnerships, Inc., Southwest Royalties, Inc. and the limited partnerships named therein, dated as of                     , 2002 (included as Appendix C to the prospectus/proxy statement forming a part of this Registration Statement)
2.2		Form of Merger Agreement by and among Southwest Consolidated Partnerships, Inc., Southwest Managed Assets, Inc. and Southwest Royalties, Inc., dated as of                             , 2002 (included as Appendix D to the prospectus/proxy statement forming a part of this Registration Statement)
3.1		Amended and Restated Certificate of Incorporation of Southwest Royalties, Inc., as filed with the Delaware Secretary of State on April 19, 2002.
*3.1	(a)	Form of Amendment to the Amended and Restated Certificate of Incorporation of Southwest Royalties, Inc.
3.2		Amended and Restated Bylaws of Southwest Royalties, Inc.
4.1		Indenture, by and among Southwest Royalties, Inc., as issuer, Southwest Royalties Holdings, Inc., Blue Heel Company and MRO Holdings, Inc., each as a guarantor, and Wilmington Trust Company, as trustee, dated April 19, 2002.
4.1	(a)	First Supplemental Indenture, by and among Southwest Royalties, Inc., as issuer, Southwest Royalties Holdings, Inc., as guarantor, MRO Holdings, Inc., as guarantor, and Wilmington Trust Company, as trustee, dated June 26, 2002.
4.2		Indenture by and among Southwest Royalties, Inc., as issuer, Southwest Royalties Holdings, Inc., as guarantor, and State Street Bank and Trust Company, as trustee, dated October 14, 1997.
4.2	(a)	First Supplemental Indenture, by and among Southwest Royalties, Inc., State Street Bank and Trust Company, and Southwest Royalties Holdings, Inc., dated April 19, 2002.
4.3		Note Exchange Agreement, by and among Southwest Royalties, Inc. and Certain Holders of the Company’s 10½% Senior Notes due 2004, dated April 19, 2002.
4.4		Stockholders Agreement by and among Southwest Royalties, Inc., Southwest Royalties Holdings, Inc., H.H. Wommack III, and Certain Other Stockholders of Southwest Royalties, Inc., dated April 19, 2002.
*4.5		Form of Certificate of Common Stock, par value $.01 per share, of Southwest Royalties, Inc.
*5.1		Opinion of Baker, Donelson, Bearman & Caldwell, P.C., regarding the legality of the securities being registered
*8.1		Opinion of Baker, Donelson, Bearman & Caldwell, P.C., regarding tax matters
10.1		Senior Credit Agreement, by and among Southwest Royalties, Inc., as Borrower, and Union Bank of California, N.A. and the Institutions named within, as Lenders, Union Bank of California, N.A., as Administrative Agent, FBR Asset Investment Corporation, as Syndication Agent, Union Bank of California, N.A., as Documentation Agent, and Friedman, Billings, Ramsey & Co., Inc. as Lead Arranger and Bookrunner, dated April 19, 2002.
10.1	(a)	Collateral Trust and Intercreditor Agreement, dated as of April 19, 2002, made and entered into by and among Southwest Royalties, Inc., Blue Heel Company, Wilmington Trust Company, as Trustee for itself and the holders from time to time of those certain notes issued by the Company pursuant to the Indenture of even date herewith, Union Bank of California, N.A. as Agent for itself and the lenders signatory to the Credit Agreement from time to time and Union Bank of California, N.A., as Collateral Trustee thereunder.
10.2		Employment Agreement, dated October 1, 2002 by and between Southwest Royalties, Inc. and Bill E. Coggin, Executive Vice President and Chief Financial Officer

Exhibit Number	Description
10.3	Employment Agreement, dated October 1, 2002 by and between Southwest Royalties, Inc. and H.H. Wommack, III, President and Chief Executive Officer
10.4	Employment Agreement, dated October 1, 2002 by and between Southwest Royalties, Inc. and J. Steven Person, Vice President, Marketing
10.5	Severance Compensation Agreement, dated December 7, 1999, by and between Southwest Royalties, Inc. and R. Douglas Keathley, Vice President, Operations
10.6	Severance Compensation Agreement, dated December 7, 1999, by and between Southwest Royalties, Inc. and Jon P. Tate, Vice President, Land
21	List of Subsidiaries of Southwest Royalties, Inc.
*23.1	Consent of Baker, Donelson, Bearman & Caldwell, P.C. (included in the opinions filed as Exhibits 5.1 and 8.1 to this Registration Statement)
23.2	Consent of KPMG, LLP, independent accountants
23.3	Consent of Friedman, Billings, Ramsey & Co., Inc.
23.4	Consent of Ryder Scott & Co., P.E.
99.1	Form of Opinion of Friedman, Billings, Ramsey & Co., Inc. (included as Appendix E to the prospectus/proxy statement forming a part of this Registration Statement)
*99.2	Form of Proxy for Special Meeting of Limited Partners of each of 21 Limited Partnerships
*99.3	Form of Written Consent of Stockholders of Southwest Consolidated Partnerships, Inc.

* To be filed by amendment.