-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, EK3REdeI6oaZAUFy3sNyzoxMHuP8d+U2XQjgiH/iAEEd+HsYeWAkPc5L1h/VnCUN ngPIQr4We7/EQM+PtQCViA== 0000887438-99-000001.txt : 19990331 0000887438-99-000001.hdr.sgml : 19990331 ACCESSION NUMBER: 0000887438-99-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWEST OIL & GAS INCOME FUND XI-A LP CENTRAL INDEX KEY: 0000887438 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752427267 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-21844 FILM NUMBER: 99578381 BUSINESS ADDRESS: STREET 1: 407 N BIG SPRING STE 300 STREET 2: C/O SOUTHWEST OIL & GAS 1992-93 INCOME CITY: MIDLAND STATE: TX ZIP: 79701 BUSINESS PHONE: 9146869927 MAIL ADDRESS: STREET 1: 407 N BIG SPRING STREET SUITE 300 CITY: MIDLAND STATE: TX ZIP: 79701 10-K 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 (Mark One) [x] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 [Fee Required] For the fiscal year ended December 31, 1998 OR [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 [No Fee Required] For the transition period from to Commission File Number 33-47667-01 Southwest Oil & Gas Income Fund XI-A, L.P. (Exact name of registrant as specified in its limited partnership agreement) Delaware 75-2427267 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 407 N. Big Spring, Suite 300, Midland, Texas 79701 (Address of principal executive office) (Zip Code) Registrant's telephone number, including area code (915) 686-9927 Securities registered pursuant to Section 12(b) of the Act None Securities registered pursuant to Section 12(g) of the Act: limited partnership interests Indicate by check mark whether registrant (1) has filed reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes x No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x] The registrant's outstanding securities consist of Units of limited partnership interests for which there exists no established public market from which to base a calculation of aggregate market value. The total number of pages contained in this report is __. There is no exhibit index. Table of Contents Item Page Part I 1. Business 3 2. Properties 7 3. Legal Proceedings 10 4. Submission of Matters to a Vote of Security Holders 10 Part II 5. Market for Registrant's Common Equity and Related Stockholder Matters 11 6. Selected Financial Data 12 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 13 8. Financial Statements and Supplementary Data 22 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 39 Part III 10. Directors and Executive Officers of the Registrant 40 11. Executive Compensation 43 12. Security Ownership of Certain Beneficial Owners and Management 43 13. Certain Relationships and Related Transactions 45 Part IV 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 46 Signatures 47 Part I Item 1. Business General Southwest Oil & Gas Income Fund XI-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on May 5, 1992. The offering of limited partnership interests began on August 20, 1992, as part of a shelf offering registered under the name of Southwest Oil & Gas 1992-93 Income Program, reached minimum capital requirements on March 17, 1993 and concluded April 30, 1993. The Partnership has no subsidiaries. The Partnership has acquired interests in producing oil and gas properties and produced and marketed the crude oil and natural gas produced from such properties. In most cases, the Partnership 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 Partnership purchased either all or part of the rights and obligations under various oil and gas leases. The principal executive offices of the Partnership are located at 407 N. Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner of the Partnership, Southwest Royalties, Inc. (the "Managing General Partner") and its staff of 98 individuals, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of oil and gas properties and the marketing of production from such properties. H. H. Wommack, III, a stockholder, director, President and Treasurer of the Managing General Partner, is also a general partner. The Partnership has no employees. Principal Products, Marketing and Distribution The Partnership has acquired and holds royalty interests and working interests in oil and gas properties located in Alabama, Kansas, Louisiana, New Mexico, Oklahoma and Texas. All activities of the Partnership 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. The revenues generated from the Partnership's oil and gas activities are dependent upon the current market for oil and gas. The prices received by the Partnership for its oil and gas production depend upon numerous factors beyond the Partnership's 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 1998 oil prices fell to their lowest daily levels since 1986 and to their lowest annual average since 1976. In two years, oil prices have been sliced by more than half. The factors that started the decline in oil prices in 1997 are the same ones that have kept them down in 1998. It was believed that there would be continued heavy consumption coming from the Asian region, but the collapse of their markets late in 1997 carried over to this year bringing demand down with it. Asian consumption had all but disappeared in 1998, creating an oversupply of crude oil on the market. That drop in demand has lasted longer than anyone had anticipated, but hopes of a recovery abound. Another reason for the continued drop in prices has been OPEC's unwillingness to completely comply with production cuts established in March and again in June. Although they have been near 90% compliance at times, they have also been below 70% on a monthly basis. Even a four-day bombing in December of Iraqi military sites could create only a one-day rally in oil prices. Crude oil closed December 31, 1998 at $12.05 per barrel on the NYMEX and posted prices closed at $9.50 per barrel. In a year of fairly optimistic expectations for gas prices, the average price of natural gas wound up declining in 1998 to its lowest level since 1995. Although the nationwide average did remain above $2.00 per MMBTU, 1998's prices were approximately 17% lower than those seen in 1997. The combination of mild weather throughout the year and a gas storage surplus both contributed to the low prices. Analysts' predictions for 1999 prices vary, ranging from a low of $1.87 per MMBTU to a high of $2.40 per MMBTU. Reduced production throughout the U.S. industry, along with large gas storage withdrawals during the first weeks of January 1999, are both key factors in our belief that the 1999 average gas price will remain around $1.80 per MMBTU level. Following is a table of the ratios of revenues received from oil and gas production for the last three years: Oil Gas 1998 40% 60% 1997 48% 52% 1996 49% 51% As the table indicates, the Partnership's revenue is almost evenly divided between its oil and gas production; therefore, Partnership revenues will be highly dependent upon the future prices and demands for oil and gas. Seasonality of Business Although the demand for natural gas is highly seasonal, with higher demand in the colder winter months and in very hot summer months, the Partnership has been able to sell all of its 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 Partnership have not fluctuated materially with the change of season. Customer Dependence 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 54% of the Partnership's total oil and gas production during 1998: Southwestern Energy Production Co. for 20%, Nustar Joint Venture for 13%, American Processing for 11% and Phillips 66 Company for 10%. Two purchasers accounted for 27% of the Partnership's total oil and gas production during 1997: Southwestern Energy Production Co. for 15%, and American Processing for 12%. Four purchasers accounted for 49% of the Partnership's total oil and gas production during 1996: Torch Operating Company for 13%, Southwestern Energy Production Company for 13%, Scurlock Permian Corporation for 13% and American Processing 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. Competition Because the Partnership has utilized all of its funds available for the acquisition of interests in producing oil and gas properties or drilling operations, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties. Factors that may adversely affect the Partnership 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 regulation. 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 Partnership's oil and gas activities will be 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 Partnership may sell its 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 Partnership's oil and gas activities will be 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. The Managing General Partner is unable to predict what, if any, effect compliance will have on the Partnership. 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 Partnership is subject to these guidelines which regulate and restrict transactions between the Managing General Partner and the Partnership. The Partnership complies with these guidelines and the Managing General Partner does not anticipate that continued compliance will have a material adverse effect on Partnership operations. Partnership Employees The Partnership has no employees; however, 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 Partnership as needed. In addition to the Managing General Partner's staff, the Partnership engages independent consultants such as petroleum engineers and geologists as needed. As of December 31, 1998, there were 98 individuals directly employed by the Managing General Partner in various capacities. In determining whether an interest in a particular producing property was to be acquired, 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. Item 2. Properties In determining whether an interest in a particular producing property was to be acquired, 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. As of December 31, 1998, the Partnership possessed an interest in oil and gas properties located in Escambia and Lamar Counties of Alabama; Labette and Neosho Counties of Kansas; La Fourche, Pointe Coupe and Terrebonne Parishes of Louisiana; Eddy County of New Mexico; Custer, Roger Mills and Washita Counties of Oklahoma; and Dickens, Hemphill, Live Oak, Upton, Ward, Winkler and Yoakum Counties of Texas. These properties consist of various interests in 101 wells and units. Due to the Partnership's objective of maintaining current operations without engaging in the drilling of any developmental or exploratory wells, or additional acquisitions of producing properties, there have not been any significant changes in properties during 1998, 1997 and 1996. During 1998, fifty-six leases were sold for approximately $55,900. During 1997, four leases were sold for approximately $38,500. During 1996, four leases were sold for approximately $6,200. On October 15, 1998, Southwest Oil & Gas Income Fund XI-A (the "Registrant") sold its interest in 53 oil and gas properties to Parks & Luttrell, Inc. ("Parks"), an unrelated party. The Registrant's interest in the properties was sold for net proceeds, after post closing adjustments, of $49,703. At December 31, 1997, the property sold to Parks & Luttrell contained proved reserves of 15,402 barrels of oil and 113,519 mcfs of gas and had a SEC 10 value of $95,033 at the time of sale. The proceeds from the sale represented 8.79% of the Registrant's total assets. The General Partner sold the above properties and allocated the proceeds to the Partnership based on current cash flows of the properties sold. Significant Properties The following table reflects the significant properties in which the Partnership has an interest: Date Purchased No. of Proved Reserves* Name and Location and Interest Wells Oil (bbls) Gas (mcf) Custer & Wright 11/94 at 28 2,000 137,000 Winkler County, 5% to 18% Texas working interest Webb 5/94 at 10% 4 14,000 4,000 Yoakum County, Texas working interest Midland Southwest 5/94 at 5 1,000 61,000 Various Counties in .02% to 33% Alabama, Texas working interest Louisiana, Kansas and Oklahoma *Ryder Scott Company Petroleum Engineers prepared the reserve and present value data for 96.4% of the Partnership's existing properties as of January 1, 1999. Another independent petroleum engineer prepared the remaining 3.6% of the Partnership's properties. 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 New York Mercantile Exchange price at December 31, 1998 of $12.05 was used as the beginning basis for the oil price. Oil price adjustments from $12.05 per barrel were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results are an average price received at the lease of $9.17 per barrel in the preparation of the reserve report as of January 1, 1999. In the determination of the gas price, the New York Mercantile Exchange price at December 31, 1998 of $1.95 was used as the beginning basis. Gas price adjustments from $1.95 per Mcf were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results are an average price received at the lease of $1.59 per Mcf in the preparation of the reserve report as of January 1, 1999. As also discussed in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, oil and gas prices were subject to frequent changes in 1998. 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 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. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. Item 3. Legal Proceedings There are no material pending legal proceedings to which the Partnership is a party. Item 4. Submission of Matters to a Vote of Security Holders No matter was submitted to a vote of security holders during the fourth quarter of 1998 through the solicitation of proxies or otherwise. Part II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters Market Information Limited partnership interest, or units, in the Partnership were initially offered and sold for a price of $500. Limited partner units are not traded on any exchange and there is no public or organized trading market for them. Further, a transferee may not become a substitute limited partner without the consent of the Managing General Partner. 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. In 1998, 20 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $100.64 per unit. As of December 31, 1997 and 1996 no limited partner units were purchased by the Managing General Partner. Number of Limited Partner Interest Holders As of December 31, 1998, there were 121 holders of limited partner units in the Partnership. Distributions Pursuant to Article III, Section 3.05 of the Partnership's Certificate and Agreement of Limited Partnership, "Net Cash Flow" shall be distributed to the partners on a monthly basis. "Net Cash Flow" is defined as "the cash generated by the Partnership's investments in producing oil and gas properties, less (i) General and Administrative Costs, (ii) Direct Costs, (iii) Operating Costs, and (iv) any reserves necessary to meet current and anticipated needs of the Partnership, as determined in the sole discretion of the Managing General Partner." During 1998, distributions were made totaling $88,784, with $81,484 distributed to the limited partners and $7,300 to the general partners. For the year ended December 31, 1998, distributions of $28.88 per limited partner unit were made, based upon 2,821 limited partner units outstanding. The decline in distributions experienced in 1998 will be expected to continue into 1999 based on the continued low oil price economy. During 1997, twelve monthly distributions were made totaling $204,862, with $187,462 distributed to the limited partners and $17,400 to the general partners. For the year ended December 31, 1997, distributions of $66.45 per limited partner unit were made, based upon 2,821 limited partner units outstanding. During 1996, twelve monthly distributions were made totaling $272,481, with $245,481 distributed to the limited partners and $27,000 to the general partners. For the year ended December 31, 1996, distributions of $87.02 per limited partner unit were made, based upon 2,821 limited partner units outstanding. Item 6. Selected Financial Data The following selected financial data for the years ended December 31 1998, 1997, 1996, 1995 and 1994 should be read in conjunction with the financial statements included in Item 8: Years ended December 31, ----------------------------------------- 1998 1997 1996 1995 1994 ---- ---- ---- ---- ---- Revenues $ 220,239 410,305 526,824 444,900 198,424 Net income (loss) (266,080) 23,326 169,369 41,317 (2,155) Partners' share of net income (loss): General partner 4,752 15,635 27,739 17,534 3,812 Limited partners (270,832) 7,691 141,630 23,783 (5,967) Limited partners' net income (loss) per unit (96.01) 2.73 50.21 8.43 (2.12) Limited partners' cash distribution per unit 28.88 66.45 87.02 85.26 8.93 Total assets $ 359,095 713,997 895,495 998,607 1,223,349 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations General Southwest Oil & Gas Income Fund XI-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on May 5, 1992. The offering of limited partnership interests began on August 20, 1992 as part of a shelf offering registered under the name of Southwest Oil & Gas 1992-93 Income Program. Minimum capital requirements for the Partnership were met on March 17, 1993 and the Offering Period terminated April 30, 1993 with 120 limited partners purchasing 2,821 units for $1,410,500. The Partnership was formed to acquire 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 will not be reinvested in other revenue producing assets except to the extent that producing facilities and wells are reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves. The economic life of the Partnership will thus depend on the period over which the Partnership's oil and gas reserves are economically recoverable. Increases or decreases in Partnership 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, offset drilling activities pursuant to farm-out arrangements 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. Based on current conditions, management anticipates performing no workovers during 1999 to enhance production. With expected price improvement, workovers may be performed in the year 2001. The partnership may have an increase in the year 2001, otherwise, the Partnership will most likely experience it's historical decline of approximately 10% per year. Results of Operations A. General Comparison of the Years Ended December 31, 1998 and 1997 The following table provides certain information regarding performance factors for the years ended December 31, 1998 and 1997: Year Ended Percentage December 31, Increase 1998 1997 (Decrease) ---- ---- --------- Average price per barrel of oil $ 11.65 18.63 (37%) Average price per mcf of gas $ 1.85 2.27 (19%) Oil production in barrels 7,600 10,500 (28%) Gas production in mcf 70,600 94,000 (25%) Gross oil and gas revenue $ 219,347 408,579 (46%) Net oil and gas revenue $ 74,837 182,714 (59%) Partnership distributions $ 88,784 204,862 (57%) Limited partner distributions $ 81,484 187,462 (57%) Per unit distribution to limited partners $ 28.88 66.45 (57%) Number of limited partner units 2,821 2,821 Revenues The Partnership's oil and gas revenues decreased to $219,347 from $408,579 for the years ended December 31, 1998 and 1997, respectively, a decrease of 46%. The principal factors affecting the comparison of the years ended December 31, 1998 and 1997 are as follows: 1. The average price for a barrel of oil received by the Partnership decreased during the year ended December 31, 1998 as compared to the year ended December 31, 1997 by 37%, or $6.98 per barrel, resulting in a decrease of approximately $73,300 in revenues. Oil sales represented 40% of total oil and gas sales during the year ended December 31, 1998 as compared to 48% during the year ended December 31, 1997. The average price for an mcf of gas received by the Partnership decreased during the same period by 19%, or $.42 per mcf, resulting in a decrease of approximately $39,500 in revenues. The total decrease in revenues due to the change in prices received from oil and gas production is approximately $112,800. 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 2,900 barrels or 28% during the year ended December 31, 1998 as compared to the year ended December 31, 1997, resulting in a decrease of approximately $33,800 in revenues. Gas production decreased approximately 23,400 mcf or 25% during the same period, resulting in a decrease of approximately $43,300 in revenues. The total decrease in revenues due to the change in production is approximately $77,100. The decline in oil and gas production is due primarily to property sales. Costs and Expenses Total costs and expenses increased to $486,319 from $386,979 for the years ended December 31, 1998 and 1997, respectively, an increase of 26%. The increase is the result of higher general and administrative expense and provision for impairment, partially offset by a decrease in lease operating costs and depletion expense. 1. Lease operating costs and production taxes were 36% lower, or approximately $81,400 less during the year ended December 31, 1998 as compared to the year ended December 31, 1997. Lease operating costs decline primarily due to property sales and the decrease in oil prices which has made it uneconomical to perform workovers. 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 $100 during the year ended December 31, 1998 as compared to the year ended December 31, 1997. 3. Depletion expense decreased to $123,000 for the year ended December 31, 1998 from $126,000 for the same period in 1997. This represents a decrease of 2%. 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 the Partnership's independent petroleum consultants. A contributing factor to the decrease in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine the Partnership's reserves for January 1, 1998 as compared to 1997. 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 increased depletion expense approximately $9,000 as of December 31, 1997. 4. The Partnership reduced the net capitalized costs of oil and gas properties by $189,555. This provision for impairment had the effect of reducing net income, but did not affect cash flow or partner distributions. See Summary of Significant Accounting Policies - Oil and Gas Properties. Results of Operations B. General Comparison of the Years Ended December 31, 1997 and 1996 The following table provides certain information regarding performance factors for the years ended December 31, 1997 and 1996: Year Ended Percentage December 31, Increase 1997 1996 (Decrease) ---- ---- --------- Average price per barrel of oil $ 18.63 20.67 (10%) Average price per mcf of gas $ 2.27 2.30 (1%) Oil production in barrels 10,500 12,500 (16%) Gas production in mcf 94,000 116,500 (19%) Gross oil and gas revenue $ 408,579 525,888 (22%) Net oil and gas revenue $ 182,714 304,762 (40%) Partnership distributions $ 204,862 272,481 (25%) Limited partner distributions $ 187,462 245,481 (24%) Per unit distribution to limited partners $ 66.45 87.02 (24%) Number of limited partner units 2,821 2,821 Revenues The Partnership's oil and gas revenues decreased to $408,579 from $525,888 for the years ended December 31, 1997 and 1996, respectively, a decrease of 22%. The principal factors affecting the comparison of the years ended December 31, 1997 and 1996 are as follows: 1. The average price for a barrel of oil received by the Partnership decreased during the year ended December 31, 1997 as compared to the year ended December 31, 1996 by 10%, or $2.04 per barrel, resulting in a decrease of approximately $25,500 in revenues. Oil sales represented 48% of total oil and gas sales during the year ended December 31, 1997 as compared to 49% during the year ended December 31, 1996. The average price for an mcf of gas received by the Partnership decreased during the same period by 1%, or $.03 per mcf, resulting in a decrease of approximately $3,500 in revenues. The total decrease in revenues due to the change in prices received from oil and gas production is approximately $29,000. 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 2,000 barrels or 16% during the year ended December 31, 1997 as compared to the year ended December 31, 1996, resulting in a decrease of approximately $37,300 in revenues. Gas production decreased approximately 22,500 mcf or 19% during the same period, resulting in a decrease of approximately $51,100 in revenues. The total decrease in revenues due to the change in production is approximately $88,400. Decrease is primarily due to a well being shut- in for 30 days and normal decline. Costs and Expenses Total costs and expenses increased to $386,979 from $357,455 for the years ended December 31, 1997 and 1996, respectively, an increase of 8%. The increase is the result of higher lease operating costs and depletion expense. 2. Lease operating costs and production taxes were 2% higher, or approximately $4,700 more during the year ended December 31, 1997 as compared to the year ended December 31, 1996. 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 year ended December 31, 1997 as compared to the year ended December 31, 1996. 3. Depletion expense increased to $126,000 for the year ended December 31, 1997 from $101,000 for the same period in 1996. This represents an increase 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 the Partnership's independent petroleum consultants. A contributing factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine the Partnership's reserves for January 1, 1998 as compared to 1997. 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 increased depletion expense approximately $36,000 as of December 31, 1996. C. Revenue and Distribution Comparison Partnership income (loss) for the years ended December 31, 1998, 1997 and 1996 was $(266,080), $23,326 and $169,369, respectively. Excluding the effects of depreciation, depletion, amortization and provision for impairment, net income would have been $47,519 in 1998, $156,346 in 1997 and $277,389 in 1996. Correspondingly, Partnership distributions for the years ended December 31, 1998, 1997 and 1996 were $88,784, $204,862 and $272,481, respectively. These differences are indicative of the changes in oil and gas prices, production and property sales. The sources for the 1998 distributions of $88,784 were oil and gas operations of approximately $73,100 and the change in oil and gas properties of approximately $46,200, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1997 distributions of $204,862 were oil and gas operations of approximately $178,000 and the change in oil and gas properties of approximately $30,800, resulting in excess cash for contingencies or subsequent distributions. The sources for the 1996 distributions of $272,481 were oil and gas operations of approximately $247,100 and property sales of approximately $6,700, offset by additions to oil and gas properties of approximately $9,800, with the balance from available cash on hand at the beginning of the period. Total distributions during the year ended December 31, 1998 were $88,784 of which $81,484 was distributed to the limited partners and $7,300 to the general partners. The per unit distribution to limited partners during the same period was $28.88. Total distributions during the year ended December 31, 1997 were $204,862 of which $187,462 was distributed to the limited partners and $17,400 to the general partners. The per unit distribution to limited partners during the same period was $66.45. Total distributions during the year ended December 31, 1996 were $272,481 of which $245,481 was distributed to the limited partners and $27,000 to the general partners. The per unit distribution to limited partners during the same period was $87.02. Since inception of the Partnership, cumulative monthly cash distributions of $877,788 have been made to the partners. As of December 31, 1998, $800,738 or $283.85 per limited partner unit, has been distributed to the limited partners, representing a 57% return of the capital contributed. Liquidity and Capital Resources The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. The Partnership knows of no material change, nor does it anticipate any such change. Cash flows provided by operating activities were approximately $73,100 in 1998 compared to $178,000 in 1997 and approximately $247,100 in 1996. The primary source of the 1998 cash flow from operating activities was profitable operations. Cash flows provided by or (used in) investing activities were approximately $46,200 in 1998 compared to $30,800 in 1997 and approximately $(3,100) in 1996. The principal source of the 1998 cash flow from investing activities was the sale of oil and gas properties. Cash flows used in financing activities were approximately $88,800 in 1998 compared to $204,800 in 1997 and approximately $272,500 in 1996. The only use in financing activities was the distributions to partners. As of December 31, 1998, the Partnership had approximately $62,200 in working capital. The Managing General Partner believes the revenues generated from operations are adequate to meet the operating needs of the Partnership. Liquidity - Managing General Partner The Managing General Partner has a highly leveraged capital structure with over $21.0 million of interest payments due in 1999 on its debt obligations. Due to severely depressed commodity prices, 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. Information Systems for the Year 2000 The Managing General Partner provides all data processing needs of the Partnership. The Managing General Partner is continuing in its effort to identify and assess its exposure to the potential Year 2000 software and imbedded chip processing and date sensitivity issue. Through the Managing General Partners data processing subsidiary, Midland Southwest Software, Inc., the Managing General Partner proactively initiated a plan to identify applicable hardware and software, assess impact and effect, estimate costs, construct and implement corrective actions, and prepare contingency plans. Identification & Assessment The Managing General Partner currently believes it has identified the internal and external software and hardware that may have date sensitivity problems. Four critical systems and/or functions were identified: (1) the proprietary software of the Partnership (OGAS) that is used for oil & gas property management and financial accounting functions, (2) the DEC VAX/VMS hardware and operating system, (3) various third-party application software including lease economic analysis, fixed asset management, geological applications, and payroll/human resource programs, and (4) External Agents. The proprietary software of the Partnership is currently in process of meeting compliance requirements with an estimated completion date of mid- year 1999. Since this is an internally generated software package, the Managing General Partner has estimated the cost to be approximately $25,000 by estimating the necessary man-hours. These modifications are being made by internal staff and do not represent additional costs to the Partnership. The Managing General Partner has not made contingency plans at this time since the conversion is ahead of schedule and being handled by Managing General Partner controlled internal programmers. Given the complexity of the systems being modified, it is anticipated that some problems may arise, but with an expected early completion date, the Managing General Partner feels that adequate time is available to overcome unforeseen delays. DEC has released a fully compliant version of its operating system that is used by the Partnership on the DEC VAX system. It will be installed in August 1999, the Managing General Partner believes that this will solve any potential problems on the system. The Managing General Partner has identified various third-party software that may have date sensitivity problems and is working with the vendors to secure solutions as well as prepare contingency plans. After review and evaluation of the vendor plans and status, the Managing General Partner believes that the problems will be resolved prior to the year 2000 or the alternate contingency plan will sufficiently and adequately remediate the problem so that there is no material disruption to business functions. The External Agents of the Partnership include suppliers, customers, owners, vendors, banks, product purchasers including pipelines, and other oil and gas property operators. The Managing General Partner is in the process of identifying and communicating with each critical External Agent about its plan and progress thereof in addressing the Year 2000 issue. This process is on schedule and the Managing General Partner, at this time, believes that there should be no material interference or disruption associated with any of the critical External Agent's functions necessary to the Partnership's business. The Managing General Partner estimates completion of this audit by mid-year 1999 and believes that alternate plans can be devised to circumvent any material problems arising from critical External Agent noncompliance. Cost To date, the Managing General Partner has incurred only minimal internal man-hour costs for identification, planning, and maintenance. The Managing General Partner believes that the necessary additional costs will also be minimal and most will fall under normal and general maintenance procedures and updates. An accurate cost cannot be determined at this time, but it is expected that the total cost to remediate all systems to be less than $50,000. Risks/Contingency The failure to correct critical systems of the Partnership, or the failure of a material business partner or External Agent to resolve critical Year 2000 issues could have a serious adverse impact on the ability of the Partnership to continue operations and meet obligations. Based on the Managing General Partner's evaluation and assessment to date, it is believed that any interruption in operation will be minor and short-lived and pose no material monetary loss, safety, or environmental risk to the Partnership. However, until all assessment is complete, it is impossible to accurately identify the risks, quantify potential impacts or establish a final contingency plan. The Managing General Partner believes that its assessment and contingency planning will be complete no later than mid-year 1999. Worst Case Scenario The Securities and Exchange Commission requires that public companies must forecast the most reasonably likely worst case Year 2000 scenario, assuming that the Managing General Partner's Year 2000 plan is not effective. Analysis of the most reasonably likely worst case Year 2000 scenarios the Partnership may face leads to contemplation of the following possibilities which, though considered highly unlikely, must be included in any consideration of worst cases: widespread failure of electrical, gas, and similar supplies by utilities serving the Partnership; widespread disruption of the services of communications common carriers; similar disruption to means and modes of transportation for the Partnership and its employees, contractors, suppliers, and customers; significant disruption to the Partnership's ability to gain access to, and continue working in, office buildings and other facilities; and the failure, of third-parties systems, the effects of which would have a cumulative material adverse impact on the Partnership's critical systems. The Partnership could experience an inability by customers, traders, and others to pay, on a timely basis or at all, obligations owed to the Partnership. Under these circumstances, the adverse effect on the Partnership, and the diminution of Partnership revenues, could be material, although not quantifiable at this time. Item 8. Financial Statements and Supplementary Data Index to Financial Statements Page Independent Auditors Reports 23 Balance Sheets 25 Statements of Operations 26 Statement of Changes in Partners Equity 27 Statements of Cash Flows 28 Notes to Financial Statements 30 INDEPENDENT AUDITORS REPORT The Partners Southwest Oil & Gas Income Fund XI-A, L.P. (A Delaware Limited Partnership): We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund XI-A, L.P. (the "Partnership") as of December 31, 1998 and 1997, and the related statements of operations, changes in partners' equity and cash flows for the years then ended. 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 generally accepted auditing standards. 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 XI-A, L.P. as of December 31, 1998 and 1997 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles. KPMG LLP Midland, Texas March 18, 1999 REPORT OF INDEPENDENT ACCOUNTANTS To the Partners Southwest Oil & Gas Income Fund XI-A, L.P. Midland, Texas We have audited the accompanying statements of operations, changes in partners' equity and cash flows of Southwest Oil & Gas Income Fund XI-A, L.P. for the year ended December 31, 1996. 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 audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of operations, changes in partners equity and cash flows are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statements of operations, changes in partners equity and cash flows. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements of operations, changes in partners equity and cash flows. We believe that our audit of the statements of operations, changes in partners equity and cash flows provides a reasonable basis for our opinion. In our opinion, the statements of operations, changes in partners equity and cash flows referred to above present fairly, in all material respects, the results of operations and cash flows of Southwest Oil & Gas Income Fund XI-A, L.P. for the year ended December 31, 1996, in conformity with generally accepted accounting principals. JOSEPH DECOSIMO AND COMPANY A Tennessee Registered Limited Liability Partnership Chattanooga, Tennessee March 14, 1997 Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 1998 and 1997 1998 1997 ---- ---- Assets Current assets: Cash and cash equivalents $ 34,874 4,368 Receivable from Managing General Partner 27,378 52,943 Account Receivable - 1,650 - --------- --------- Total current assets 62,252 58,961 - --------- --------- Oil and gas properties - using the full- cost method of accounting 1,017,398 1,061,992 Less accumulated depreciation, depletion and amortization 720,555 408,000 - --------- --------- Net oil and gas properties 296,843 653,992 - --------- --------- Organization costs, net of amortization of $33,930 in 1997 - 1,044 - --------- --------- $ 359,095 713,997 ========= ========= Liabilities and Partners' Equity Current liabilities - Distributions payable $ - 38 - --------- -------- Partners' equity: General partners (7,892) (5,344) Limited partners 366,987 719,303 - --------- --------- Total partners' equity 359,095 713,959 - --------- --------- $ 359,095 713,997 ========= ========= The accompanying notes are an integral part of these financial statements. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 1998, 1997 and 1996 1998 1997 1996 ---- ---- ---- Revenues Oil and gas revenues $ 219,347 408,579 525,888 Interest income from operations 892 1,726 936 ------- - ------- ------- 220,239 410,305 526,824 ------- - ------- ------- Expenses Production 144,510 225,865 221,126 General and administrative 28,210 28,094 28,309 Depreciation, depletion and amortization 124,044 133,020 108,020 Provision for impairment of oil and gas properties 189,555 - - ------- - ------- ------- 486,319 386,979 357,455 ------- - ------- ------- Net income (loss) $ (266,080) 23,326 169,369 ======= ======= ======= Net income (loss) allocated to: Managing General Partner $ 4,277 14,071 24,965 ======= ======= ======= General Partner $ 475 1,564 2,774 ======= ======= ======= Limited partners $ (270,832) 7,691 141,630 ======= ======= ======= Per limited partner unit $ (96.01) 2.73 50.21 ======= ======= ======= The accompanying notes are an integral part of these financial statements. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 1998, 1997 and 1996 General Limited Partners Partners Total -------- -------- ----- Balance at December 31, 1995 $ (4,318) 1,002,925 998,607 Net income 27,739 141,630 169,369 Distributions (27,000) (245,481)(272,481) ------- - --------- --------- Balance at December 31, 1996 (3,579) 899,074 895,495 Net income 15,635 7,691 23,326 Distributions (17,400) (187,462)(204,862) ------- - --------- --------- Balance at December 31, 1997 (5,344) 719,303 713,959 Net income (loss) 4,752 (270,832)(266,080) Distributions (7,300) (81,484) (88,784) ------- - --------- --------- Balance at December 31, 1998 $ (7,892) 366,987 359,095 ======= ========= ========= The accompanying notes are an integral part of these financial statements. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 1998, 1997 and 1996 1998 1997 1996 ---- ---- ---- Cash flows from operating activities: Oil and gas revenue $ 262,427 439,267 498,900 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (190,235) (263,063)(252,739) Interest received 892 1,726 936 -------- - -------- ---------- Net cash provided by operating activities 73,084 177,930 247,097 -------- - -------- ---------- Cash flows from investing activities: Sale of oil and gas properties 53,679 39,786 6,693 Additions to oil and gas properties (7,435) (8,980) (9,821) -------- - -------- ---------- Net cash provided by (used in) investing activities 46,244 30,806 (3,128) -------- - -------- ---------- Cash flows used in financing activities: Partner distributions (88,822) (204,824)(272,481) -------- - -------- ---------- Net increase (decrease) in cash and cash equivalents 30,506 3,912 (28,512) Beginning of period 4,368 456 28,968 -------- - -------- ---------- End of period $ 34,874 4,368 456 ======== ======== ========== (continued) The accompanying notes are an integral part of these financial statements. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Statements of Cash Flows, continued Years ended December 31, 1998, 1997 and 1996 1998 1997 1996 ---- ---- ---- Reconciliation of net income (loss) to net cash provided by operating activities: Net income (loss) $ (266,080) 23,326 169,369 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 124,044 133,020 108,020 Provision for impairment of oil and gas properties 189,555 - - - (Increase) decrease in receivables 43,080 30,688 (26,988) Decrease in payables (17,515) (9,104) (3,304) ------- - ------- ------- Net cash provided by operating activities $ 73,084 177,930 247,097 ======= ======= ======= Supplemental schedule of noncash investing and financing activities Oil and gas properties included in accounts receivable $ - 1,650 - The accompanying notes are an integral part of these financial statements. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 1. Organization Southwest Oil & Gas Income Fund XI-A, L.P. was organized under the laws of the state of Delaware on May 5, 1992, 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 will sell 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. Partnership profits and losses, as well as all items of income, gain, loss, deduction, or credit, will be credited or charged as follows: Limited General Partners Partners (1) -------- -------- Organization and offering expenses (2) 100% - Acquisition costs 100% - Operating costs 90% 10% Administrative costs (3) 90% 10% Direct costs 90% 10% All other costs 90% 10% Interest income earned on capital contributions 100% - Oil and gas revenues 90% 10% Other revenues 90% 10% Amortization 100% - Depletion allowances 100% - (1) H.H. Wommack, III, President of the Managing General Partner, is an additional general partner in the Partnership and has a one percent interest in the Partnership. Mr. Wommack is the majority stockholder of the Managing General Partner whose continued involvement in Partnership management is important to its operations. Mr. Wommack, as a general partner, shares also in Partnership liabilities. (2) Organization and Offering Expenses (including all cost of selling and organizing the offering) include a payment by the Partnership of an amount equal to three percent (3%) of Capital Contributions for reimbursement of such expenses. All Organization Costs (which excludes sales commissions and fees) in excess of three percent (3%) 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's revenues; however; Administrative Costs in the Partnership year in excess of two percent (2%) of Capital Contributions shall be allocated to and paid by the Managing General Partner. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 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. 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, 1998, the net capitalized cost exceeded the estimated present value of oil and gas reserves, thus an adjustment of $189,555 was made to the financial statement. As of December 31, 1997 and 1996, 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. Actual results could differ from those estimates. Organization Costs Organization costs are stated at cost and are amortized over sixty months using the straight-line method. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 2. Summary of Significant Accounting Policies - continued 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, 1998 there were no significant amounts of imbalance in terms of units and value. As of December 31, 1997 and 1996, the Partnership was over produced by 3,521 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, 1998 is $83,207, more than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles. The Partnerships tax basis in its net oil and gas properties at December 31, 1997 is $76,058, less than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 2. Summary of Significant Accounting Policies - 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, 1998 and 1997 there were 2,821 limited partner units outstanding held by 121 partners. As of December 31, 1998 there were 2,821 limited partner units outstanding held by 120 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. 3. Liquidity - Managing General Partner The Managing General Partner has a highly leveraged capital structure with over $21.0 million of interest payments due in 1999 on its debt obligations. Due to severely depressed commodity prices, 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. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 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, 1998, 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 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 $29,400, $38,600 and $42,000 for the years ended December 31, 1998, 1997 and 1996. 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 $40, $100 and $1,300 for the years ended December 31, 1998, 1997 and 1996 and the Managing General Partner believes that these costs are comparable to similar charges paid by the Partnership to unrelated third parties. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 5. Related Party Transactions - continued Southwest Royalties, Inc., the Managing General Partner, was paid $11,787, $20,000 and $19,649 for the years ended December 31, 1998, 1997 and 1996, as an administrative fee, for indirect general and administrative overhead expenses. Amounts due from Southwest Royalties, Inc. totaled $27,378 and $52,943 as of December 31, 1998 and 1997, respectively, all of which is from oil and gas production distributed to the Partnership subsequent to the end of the year. 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, 1998 and approximately $30 and $150 for the years ended December 31, 1997 and 1996. 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 54% of the Partnership's total oil and gas production during 1998: Southwestern Energy Production Co. for 20%, Nustar Joint Venture for 13%, American Processing 11% and Phillips 66 Company for 10%. Two purchasers accounted for 27% of the Partnership's total oil and gas production during 1997: Southwestern Energy Production Co. 15%, and American Processing 12%. Four purchasers accounted for 49% of the Partnership's total oil and gas production during 1996: Torch Operating Company 13%, Southwestern Energy Production Company 13%, Scurlock Permian Corporation 13% and American Processing 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. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 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, 1996 97,000 1,013,000 Revisions of previous estimates 18,000 103,000 Production (12,000) (117,000) Sale of minerals in place - (72,000) ------- --------- December 31, 1996 103,000 927,000 Revisions of previous estimates (26,000) (316,000) Production (11,000) (94,000) Sale of minerals in place (2,000) (1,000) ------- --------- December 31, 1997 64,000 516,000 Revisions of previous estimates (23,000) 15,000 Production (8,000) (71,000) Sale of minerals in place (11,000) (104,000) ------- --------- December 31, 1998 22,000 356,000 ======= ========= Proved developed reserves - December 31, 1996 102,000 894,000 ======= ========= December 31, 1997 64,000 485,000 ======= ========= December 31, 1998 22,000 353,000 ======= ========= All of the Partnership's reserves are located within the continental United States. *Ryder Scott Company Petroleum Engineers prepared the reserve and present value data for 96.4% of the Partnership's existing properties as of January 1, 1999. Another independent petroleum engineer prepared the remaining 3.6% of the Partnership's properties. 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 New York Mercantile Exchange price at December 31, 1998 of $12.05 was used as the beginning basis for the oil price. Oil price adjustments from $12.05 per barrel were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results are an average price received at the lease of $9.17 per barrel in the preparation of the reserve report as of January 1, 1999. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 7. Estimated Oil and Gas Reserves (unaudited) - continued In the determination of the gas price, the New York Mercantile Exchange price at December 31, 1998 of $1.95 was used as the beginning basis. Gas price adjustments from $1.95 per Mcf were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results are an average price received at the lease of $1.59 per Mcf in the preparation of the reserve report as of January 1, 1999. 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. Southwest Oil & Gas Income Fund XI-A, L.P. (a Delaware limited partnership) Notes to Financial Statements 8. Estimated Oil & Gas Reserves (unaudited) - continued The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1998, 1997 and 1996 is presented below: 1998 1997 1996 ---- ---- ---- Future cash inflows $ 763,000 2,128,000 5,744,000 Production and development costs 347,000 1,028,000 2,433,000 --------- --------- --------- Future net cash flows 416,000 1,100,000 3,311,000 10% annual discount for estimated timing of cash flows 119,000 381,000 1,395,000 --------- --------- --------- Standardized measure of discounted future net cash flows $ 297,000 719,000 1,916,000 ========= ========= ========= The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 1998, 1997 and 1996 are as follows: 1998 1997 1996 ---- ---- ---- Sales of oil and gas produced, net of production costs $ (75,000) (183,000) (516,000) Changes in prices and productions costs (235,000) (948,000) 1,101,000 Changes of production rates (timing) and others (8,000) 122,000 67,000 Revisions of previous quantities estimates (81,000) (377,000) (111,000) Accretion of discount 72,000 192,000 184,000 Sales of minerals in place (95,000) (3,000) (36,000) Discounted future net cash flows - Beginning of year 719,000 1,916,000 1,227,000 --------- --------- --------- End of year $ 297,000 719,000 1,916,000 ========= ========= ========= 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. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure On June 9, 1997 Southwest Royalties, Inc. the Partnership's Managing General Partner (Southwest Royalties, Inc.) dismissed Joseph Decosimo and Company as the Partnership's independent accountants. The Managing General Partner's Board of Directors approved the decision to change the Partnership's independent accountants. The report of Joseph Decosimo and Company on the financial statements for the fiscal year ended December 31, 1996 contained no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principle. In connection with its audit for the fiscal year ended December 31, 1996 and through June 9, 1997, there have been no disagreements with Joseph Decosimo and Company on any matter of accounting principles or practices, financial statements disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of Joseph Decosimo and Company would have caused them to make reference thereto in their report on the financial statements for such year. The Registrant has requested that Joseph Decosimo and Company furnish it with a letter addressed to the SEC stating whether or not is agrees with the above statements. A copy of that letter is included as Exhibit 16 and has been filed with the Securities and Exchange Commission. Part III Item 10. Directors and Executive Officers of the Registrant Management of the Partnership is provided by Southwest Royalties, Inc., as Managing General Partner. The names, ages, offices, positions and length of service of the directors and executive officers of Southwest Royalties, Inc. are set forth below. Each director and executive officer serves for a term of one year. The present directors of the Managing General Partner have served in their capacity since the Company's formation in 1983. Name Age Position - -------------------- --- ----------------------------------- - ------- H. H. Wommack, III 43 Chairman of the Board, President, Chief Executive Officer, Treasurer and Director H. Allen Corey 42 Secretary and Director Bill E. Coggin 44 Vice President and Chief Financial Officer Jon P. Tate 41 Vice President, Land and Assistant Secretary R. Douglas Keathley 43 Vice President, Operations J. Steven Person 40 Vice President, Marketing Paul L. Morris 57 Director H. H. Wommack, III, is Chairman of the Board, President, Chief Executive Officer, Treasurer, principal stockholder and a director of the Managing General Partner, and has served as its President since the Company's organization in August, 1983. Prior to the formation of the Company, Mr. Wommack was a self-employed independent oil producer engaged in the purchase and sale of royalty and working interests in oil and gas leases, and the drilling of exploratory and developmental oil and gas wells. Mr. Wommack holds a J.D. degree from the University of Texas from which he graduated in 1980, and a B.A. from the University of North Carolina in 1977. H. Allen Corey, a founder of the Managing General Partner, has served as the Managing General Partner's secretary and a director since its inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew pub restaurant chain based in the Southeast. Prior to his involvement with Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in Chattanooga, Tennessee. He is currently of counsel to the law firm of Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga, Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University Law School and B.A. degree from the University of North Carolina at Chapel Hill. Bill E. Coggin, Vice President and Chief Financial Officer, has been with the Managing General Partner since 1985. Mr. Coggin was Controller for Rod Ric Corporation of Midland, Texas, an oil and gas drilling company, during the latter part of 1984. He was Controller for C.F. Lawrence & Associates, Inc., an independent oil and gas operator also of Midland, Texas during the early part of 1984. Mr. Coggin taught public school for four years prior to his business experience. Mr. Coggin received a B.S. in Education and a B.B.A. in Accounting from Angelo State University. Jon P. Tate, Vice President, Land and Assistant Secretary, assumed his responsibilities with the Managing General Partner in 1989. Prior to joining the Managing General Partner, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as Land Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin Landman's Association and received his B.B.S. degree from Hardin-Simmons University. R. Douglas Keathley, Vice President, Operations, assumed his responsibilities with the Managing General Partner as a Production Engineer in October, 1992. Prior to joining the Managing General Partner, Mr. Keathley was employed for four (4) years by ARCO Oil & Gas Company as senior drilling engineer working in all phases of well production (1988- 1992), eight (8) years by Reading & Bates Petroleum Company as senior petroleum engineer responsible for drilling (1980-1988) and two (2) years by Tenneco Oil Company as drilling engineer responsible for all phases of drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum Engineering in 1977 from the University of Oklahoma. J. Steven Person, Vice President, Marketing, assumed his responsibilities with the Managing General Partner as National Marketing Director in 1989. Prior to joining the Managing General Partner, Mr. Person served as Vice President of Marketing for CRI, Inc., and was associated with Capital Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor University in 1982 and an M.D.A. from Houston Baptist University in 1987. Paul L. Morris has served as a Director of Southwest Royalties Holdings, Inc. since August 1998 and Southwest Royalties, Inc. since September 1998. Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest independently owned oil and gas companies in the United States. Prior to his position with Wagner & Brown, Mr. Morris served as President of Banner Energy and in various managerial positions with Columbia Gas System, Inc. Key Employees Accounting and Administrative Officer - Debbie A. Brock, age 46, assumed her position with the Managing General Partner in 1991. Prior to joining the Managing General Partner, Ms. Brock was employed with Western Container Corporation as Accounting Manager (1982-1990), Synthetic Industries (Texas), Inc. as Accounting Manager (1976-1982) and held various accounting positions in the manufacturing industry (1971-1975). Ms. Brock received a B.B.A. from the University of Houston. Controller - Robert A. Langford, age 49, assumed his responsibilities with the Managing General Partner in 1992. Mr. Langford received his B.B.A. degree in Accounting in 1975 from the University of Central Arkansas. Prior to joining the Managing General Partner, Mr. Langford was employed with Forest Oil Corporation as Corporate Coordinator, Regional Coordinator, Accounting Manager. He held various other positions from 1982-1992 and 1976-1980 and was Assistant Controller of National Oil Company from 1980- 1982. Financial Reporting Manager - Bryan Dixon, C.P.A., age 32, assumed his responsibilities with the Managing General Partner in 1992. Mr. Dixon received his B.B.A. degree in Accounting in 1988 from Texas Tech University in Lubbock, Texas. Prior to joining the Managing General Partner, Mr. Dixon was employed as a Senior Auditor with Johnson, Miller & Company from 1991-1992 and Audit Supervisor for Texas Tech University and the Texas Tech University Health Sciences Center from 1988-1991. Production Superintendent - Steve C. Garner, age 57, assumed his responsibilities with the Managing General Partner as Production Superintendent in July, 1989. Prior to joining the Managing General Partner, Mr. Garner was employed 16 years by Shell Oil Company working in all phases of oil field production as operations foreman, one and one-half years with Petroleum Corporation of Delaware as Production Superintendent, six years as an independent engineering consultant, and one year with Citation Oil & Gas Corp. as a workover, completion and production foreman. Mr. Garner has worked extensively in the Permian Basin oil field for the last 25 years. Tax Manager - Carolyn Cookson, age 42, assumed her position with the Managing General Partner in April, 1989. Prior to joining the Managing General Partner, Ms. Cookson was employed as Director of Taxes at C.F. Lawrence & Associates, Inc. from 1983 to 1989, and worked in public accounting at McCleskey, Cook & Green, P.C. from 1981 to 1983 and Deanna Brady, C.P.A. from 1980 to 1981. She is a member of the Permian Basin Chapter of the Petroleum Accountants' Society, and serves on its Board of Directors and is liaison to the Tax Committee. Ms. Cookson received a B.B.A. in accounting from New Mexico State University. Investor Relations Manager - Sandra K. Flournoy, age 52, came to Southwest Royalties, Inc. in 1988 from Parker & Parsley Petroleum, where she was Assistant Manager of Investor Services and Broker/Dealer Relations for two years. Prior to that, Ms. Flournoy was Administrative Assistant to the Superintendent at Greenwood ISD for four years. In certain instances, the Managing General Partner will engage professional petroleum consultants and other independent contractors, including engineers and geologists in connection with property acquisitions, geological and geophysical analysis, and reservoir engineering. The Managing General Partner believes that, in addition to its own "in-house" staff, the utilization of such consultants and independent contractors in specific instances and on an "as-needed" basis allows for greater flexibility and greater opportunity to perform its oil and gas activities more economically and effectively. Item 11. Executive Compensation The Partnership does not have any directors or executive officers. The executive officers of the Managing General Partner do not receive any cash compensation, bonuses, deferred compensation or compensation pursuant to any type of plan, from the Partnership. The Managing General Partner received $11,787, $20,000 and $19,649 during 1998, 1997 and 1996 as an annual administrative fee. Item 12. Security Ownership of Certain Beneficial Owners and Management There are no limited partners who own of record, or are known by the Managing General Partner, to beneficially own, more than five percent of the Partnership's limited partnership interests. The Managing General Partner owns a nine percent interest in the Partnership as a general partner. Through prior purchases, the Managing General Partner also owns 20 limited partner units, or 0.7% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 9.6%. No officer or director of the Managing Partner owns Units in the Partnership. H.H. Wommack, III, as the individual general partner of the Partnership, owns a one percent interest in the Partnership as a general partner. There are no arrangements known to the Managing General Partner which may at a subsequent date result in a change of control of the Partnership. Amount and Nature of Percent Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------------- --------------- ------- Limited Partnership Southwest Royalties, Inc. Directly Owns 9.6% Interest Managing General Partner 20 Units 407 N. Big Spring Street Midland, TX 79701 Limited Partnership H. H. Wommack, III Indirectly Owns 9.6% Interest Chairman of the Board, 20 Units President, CEO, Treasurer and Director of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701 Limited Partnership H. Allen Corey Indirectly Owns 9.6% Interest Secretary and Director of 20 Units Southwest Royalties, Inc., the Managing General Partner 633 Chestnut Street Chattanooga, TN 37450-1800 Limited Partnership Bill E. Coggin Indirectly Owns 9.6% Interest Vice President and CFO of 20 Units Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701 Limited Partnership Jon P. Tate Indirectly Owns 9.6% Interest Vice President, Land and 20 Units Assistant Secretary of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701 Limited Partnership J. Steven Person Indirectly Owns 9.6% Interest Vice President, Marketing 20 Units of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701 Limited Partnership R. Douglas Keathley Indirectly Owns 9.6% Interest Vice President,20 Units Operations of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701 Amount and Nature of Percent Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------------- --------------- ------- Limited Partnership Paul L. Morris Indirectly Owns 9.6% Interest Director of Southwest 20 Units Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701 There are no arrangements known to the Managing General Partner which may at a subsequent date result in a change of control of the Partnership. Item 13. Certain Relationships and Related Transactions In 1998, the Managing General Partner received $11,787 as an administrative fee. This amount is part of the general and administrative expenses incurred by the Partnership. In some instances the Managing General Partner and certain officers and employees may be working interest owners in an oil and gas property in which the Partnership also has a working interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $29,400 for administrative overhead attributable to operating such properties during 1998. 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 $40 for the year ended December 31, 1998. In the opinion of management, the terms of the above transactions are similar to ones with unaffiliated third parties. Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a)(1) Financial Statements: Included in Part II of this report -- Reports of Independent Accountants Balance Sheets Statements of Operations Statements of Changes in Partners' Equity Statements of Cash Flows Notes to Financial Statements (2) Schedules required by Article 12 of Regulation S- X are either omitted because they are not applicable or because the required information is shown in the financial statements or the notes thereto. (3) Exhibits: 4 (a) Certificate of Limited Partnership of Southwest Oil & Gas Income Fund XI- A, L.P., dated May 5, 1992. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1992) (b) Agreement of Limited Partnership of Southwest Oil & Gas Income Fund XI- A, L.P., dated May 5, 1992. (Incorporated by reference from the Partnership's Form 10-K for the fiscal year ended December 31, 1992) 27 Financial Data Schedule (b) Reports on Form 8-K The Partnership filed an 8-K on October 28, 1998 under Item 2 "Acquisition or Disposition of Asset." On December 15, 1998 an 8-K/A was filed concerning the disposition. Signatures Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Southwest Oil & Gas Income Fund XI-A, L.P., a Delaware limited partnership By: Southwest Royalties, Inc., Managing General Partner By: /s/ H. H. Wommack, III ----------------------------- H. H. Wommack, III, President Date: March 31, 1999 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Partnership and in the capacities and on the dates indicated. By: /s/ H. H. Wommack, III ----------------------------------- H. H. Wommack, III, Chairman of the Board, President, Chief Executive Officer, Treasurer and Director Date: March 31, 1999 By: /s/ H. Allen Corey ----------------------------- H. Allen Corey, Secretary and Director Date: March 31, 1999 EX-27 2
5 This schedule contains summary finanial information extracted from the Balance Sheet at December 31, 1998 and the Statement of Operations for the Year Ended December 31, 1998 and is qualified in its entirety by reference to such financial statements. YEAR DEC-31-1998 DEC-31-1998 34,874 0 27,378 0 0 62,252 1,017,398 720,555 359,095 0 0 0 0 0 359,095 359,095 219,347 220,239 144,510 144,510 341,809 0 0 (266,080) 0 (266,080) 0 0 0 (266,080) (96.01) (96.01)
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