Item 1. Business
General Southwest Royalties Institutional 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 August 20, 1992, as part of a shelf offering registered under the name Southwest Royalties Institutional 1992-93 Income Program, reached minimum capital requirements on December 10, 1992 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 non-operating 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 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 interests and net profit 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.
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 37% 63% 1998 39% 61% 1997 45% 55%
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 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 80% of the Partnership's total oil and gas production during 1999: Sid Richardson Gasoline Co. for 29%, Phillip 66 for 23%, Navajo Refining Company, Inc. for 18% and Southwestern Energy Prod. Company for 10%. Four purchasers accounted for 63% of the Partnership's total oil and gas production during 1998: American Processing for 22%, Nustar Joint Venture for 14%, Navajo Refining Company, Inc. for 14% and Southwestern Energy Prod. Company for 13%. Two purchasers accounted for 37% of the Partnership's total oil and gas production during 1997: American Processing for 24%, and Navajo Refining Company, Inc. for 13%. 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 net profits or royalty 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 - 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.
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 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 Dewitt, Dickens, Fayette, Gaines, Hemphill, Howard, Live Oak, Reagan, Reeves, Upton, Ward, Winkler, and Yoakum Counties of Texas. These properties consist of various interests in 102 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 1999 and 1998.
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 operations. 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.
There were no property sales during 1999. During 1998, fifty-five leases were sold for approximately $78,900. During 1997, four leases were sold for approximately $44,700.
On October 15, 1998, Southwest Royalties Institutional Income Fund XI-A (the "Registrant") sold its interest in 54 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 $70,735. At December 31, 1997, the property sold to Parks & Luttrell contained proved reserves of 27,531 barrels of oil and 113,835 mcfs of gas and had a SEC 10 value of $120,179 at the time of sale. The proceeds from the sale represented 7.55% 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 1% 33 35,000 611,000 Winkler County, to 40% net Texas profits interests
Elizabeth Windham 10/94 at 28.9% 1 - 109,000 Upton County, Texas net profits interests
Webb Lease 5/94 at 12.5% 4 21,000 9,000 Yoakum County, net profits Texas interests
*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 $22.81 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.
As also discussed in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, oil 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 farm- out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.
The 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.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is a party.
Item 4.
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.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
Market Information
Limited partnership interests, 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. The Managing General Partner has become aware of certain limited and sporadic transfers of units between limited partners and third parties, but has no verifiable information regarding the prices at which such units have been transferred. 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 1999, 10 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $108.72 per unit. There were no limited partner units were purchased by the Managing General Partner, during 1998. In 1997, 126 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $192.93 per unit.
Number of Limited Partner Interest Holders
As of December 31, 1999, there were 220 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 $179,960, with $165,460 distributed to the limited partners and $14,500 to the general partners. For the year ended December 31, 1999, distributions of $30.54 per limited partner unit were made, based upon 5,418 limited partner units outstanding. During 1998, distributions were made totaling $179,000, with $163,600 distributed to the limited partners and $15,400 to the general partners. For the year ended December 31, 1998, distributions of $30.20 per limited partner unit were made, based upon 5,418 limited partner units outstanding. During 1997, twelve monthly distributions were made totaling $363,956, with $331,256 distributed to the limited partners and $32,700 to the general partners. For the year ended December 31, 1997, distributions of $61.14 per limited partner unit were made, based upon 5,418 limited partner units outstanding.
Item 6.
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:
Year ended December 31, ------------------------------------------------------- 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- Revenues $ 221,645 54,628 377,633 531,508 342,727
Net income (loss) 129,630 (588,592) (133,264) 285,720 42,213
Partners' share of net income (loss):
General partners 15,863 3,061 23,329 40,382 29,253
Limited partners 113,767 (591,653) (156,593) 245,338 12,960
Limited partners' net income per unit 21.00 (109.20) (28.90) 45.28 2.39
Limited partners' cash distribution per unit 30.54 30.20 61.14 76.51 71.78
Total assets $ 525,852 576,182 1,343,7741,841,0142,010,059
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Southwest Royalties Institutional Income Fund XI-A, L.P. was organized as a Delaware limited partnership on May 5, 1992. The offering of limited partnership interests began August 20, 1992, 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 10, 1992, and the Offering Period terminated April 30, 1993 with 213 limited partners purchasing 5,418 units for $2,709,000.
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 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 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 few 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 year 2003, otherwise, the Partnership will most likely experience the historical production decline of approximately 12% 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 $ 16.56 11.33 46% Average price per mcf of gas $ 2.26 1.69 34% Oil production in barrels 8,390 12,000 (30%) Gas production in mcf 105,480 125,100 (16%) Income from net profits interests $ 198,794 83,345 139% Partnership distributions $ 179,960 179,000 1% Limited partner distributions $ 165,460 163,600 1% Per unit distribution to limited partners $ 30.54 30.20 1% Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests increased to $198,794 from $83,345 for the years ended December 31, 1999 and 1998, respectively, an increase of 139%. 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 46%, or $5.23 per barrel, resulting in an increase of approximately $62,800 in income from net profits interests. Oil sales represented 37% of total oil and gas sales during the year ended December 31, 1999 as compared to 39% 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 34%, or $.57 per mcf, resulting in an increase of approximately $71,300 in income from net profits interests.
The total increase in income from net profits interests due to the change in prices received from oil and gas production is approximately $134,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 3,610 barrels or 30% during the year ended December 31, 1999 as compared to the year ended December 31, 1998, resulting in a decrease of approximately $59,800 in income from net profits interests.
Gas production decreased approximately 19,620 mcf or 16% during the same period, resulting in a decrease of approximately $44,300 in income from net profits interests.
The total decrease in income from net profits interests due to the change in production is approximately $104,100. The decrease in production is due primarily to property sales during 1998.
3. Lease operating costs and production taxes were 32% lower, or approximately $85,400 less during the year ended December 31, 1999 as compared to the year ended December 31, 1998. The decrease in lease operating costs are due primarily to property sales during 1998.
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 $92,015 from $643,220 for the years ended December 31, 1999 and 1998, respectively, a decrease of 86%. The decrease is the result of lower general and administrative costs, provision for impairment and depletion expense.
1. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 22% or approximately $12,200 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 $50,000 for the year ended December 31, 1999 from $187,000 for the same period in 1998. This represents a decrease of 73%. 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 $74,000 as of December 31, 1998.
The Partnership reduced the net capitalized costs of oil and gas properties during 1998 by $402,040. 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, 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 $ 11.33 18.80 (40%) Average price per mcf of gas $ 1.69 2.25 (25%) Oil production in barrels 12,000 16,100 (25%) Gas production in mcf 125,100 161,900 (23%) Income from net profits interests $ 83,345 279,147 (70%) Partnership distributions $ 179,000 363,956 (51%) Limited partner distributions $ 163,600 331,256 (51%) Per unit distribution to limited partners $ 30.20 61.14 (51%) Number of limited partner units 5,418 5,418
Revenues
The Partnership's income from net profits interests decreased to $83,345 from $279,147 for the years ended December 31, 1998 and 1997, respectively, a decrease of 70%. 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 $7.47 per barrel, resulting in a decrease of approximately $120,300 in income from net profits interests. Oil sales represented 39% of total oil and gas sales during the year ended December 31, 1998 as compared to 45% 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 25%, or $.56 per mcf, resulting in a decrease of approximately $90,700 in income from net profits interests.
The total decrease in income from net profits interests due to the change in prices received from oil and gas production is approximately $211,000. 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 4,100 barrels or 25% during the year ended December 31, 1998 as compared to the year ended December 31, 1997, resulting in a decrease of approximately $46,500 in income from net profits interests.
Gas production decreased approximately 36,800 mcf or 23% during the same period, resulting in a decrease of approximately $62,200 in income from net profits interests.
The total decrease in income from net profits interests due to the change in production is approximately $108,700. The decline in oil and gas production is due primarily to property sales and a gas plant explosion which stopped production on some wells for March and April of 1998.
3. Lease operating costs and production taxes were 32% lower, or approximately $123,800 less during the year ended December 31, 1998 as compared to the year ended December 31, 1997. Lease operating costs decreased primarily due 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 increased to $643,220 from $510,897 for the years ended December 31, 1998 and 1997, respectively, an increase of 26%. The increase is the result of higher general and administrative costs and provision for impairment, partially offset by a decrease in depletion expense.
1. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs increased 9% or approximately $4,200 during the year ended December 31, 1998 as compared to the year ended December 31, 1997. The increase in general and administrative costs are the result of higher accounting fees due to the necessity of contracting out preparation of tax depletion and K- 1 schedules.
3. Depletion expense decreased to $187,000 for the year ended December 31, 1998 from $249,000 for the same period in 1997. This represents a decrease of 25%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by 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 $17,000 as of December 31, 1997.
The Partnership reduced the net capitalized costs of oil and gas properties by $402,040. 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.
C. Revenue and Distribution Comparison
Partnership net income or (loss) for the years ended December 31, 1999, 1998 and 1997 was $129,630, $(588,592) and $(133,264) respectively. Excluding the effects of depreciation, depletion, amortization and provision for impairment, net income for the years ended December 31, 1999, 1998 and 1997 would have been $179,630, $448 and $327,711, respectively. Correspondingly, Partnership distributions for the years ended December 31, 1999, 1998 and 1997 were $179,960, $179,000 and $363,956, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 1999, 1998 and 1997.
The sources for the 1999 distributions of $179,960 were oil and gas operations of approximately $152,700, with the balance from available cash on hand at the beginning of the period. The sources for the 1998 distributions of $179,000 were oil and gas operations of approximately $106,900 and the change in oil and gas properties of approximately $77,300, result in excess cash for contingencies or subsequent distributions. The sources for the 1997 distributions of $363,956 were oil and gas operations of approximately $366,400 and the change in oil and gas properties of approximately $43,200, result in excess cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 1999 were $179,960 of which $165,460 was distributed to the limited partners and $14,500 to the general partners. The per unit distribution to limited partners during the same period was $30.54. Total distributions during the year ended December 31, 1998 were $179,000 of which $163,600 was distributed to the limited partners and $15,400 to the general partners. The per unit distribution to limited partners during the same period was $30.20. Total distributions during the year ended December 31, 1997 were $363,956 of which $331,256 was distributed to the limited partners and $32,700 to the general partners. The per unit distribution to limited partners during the same period was $61.14.
Since inception of the Partnership, cumulative monthly cash distributions of $1,714,408 have been made to the partners. As of December 31, 1999, $1,568,658 or $289.53 per limited partner unit, has been distributed to the limited partners, representing a 58% 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 $152,700 in 1999 compared to $106,900 in 1998 and approximately $366,400 in 1997. The primary source of the 1999 cash flow from operating activities was profitable operations.
There were no investing activities for 1999. Cash flows provided by investing activities were approximately $77,300 in 1998 and approximately $43,200 in 1997.
Cash flows provided by financing activities were approximately $180,000 in 1999 compared to $179,000 in 1998 and approximately $364,000 in 1997. The only 1999 use in financing activities was the distributions to partners.
As of December 31, 1999, the Partnership had approximately $87,900 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.
Item 8. Financial Statements and Supplementary Data
Page
Independent Auditors Report 19
Balance Sheets 20
Statements of Operations 21
Statement 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-A, L.P. (A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund XI-A, 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-A, 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-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 1999 and 1998
1999 1998 ---- ---- Assets
Current assets: Cash and cash equivalents $ 30,195 57,406 Receivable from Managing General Partner 57,750 30,869
- --------- --------- Total current assets 87,945 88,275
- --------- --------- Oil and gas properties - using the full- cost method of accounting 2,029,769 2,029,769 Less accumulated depreciation, depletion and amortization 1,591,862 1,541,862
- --------- --------- Net oil and gas properties 437,907 487,907
- --------- --------- $ 525,852 576,182
========= ========= Liabilities and Partners' Equity
Partners' equity: General partners $ (23,815) (25,178) Limited partners 549,667 601,360
- --------- --------- Total partners' equity 525,852 576,182
- --------- --------- $ 525,852 576,182
========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, 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 $ 198,794 83,345 279,147 Interest 1,851 1,441 4,062 Miscellaneous income 21,000 (30,159) 94,424 ------- - ------- ------- 221,645 54,628 377,633 ------- - ------- ------- Expenses
General and administrative 42,015 54,180 49,922 Depreciation, depletion and amortization 50,000 187,000 258,153 Provision for impairment of oil and gas properties - 402,040 202,822 ------- - ------- ------- 92,015 643,220 510,897 ------- - ------- ------- Net income (loss) $ 129,630 (588,592)(133,264) ======= ======= ======= Net income (loss) allocated to:
Managing General Partner $ 14,277 2,755 20,996 ======= ======= ======= General partner $ 1,586 306 2,333 ======= ======= ======= Limited partners $ 113,767 (591,653)(156,593) ======= ======= ======= Per limited partner unit $ 21.00 (109.20) (28.90) ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 1999, 1998, 1997
General Limited Partners Partners Total -------- -------- ----- Balance at December 31, 1996 $ (3,468) 1,844,4621,840,994
Net income (loss) 23,329 (156,593)(133,264)
Distributions (32,700) (331,256)(363,956) ------- - --------- --------- Balance at December 31, 1997 (12,839) 1,356,6131,343,774
Net income (loss) 3,061 (591,653)(588,592)
Distributions (15,400) (163,600)(179,000) ------- - --------- --------- Balance at December 31, 1998 (25,178) 601,360 576,182
Net income 15,863 113,767 129,630
Distributions (14,500) (165,460)(179,960) ------- - --------- --------- Balance at December 31, 1999 $ (23,815) 549,667 525,852 ====== ========== =========
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, 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 $ 163,960 139,461 412,279 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (13,062) (33,964)(49,922) Interest received 1,851 1,441 4,062 --------- - --------- --------- Net cash provided by operating activities 152,749 106,938 366,419 --------- - --------- --------- Cash flows from investing activities:
Sale of oil and gas properties - 77,278 43,152 --------- - --------- --------- Cash flows from financing activities:
Distributions to partners (179,960) (179,000)(363,976) --------- - --------- --------- Net increase (decrease) in cash and cash equivalents (27,211) 5,216 45,595
Beginning of period 57,406 52,190 6,595 --------- - --------- --------- End of period $ 30,195 57,406 52,190 ========= ========= =========
(continued)
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, 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) $ 129,630 (588,592)(133,264)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 50,000 187,000 258,153 Provision for impairment of oil and gas properties - 402,040 202,822 Decrease (increase) in receivables (34,834) 56,116 38,708 Increase in payables 7,953 50,374 - ------- - ------- ------- Net cash provided by operating activities $ 152,749 106,938 366,419 ======= ======= =======
Supplemental schedule of noncash investing and financing activities:
Oil and gas properties included in receivable from Managing General Partner $ - - - 1,650 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Royalties Institutional 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 costs 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 a 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-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 December 31, 1999 the net capitalized costs did not exceed the estimated present value of oil and gas reserves. As of December 31, 1998, the net capitalized cost exceeded the estimated present value of oil and gas reserves thus an adjustment of $402,040 was made to the financial statement. As of December 31, 1997, the net capitalized cost exceeded the estimated present value of oil and gas reserves thus an adjustment of $202,822 was made to the financial statement.
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-A, 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.
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 and 1998 there were no significant amounts of imbalance in terms of units and value. As of December 31, 1997 the Partnership was over produced by 3,521.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Partnership's tax basis in its net oil and gas properties at December 31, 1999 and 1998 is $482,437 and $517,965 more, respectively, as that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
Cash and Cash Equivalents For purposes of the statements of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.
Number of Limited Partner Units As of December 31, 1999, 1998 and 1997 there were 5,418 limited partner units outstanding held by 220, 221 and 221 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.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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.
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.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
4. Commitments and Contingent Liabilities - continued 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.
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 $58,400, $60,100 and $70,000 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 $5,000, $10 and $500 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 $37,000 during 1999, $37,442 during 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 $57,750 and $30,869 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 1999 and 1998.
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 service provided to the Partnership for the year ended December 31, 1999 and 1998, and approximately $30 for the years ended December 31, 1997.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
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 80% of the Partnership's total oil and gas production during 1999: Sid Richardson Gasoline Co. for 29%, Phillip 66 for 23%, Navajo Refining Company, Inc. for 18% and Southwestern Energy Prod. Company for 10%. Four purchasers accounted for 63% of the Partnership's total oil and gas production during 1998: American Processing for 22%, Nustar Joint Venture for 14%, Navajo Refining Company, Inc. for 14% and Southwestern Energy Prod. Company for 13%. Two purchasers accounted for 37% of the Partnership's total oil and gas production during 1997: American Processing for 24%, and Navajo Refining Company, Inc. for 13%. In the event any of these purchasers were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's sales of oil and gas production.
7. Estimated Oil and Gas Reserves (unaudited) The Partnership's interest in proved oil and gas reserves is as follows:
Oil (bbls) Gas (mcf) ---------- ---------
Proved developed and undeveloped reserves -
January 1, 1997 166,000 1,866,000
Revision of estimates in place (56,000) (695,000) Production (16,000) (162,000) Sale of minerals in place (2,000) (1,000) ------- --------- December 31, 1997 92,000 1,008,000
Revision of estimates in place (33,000) (16,000) Production (12,000) (125,000) Sale of minerals in place (20,000) (104,000) ------- --------- December 31, 1998 27,000 763,000
Revision of estimates in place 51,000 206,000 Production (8,000) (105,000) ------- --------- December 31, 1999 70,000 864,000 ======= =========
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
Proved developed reserves - Oil (bbls) Gas (mcf) ---------- -------- - -
December 31, 1997 91,000 965,000 ======= ========= December 31, 1998 27,000 753,000 ======= ========= December 31, 1999 70,000 855,000 ======= =========
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 $22.81 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.
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.
Southwest Royalties Institutional Income Fund XI-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing, proved developed non-producing and proved undeveloped. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out, or receives cash.
Southwest Royalties Institutional Income Fund XI-A, 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 $ 1,744,000 733,000 1,709,000 10% annual discount for estimated timing of cash flows 703,000 245,000 556,000 --------- --------- --------- Standardized measure of discounted future net cash flows $ 1,041,000 488,000 1,153,000 ========= ========= =========
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 $ (199,000) (83,000) (279,000) Changes in prices and production costs 309,000 (349,000) (1,912,000) Changes of production rates (timing) and others (21,000) (110,000) 262,000 Revisions of previous quantities estimates 415,000 (118,000) (758,000) Accretion of discount 49,000 115,000 349,000 Sales of minerals in place - (120,000) (3,000) Discounted future net cash flows - Beginning of year 488,000 1,153,000 3,494,000 --------- --------- --------- End of year $ 1,041,000 488,000 1,153,000 ========= ========= =========
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.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Part III
Item 10.
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.
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 $37,000 during 1999 as an annual administrative fee.
Item 12.
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 336 limited partner units, or 6.2% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 14.6%.
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. The officers and directors of the Managing General Partner are considered beneficial owners of the limited partner units acquired by the Managing General Partner by virtue of their status as such. A list of beneficial owners of limited partner units, acquired by the Managing General Partner, is as follows:
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 6.2% Interest Managing General Partner 336 Units 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly Owns 6.2% Interest Chairman of the Board, 336 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 6.2% Interest Secretary and Director of 336 Units Southwest Royalties, Inc., the Managing General Partner 633 Chestnut Street Chattanooga, TN 37450-1800
Limited Partnership Bill E. Coggin Indirectly Owns 6.2% Interest Vice President and CFO of 336 Units Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership J. Steven Person Indirectly Owns 6.2% Interest Vice President, Marketing 336 Units of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
Limited Partnership Paul L. Morris Indirectly Owns 6.2% Interest Director of Southwest 336 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.
Item 13. Certain Relationships and Related Transactions
In 1999, the Managing General Partners received $37,000 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 $58,400 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 $5,000 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.
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-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 Royalties Institutional 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) Report 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-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, 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