-----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, Gni7crylPcwCibmwsm4lACdlOJuhOU4ptUceGqMPXqdmBGCdSSceGarra2LAt6dX Nu14UE6gICZRaz4t0uCJjg== 0000887425-00-000001.txt : 20000323 0000887425-00-000001.hdr.sgml : 20000323 ACCESSION NUMBER: 0000887425-00-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000322 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND XI-B LP CENTRAL INDEX KEY: 0000887425 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752427289 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 033-47668-02 FILM NUMBER: 575043 BUSINESS ADDRESS: STREET 1: 407 N BIG SPRING STE 300 STREET 2: C/O SOUTHWEST ROYALTIES INSTITUTIONAL CITY: MIDLAND STATE: TX ZIP: 79701 BUSINESS PHONE: 9156869927 MAIL ADDRESS: STREET 1: 407 N BIG SPRING ST 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, 1999 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 33-47668-02 Southwest Royalties Institutional Income Fund XI-B, L.P. (Exact name of registrant as specified in its limited partnership agreement) Delaware 75-2427289 (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 37. There is no exhibit index. Table of Contents Item Page Part I 1. Business 3 2. Properties 6 3. Legal Proceedings 8 4. Submission of Matters to a Vote of Security Holders 8 Part II 5. Market for Registrant's Common Equity and Related Stockholder Matters 9 6. Selected Financial Data 10 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 11 8. Financial Statements and Supplementary Data 18 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 33 Part III 10. Directors and Executive Officers of the Registrant 34 11. Executive Compensation 35 12. Security Ownership of Certain Beneficial Owners and Management 35 13. Certain Relationships and Related Transactions 36 Part IV 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 36 Signatures 37 Part I Item 1. Business General Southwest Royalties Institutional Income Fund XI-B, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on August 31, 1993. The offering of limited partnership interests began October 25, 1993, as part of a shelf offering registered under the name Southwest Royalties Institutional 1992-93 Income Program. Minimum capital requirements for the Partnership were met on December 8, 1993 and concluded August 20, 1994. The Partnership has no subsidiaries. As of December 31, 1996, the Partnership had utilized approximately $2,008,600 of limited partner capital contributions to acquire interests in oil and gas properties. All excess capital, $89,489, and the associated organization costs of $3,132, has been distributed to the limited partners in proportion to their capital contributions as a return of capital. 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 97 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 interest and net profit interests in oil and gas properties located in New Mexico 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. With some periodic exceptions, since the early 1980's, there has been a worldwide oversupply of oil; therefore, market prices have declined significantly. 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 for oil and natural gas. Oil prices experienced a year of recovery during 1999. After seeing prices languish near $10 per barrel in December 1998, a rebound occurred that would briefly push NYMEX pricing over $27 in late November 1999. Crude oil prices reached $20 per barrel in mid-July and would not fall below $21 the rest of the year. There were drastic improvements to the main factors that gave rise to the worst price depression in history. These improvements provoked a spike in crude oil prices to levels not seen since the Gulf War. First, OPEC has done a remarkable job of adhering to production cuts agreed to in March, despite the temptation to cheat given current pricing. As prices have risen over the last twelve months, OPEC has consistently maintained a compliance rate above 90 percent. Also, most foreign markets are well on their way to recovery, greatly increasing the demand for energy in those countries. These and other factors have eliminated the "oversupply" of crude oil that we experienced in 1998. The near month contract for crude oil settled at $25.60 per barrel on December 30, 1999. In 1999 natural gas prices rose 10% to an average of $2.18/MMBtu, 18 cents higher than the $2.00/MMBtu average seen in 1998. Despite warmer-than- normal heating seasons at both ends of the year, 1999 was the fourth year in a row that prices averaged $2.00/MMBtu or above. Citing lower storage levels and a rising demand for natural gas, industry experts are predicting a "healthy jump" in prices for 2000. Although higher prices in 1999 fueled an increase in production, end of year gas in storage nationwide is only 75% of capacity as compared to 87% at the end of 1998. Further, gas demand is expected to continue to increase at a faster pace than the amount of gas being replaced. A record breaking 70% of single-family homes built in 1999 were equipped with natural gas services ranging from traditional heating to water heating, cooking and grilling. Based on these encouraging statistics, we remain optimistic in our expectation of slightly higher natural gas prices in the coming year, hopefully seeing an average above the $2.20/MMBtu level. Following is a table of the ratios of revenues received from oil and gas production for the last three years: Oil Gas 1999 46% 54% 1998 46% 54% 1997 48% 52% As the table indicates, the Partnership's revenue is almost evenly divided between its oil and gas production. The 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 volume sold by the Partnership is not expected to fluctuate 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. Three purchasers accounted for 84% of the Partnership's total oil and gas production during 1999: Navajo Refining Company for 40%, Sid Richardson Gasoline Co. for 33% and Phillips 66 for 11%. Two purchasers accounted for 72% of the Partnership's total oil and gas production during 1998: Navajo Refining Company for 39% and American Processing for 33%. Two purchasers accounted for 71% of the Partnership's total oil and gas production during 1997: Navajo Refining Company, Inc. for 36%, and American Processing for 35%. 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, 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, 1999 there were 97 individuals directly employed by the Managing General Partner in various capacities. 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, 1999, the Partnership possessed an interest in oil and gas properties located in Eddy County of New Mexico; Andrews, Dawson, Howard, Midland, Reeves, Schleicher, Upton, Ward and Winkler Counties of Texas. These properties consist of various interests in 78 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 has not been any significant changes in properties during 1999, 1998 and 1997. During 1999, one lease was sold for approximately $1,600. During 1998, five leases were sold for approximately $600. In compliance with the Partnership Agreement, if the Partnership should purchase a producing property from the Managing General Partner, such purchase price would be prior cost, adjusted for any intervening operation. If such adjusted cost was greater than fair market value, or if specific cost was unable to be determined, such purchase price would be fair market value as determined by an independent reservoir engineer. 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 33 35,000 611,000 Winkler County, 1% to 40% Texas net profits interests Michael Dingman 9/94 at 43 26,000 129,000 Midland, Reeves, .5% to 50% Dawson, Schleicher, net profits Winkler Ward, interests Andrews, Counties, Texas; Eddy County, New Mexico *Donald R. Creamer, P.E., an Independent Registered Petroleum Engineer prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2000. 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, 1999 of $25.60 was used as the beginning basis for the oil price. Oil price adjustments from $25.60 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 $23.40 per barrel in the preparation of the reserve report as of January 1, 2000. In the determination of the gas price, the New York Mercantile Exchange price at December 31, 1999 of $2.33 was used as the beginning basis. Gas price adjustments from $2.33 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 $1.98 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 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. 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 Operation. 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 1999 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 interests, or units, in the Partnership are currently being 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. As of December 31, 1999, 1998 and 1997, no limited partner units were purchased by the Managing General Partner. Number of Limited Partner Interest Holders As of December 31, 1999, there were 175 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 1999, distributions were made totaling $112,699, with $101,599 distributed to the limited partners and $11,100 to the general partners. For the year ended December 31, 1999, distributions of $20.94 per limited partner unit were made, based upon 4,851 limited partner units outstanding. During 1998, distributions were made totaling $58,500, with $52,650 distributed to the limited partners and $5,850 to the general partners. For the year ended December 31, 1998, distributions of $10.85 per limited partner unit were made, based upon 4,851 limited partner units outstanding. During 1997, twelve monthly distributions were made totaling $300,600, with $270,540 distributed to the limited partners and $30,060 to the general partners. For the year ended December 31, 1997, distributions of $55.77 per limited partner unit were made, based upon 4,851 limited partner units outstanding. Item 6. Selected Financial Data The following selected financial data for the years ended December 31 1999, 1998, 1997, 1996 and 1995 should be read in conjunction with the financial statements included in Item 8: Years ended December 31, ----------------------------------------------- 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- Revenues $ 210,376 2,205 304,410 395,095 251,501 Net income (loss) 129,693 (462,692) (467,687) 180,841 (99,700) Partners' share of net income (loss): General partners 16,880 (4,631) 25,491 34,555 19,946 Limited partners 112,814 (458,061) (493,178) 146,286(119,646) Limited partners' net income (loss) per unit 23.26 (94.43) (101.67) 30.16 (24.66) Limited partner's cash distribution per unit 20.94 10.85 55.77 64.78 45.14 Total assets $ 405,423 388,507 909,6261,677,9071,835,834 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations General Southwest Royalties Institutional Income Fund XI-B, L.P. was organized as a Delaware limited partnership on August 31, 1993. The offering of limited partnership interests began October 25, 1993, as part of a shelf offering registered under the name Southwest Royalties Institutional 1992-93 Income Program. Minimum capital requirements for the Partnership were met on December 8, 1993, and the Offering Period terminated August 20, 1994 with 174 limited partners purchasing 4,851 units for $2,425,500. The Partnership was formed to acquire non-operating interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. 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 farmout arrangements and on the depletion 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 has fluctuated over the past few years and is expected to fluctuate in later years based on these factors. Based on current conditions, management anticipates performing workovers during 2000 to enhance production. Additional workovers may be performed in the year 2003. The partnership may have an increase in production volumes for the years 2000 and 2003, otherwise, the partnership will most likely experience the historical production decline of approximately 11% per year. Results of Operations A. General Comparison of the Years Ended December 31, 1999 and 1998 The following table provides certain information regarding performance factors for the years ended December 31, 1999 and 1998: Year Ended Percentage December 31, Increase 1999 1998 (Decrease) ---- ---- --------- Average price per barrel of oil $ 16.74 11.68 43% Average price per mcf of gas $ 2.26 1.52 49% Oil production in barrels 9,280 9,800 (5%) Gas production in mcf 81,160 87,300 (7%) Income from net profits interests $ 188,298 31,907 490% Partnership distributions $ 112,699 58,500 93% Limited partner distributions $ 101,599 52,650 93% Per unit distribution to limited partners $ 20.94 10.85 93% Number of limited partner units 4,851 4,851 Revenues The Partnership's income from net profits interests increased to $188,298 from $31,907 for the years ended December 31, 1999 and 1998, respectively, an increase of 490%. The principal factors affecting the comparison of the years ended December 31, 1999 and 1998 are as follows: 1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 1999 as compared to the year ended December 31, 1998 by 43%, or $5.06 per barrel, resulting in an increase of approximately $49,600 in income from net profits interests. Oil sales represented 46% of total oil and gas sales during the year ended December 31, 1999 as compared to 46% during the year ended December 31, 1998. The average price for an mcf of gas received by the Partnership increased during the same period by 49%, or $.74 per mcf, resulting in an increase of approximately $64,600 in income from net profits interests. The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $114,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future. 2. Oil production decreased approximately 520 barrels or 5% during the year ended December 31, 1999 as compared to the year ended December 31, 1998, resulting in a decrease of approximately $8,700 in income from net profits interests. Gas production decreased approximately 6,140 mcf or 7% during the same period, resulting in a decrease of approximately $13,900 in income from net profits interests. The total decrease in income from net profits interests due to the change in production is approximately $22,600. 3. Lease operating costs and production taxes were 30% lower, or approximately $64,100 less during the year ended December 31, 1999 as compared to the year ended December 31, 1998. The decrease in lease operating costs are primarily due to workovers performed in 1998 and property sales. 4. As of December 31, 1998, miscellaneous expense was approximately $30,159. The Partnership entered into a purchase agreement on the Tar Baby lease that guaranteed net income each month from October 1994 through January 1998. This income was recorded on the Partnerships books as miscellaneous income. Based on new information obtained in May 1998, an adjustment of $52,706 was found to be necessary. This adjustment was recorded as miscellaneous expense on the Partnerships books for the quarter ended June 30, 1998. Costs and Expenses Total costs and expenses decreased to $80,683 from $464,897 for the years ended December 31, 1999 and 1998, respectively, a decrease of 83%. The decrease is the result of lower depletion expense, provision for impairment and general and administrative costs. 1. General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 14% or approximately $6,900 during the year ended December 31, 1999 as compared to the year ended December 31, 1998. The decrease of general and administrative costs were due in part to additional accounting costs incurred in 1998 in relation to the outsourcing of K-1 tax package preparation and a change in auditors requiring opinions from both the predecessors and successor auditors. Additionally, the Managing General Partner in its effort to cut back on general and administrative costs whenever and wherever possible was able to reduce the cost of reserve reports and K-1 tax package preparation during 1999. 2. Depletion expense decreased to $39,000 for the year ended December 31, 1999 from $130,000 for the same period in 1998. This represents a decrease of 70%. 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 increase in the price of oil and gas used to determine the Partnership's reserves for January 1, 2000 as compared to 1999. Another contributing factor was due to the impact of revisions of previous estimates on reserves. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have decreased depletion expense approximately $54,000 as of December 31, 1998. The Partnership reduced the net capitalized costs of oil and gas properties in 1998 by approximately $279,567. The write-down has the effect of reducing net income, but did not affect cash flow or partner distributions. Results of Operations B. 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 $ 11.68 19.37 (40%) Average price per mcf of gas $ 1.52 2.22 (32%) Oil production in barrels 9,800 11,400 (14%) Gas production in mcf 87,300 109,000 (20%) Income from net profits interests $ 31,907 206,956 (85%) Partnership distributions $ 58,500 300,600 (81%) Limited partner distributions $ 52,650 270,540 (81%) Per unit distribution to limited partners $ 10.85 55.77 (81%) Number of limited partner units 4,851 4,851 Revenues The Partnership's income from net profits interests decreased to $31,907 from $206,956 for the years ended December 31, 1998 and 1997, respectively, a decrease of 85%. 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 40%, or $7.69 per barrel, resulting in a decrease of approximately $87,700 in income from net profits interests. Oil sales represented 46% 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 32%, or $.70 per mcf, resulting in a decrease of approximately $76,300 in income from net profits interests. The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $164,000. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future. 2. Oil production decreased approximately 1,600 barrels or 14% during the year ended December 31, 1998 as compared to the year ended December 31, 1997, resulting in a decrease of approximately $18,700 in income from net profits interests. Gas production decreased approximately 21,700 mcf or 20% during the same period, resulting in a decrease of approximately $33,000 in income from net profits interests. The total decrease in income from net profits interests due to the change in production is approximately $51,700. The decrease in oil and gas production is primarily due to property sales and a gas plant explosion which stopped production in March and April of 1998. 3. Lease operating costs and production taxes were 16% lower, or approximately $41,000 less during the year ended December 31, 1998 as compared to the year ended December 31, 1997. The decrease in lease operating costs are primarily in relation to property sales. 4. As of December 31, 1998, miscellaneous expense was approximately $30,159. The Partnership entered into a purchase agreement on the Tar Baby lease that guaranteed net income each month from October 1994 through January 1998. This income was recorded on the Partnerships books as miscellaneous income. Based on new information obtained in May 1998, an adjustment of $52,706 was found to be necessary. This adjustment was recorded as miscellaneous expense on the Partnerships books for the quarter ended June 30, 1998. Costs and Expenses Total costs and expenses decreased to $464,897 from $772,097 for the years ended December 31, 1998 and 1997, respectively, a decrease of 40%. The decrease is the result of lower depletion expense, provision for impairment and general and administrative costs. 1. General and administrative costs consists of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 2% or approximately $1,000 during the year ended December 31, 1998 as compared to the year ended December 31, 1997. 3. Depletion expense decreased to $130,000 for the year ended December 31, 1998 from $226,000 for the same period in 1997. This represents a decrease of 42%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by 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 $30,000 as of December 31, 1997. The Partnership reduced the net capitalized costs of oil and gas properties in 1998 by approximately $279,567. The write-down has the effect of reducing net income, but did not affect cash flow or partner distributions. C. Revenue and Distribution Comparison Partnership income or (loss) for the years ended December 31, 1999, 1998 and 1997 was $129,693, $(462,692) and $(467,687), respectively. Excluding the effects of depreciation, depletion, amortization and provision for impairment, net income (loss) would have been $168,795 in 1999, $(46,305) in 1998 and $254,907 in 1997. Correspondingly, Partnership distributions for the years ended December 31, 1999, 1998 and 1997 were $112,699, $58,500 and $300,600, respectively. These differences are indicative of the changes in oil and gas prices, production and property. The sources for the 1999 distributions of $112,699 were oil and gas operations of approximately $133,600, and the change in oil and gas properties of approximately $1,600, resulting in excess cash for contingencies or subsequent distributions. The source for the 1998 distributions of $58,500 were oil and gas operations of approximately $55,200, and the change in oil and gas properties of approximately $600, with the balance from available cash on hand at the beginning of the period. The source for the 1997 distributions of $300,600 were oil and gas operations of approximately $285,200, with the balance from available cash on hand at the beginning of the period. Total distributions during the year ended December 31, 1999 were $112,699 of which $101,599 was distributed to the limited partners and $11,100 to the general partners. The per unit distribution to limited partners during the same period was $20.94. Total distributions during the year ended December 31, 1998 were $58,500 of which $52,650 was distributed to the limited partners and $5,850 to the general partners. The per unit distribution to limited partners during the same period was $10.85. Total distributions during the year ended December 31, 1997 were $300,600 of which $270,540 was distributed to the limited partners and $30,060 to the general partners. The per unit distribution to limited partners during the same period was $55.77. Since inception of the Partnership, cumulative monthly cash contributions of $1,102,138 have been made to the partners. As of December 31,1999 $1,005,952 or $207.37 per limited partner unit, has been distributed to the limited partners, representing a 41% return of the capital contributed. Liquidity and Capital Resources The primary source of cash is from operations, the receipt of income from net profits 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 $133,600 in 1999 compared to $55,200 in 1998 and approximately $285,200 in 1997. The primary source of the 1999 cash flow from operating activities was profitable operations. Cash flows from investing activities were approximately $1,600 in 1999. Cash flows from investing activities were approximately $600 in 1998. The Partnership had no cash flows from investing activities in 1997. Cash flows used in financing activities were approximately $112,800 in 1999 compared to $58,400 in 1998 and approximately $300,500 in 1997. The only 1999 use in financing activities was the distribution to partners. As of December 31, 1999, the Partnership had approximately $64,800 in working capital. The Managing General Partner knows of no other commitments and believes the revenues generated from operations will be 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 $35.1 million principal and $17.5 million interest payments due in 2000 on its debt obligations. Due to the severely depressed commodity prices experienced during the last quarter of 1997, throughout 1998 and continuing through the second quarter of 1999 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 year 2000 issue referred to the risk of disruptions of operations caused by the failure of computer-controlled systems, including systems used by third parties, to properly recognize date sensitive information when the year changed from 1999 to 2000. During the year ended December 31, 1999, the Managing General Partners data processing subsidiary, Midland Southwest Software, Inc., installed new software as part of an on-going project to upgrade its financial and management information systems. The cost of upgrading the software occurred in the normal course of Midland Southwest Software's business and was not material to the results of operations or financial condition of the Partnership. The Partnership has not experienced any significant business disruptions due to year 2000 issues causing processing errors in its systems, or a third party's systems, during the period of operations after January 1, 2000 until the filing of the 10-K. Item 8. Financial Statements and Supplementary Data Index to Financial Statements Page Independent Auditors Report 19 Balance Sheets 20 Statements of Operations 21 Statements of Changes in Partners' Equity 22 Statements of Cash Flows 23 Notes to Financial Statements 25 INDEPENDENT AUDITORS REPORT The Partners Southwest Royalties Institutional Income Fund XI-B, L.P. (A Delaware Limited Partnership): We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund XI-B, L.P. (the "Partnership") as of December 31, 1999 and 1998, and the related statements of operations, changes in partners' equity and cash flows for each of the years in the three-year period ended December 31, 1999. 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 Royalties Institutional Income Fund XI-B, L.P. as of December 31, 1999 and 1998 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1999 in conformity with generally accepted accounting principles. KPMG LLP Midland, Texas March 10, 2000 Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Balance Sheets December 31, 1999 and 1998 1999 1998 ---- ---- Assets Current assets: Cash and cash equivalents $ 24,784 2,410 Receivable from Managing General Partner 39,956 4,796 Other receivable 70 - - --------- --------- Total current assets 64,810 7,206 - --------- --------- Oil and gas properties - using the full- cost method of accounting 2,006,334 2,007,920 Less accumulated depreciation, depletion and amortization 1,665,721 1,626,721 - --------- --------- Net oil and gas properties 340,613 381,199 - --------- --------- Organization costs, net of amortization $37,200 in 1998 - 102 - --------- --------- $ 405,423 388,507 ========= ========= Liabilities and Partners' Equity Current liability - distribution payable $ - 79 - --------- --------- Partners' equity: General partners 6,578 797 Limited partners 398,845 387,631 - --------- --------- Total partners' equity 405,423 388,428 - --------- --------- $ 405,423 388,507 ========= ========= The accompanying notes are an integral part of these financial statements. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 1999, 1998 and 1997 1999 1998 1997 ---- ---- ---- Revenues Income from net profits interests $ 188,298 31,907 206,956 Interest from operations 1,078 457 3,030 Miscellaneous income 21,000 (30,159) 94,424 ------- - ------- ------- 210,376 2,205 304,410 ------- - ------- ------- Expenses General and administrative 41,580 48,510 49,503 Depreciation, depletion and amortization 39,102 136,820 233,440 Provision for impairment of oil and gas properties - 279,567 489,154 ------- - ------- ------- 80,682 464,897 772,097 ------- - ------- ------- Net income (loss) $ 129,694 (462,692)(467,687) ======= ======= ======= Net income (loss)allocated to: Managing General Partner $ 15,193 (4,168) 22,942 ======= ======= ======= General Partner $ 1,688 (463) 2,549 ======= ======= ======= Limited partners $ 112,813 (458,061)(493,178) ======= ======= ======= Per limited partner unit $ 23.26 (94.43) (101.67) ======= ======= ======= The accompanying notes are an integral part of these financial statements. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Statements of Changes in Partners' Equity Years ended December 31, 1999, 1998 and 1997 General Limited Partners Partners Total -------- -------- ----- Balance at December 31, 1996 $ 15,847 1,662,0601,677,907 Net income (loss) 25,491 (493,178)(467,687) Distributions (30,060) (270,540)(300,600) ------- - --------- --------- Balance at December 31, 1997 11,278 898,342 909,620 Net income (loss) (4,631) (458,061)(462,692) Distributions (5,850) (52,650) (58,500) ------- - --------- --------- Balance at December 31, 1998 797 387,631 388,428 Net income 16,881 112,813 129,694 Distributions (11,100) (101,599)(112,699) ------- - --------- --------- Balance at December 31, 1999 $ 6,578 398,845 405,423 ======= ========= ========= The accompanying notes are an integral part of these financial statements. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 1999, 1998 and 1997 1999 1998 1997 ---- ---- ---- Cash flows from operating activities: Cash received from net profits interests $ 162,358 78,812 331,720 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (29,800) (24,029)(49,503) Interest received 1,078 457 3,030 -------- - -------- ---------- Net cash provided by operating activities 133,636 55,240 285,247 -------- - -------- ---------- Cash flows from investing activities: Sales of oil and gas properties 1,586 649 - -------- - -------- ---------- Cash flows from financing activities: Distributions to partners (112,848) (58,427)(300,524) -------- - -------- ---------- Net increase (decrease) in cash and cash equivalents 22,374 (2,538) (15,277) Beginning of period 2,410 4,948 20,225 -------- - -------- ---------- End of period $ 24,784 2,410 4,948 ======== ======== ========== (continued) The accompanying notes are an integral part of these financial statements. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Statements of Cash Flows, continued Years ended December 31, 1999, 1998 and 1997 1999 1998 1997 ---- ---- ---- Reconciliation of net income (loss) to net cash provided by operating activities: Net income (loss) $ 129,694 (462,692)(467,687) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 39,102 136,820 233,440 (Increase) decrease in receivables (25,940) 46,905 30,339 (Decrease) increase in payables (9,220) 54,640 - Provision for impairment of oil and gas properties - 279,567 489,154 ------- - ------- ------- Net cash provided by operating activities $ 133,636 55,240 285,247 ======= ======= ======= The accompanying notes are an integral part of these financial statements. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Notes to Financial Statements 1. Organization Southwest Royalties Institutional Income Fund XI-B, L.P. was organized under the laws of the state of Delaware on August 31, 1993, 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 Partner 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% All 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 Royalties Institutional Income Fund XI-B, 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, 1999 and 1997, the net capitalized costs did not exceed the estimated value of oil and gas reserves. The Partnership reduced the net capitalized costs of oil and gas properties in 1998 by approximately $279,567. This write-down has the effect of reducing net income, but did not affect cash flow or partnership distributions. The Partnership's interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Notes to Financial Statements 2. Summary of Significant Accounting Policies - continued 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. 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, 1999, 1998 and 1997, there were no significant amounts of imbalance in terms of units and value. Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners. In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Partnership's tax basis in its oil and gas properties at December 31, 1999 and 1998 is $485,118 and $558,051 more than that shown on the accompanying Balance Sheet in accordance with generally accepted accounting principles. Southwest Royalties Institutional Income Fund XI-B, 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, 1999, 1998 and 1997 there were 4,851 limited partner units outstanding held by 175, 176 and 176 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 $35.1 million principal and $17.5 million interest payments due in 2000 on its debt obligations. Due to the severely depressed commodity prices experienced during the last quarter of 1997, throughout 1998 and continuing through the second quarter of 1999 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 Royalties Institutional Income Fund XI-B, 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, 1999, 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. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Notes to Financial Statements 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 $55,300, $54,700 and $56,000 for the years ended December 31, 1999, 1998 and 1997, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates. Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $5,200, $600 and $700 for the years ended December 31, 1999, 1998 and 1997, respectively, and the Managing General Partner believes that these costs are comparable to similar charges paid by the Partnership to unrelated third parties. Southwest Royalties, Inc., the Managing General Partner, was paid $36,000 in 1999, $33,711 in 1998 and $42,000 during 1997, as an administrative fee for indirect general and administrative overhead expenses. Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $39,956 and $4,796 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 1999 and 1998, respectively. In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services for the years ended December 31, 1999, 1998 and 1997. 6. Major Customers No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 84% of the Partnership's total oil and gas production during 1999: Navajo Refining Company for 40%, Sid Richardson Gasoline Co. for 33% and Phillips 66 for 11%. Two purchasers accounted for 72% of the Partnership's total oil and gas production during 1998: Navajo Refining Company for 39% and American Processing for 33%. Two purchasers accounted for 71% of the Partnership's total oil and gas production during 1997: Navajo Refining Company, Inc. 36%, and American Processing 35%. 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 Royalties Institutional Income Fund XI-B, 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, 1997 129,000 1,447,000 Revisions of previous estimates (60,000) (552,000) Production (11,000) (109,000) ------- --------- December 31, 1997 58,000 786,000 Sales of reserves in place (2,000) (1,000) Revisions of previous estimates (24,000) (60,000) Production (10,000) (87,000) ------- --------- December 31, 1998 22,000 638,000 Revisions of previous estimates 49,000 227,000 Production (9,000) (81,000) ------- --------- December 31, 1999 62,000 784,000 ======= ========= Proved developed reserves - December 31, 1997 53,000 771,000 ======= ========= December 31, 1998 22,000 626,000 ======= ========= December 31, 1999 61,000 770,000 ======= ========= All of the Partnership's reserves are located within the continental United States. *Donald R. Creamer, P.E., an Independent Registered Petroleum Engineer prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2000. 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, 1999 of $25.60 was used as the beginning basis for the oil price. Oil price adjustments from $25.60 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 $23.40 per barrel in the preparation of the reserve report as of January 1, 2000. In the determination of the gas price, the New York Mercantile Exchange price at December 31, 1999 of $2.33 was used as the beginning basis. Gas price adjustments from $2.33 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 $1.98 per Mcf in the preparation of the reserve report as of January 1, 2000. Southwest Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Notes to Financial Statements 7. Estimated Oil and Gas Reserves (unaudited) - continued The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated. Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. 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 Royalties Institutional Income Fund XI-B, L.P. (a Delaware limited partnership) Notes to Financial Statements 7. 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, 1999, 1998 and 1997 is presented below: 1999 1998 1997 ---- ---- ---- Future cash inflows, net of production and development costs $ 1,478,000 593,000 1,104,000 10% annual discount for estimated timing of cash flows 589,000 212,000 313,000 --------- --------- --------- Standardized measure of discounted future net cash flows $ 889,000 381,000 791,000 ========= ========= ========= The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 1999, 1998 and 1997 are as follows: 1999 1998 1997 ---- ---- ---- Sales of oil and gas produced, net of production costs $ (188,000) (32,000) (207,000) Changes in prices and production costs 241,000 (210,000) (1,560,000) Changes of production rates (timing) and others 17,000 (135,000) 212,000 Revisions of previous quantities estimates 401,000 (103,000) (643,000) Accretion of discount 38,000 79,000 272,000 Discounted future net cash flows - Sales of minerals in place (1,000) (9,000) - Beginning of year 381,000 791,000 2,717,000 --------- --------- --------- End of year $ 889,000 381,000 791,000 ========= ========= ========= 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 None 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 44 Chairman of the Board, President, Chief Executive Officer, Treasurer and Director H. Allen Corey 43 Secretary and Director Bill E. Coggin 45 Vice President and Chief Financial Officer J. Steven Person 41 Vice President, Marketing Paul L. Morris 58 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. 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 Jon P. Tate, Vice President, Land and Assistant Secretary, age 42, 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, age 44, 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. 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 $36,000 during 1999, $33,711 during 1998 and $42,000 during 1997, 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. No officer or director of the Managing General Partner owns Units in the Partnership. H. H. Wommack, III, as the individual general partner of the Partnership, owns a one percent interest 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. Item 13. Certain Relationships and Related Transactions In 1999, the Managing General Partner received $36,000 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 $55,300 for administrative overhead attributable to operating such properties during 1999. Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $5,200 for the year ended December 31, 1999. 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 -- Independent Auditors Report Balance Sheet Statement of Operations Statement of Changes in Partners' Equity Statement 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 Royalties Institutional Income Fund XI-B, L.P., dated August 24, 1993. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1993). (b) Agreement of Limited Partnership of Southwest Royalties Institutional Income Fund XI-B, L.P., dated August 27, 1993. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1993). 27 Financial Data Schedule (b) Reports on Form 8-K There were no reports filed on Form 8-K during the quarter ended December 31, 1999. 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 Royalties Institutional Income Fund XI-B, 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, 2000 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, 2000 By: /s/ H. Allen Corey ----------------------------- H. Allen Corey, Secretary and Director Date: March 31, 2000 EX-27 2
5 This schedule contains summary financial information extracted from the Balance Sheet at December 31, 1999 and the Statement of Operations for the Year Ended December 31, 1999 and is qualified in its entirety by reference to such financial statements. YEAR DEC-31-1999 DEC-31-1999 24,784 0 40,026 0 0 64,810 2,006,334 1,665,721 405,423 0 0 0 0 0 405,423 405,423 188,298 210,376 0 0 80,682 0 0 129,694 0 129,694 0 0 0 129,694 23.26 23.26
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