Item 1. Business
General Southwest Developmental Drilling Fund 91-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on January 7, 1991. The offering of limited and general partner interests began September 17, 1991 as part of a shelf offering registered under the name Southwest Developmental Drilling Program 1991-92, reached minimum capital requirements on April 22, 1992 and concluded April 30, 1992. The Partnership has no subsidiaries.
The Partnership has expended its capital and acquired leasehold interests and completed drilling operations. The Partnership has produced and marketed the crude oil and natural gas produced from such properties.
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 92 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. The Partnership has no employees.
Principal Products, Marketing and Distribution The Partnership has acquired leasehold interests and drilled oil and gas properties located in Texas and New Mexico. 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.
The year 2000 was a record year for crude oil prices. The world energy markets witnessed a continuation of the 1999 recovery seeing prices in the U.S. peak at $37 per barrel in September. Increasing demand and depleting inventories appeared to be the motivators in crude's dramatic rise. At the beginning of 2000, U.S. crude oil inventories were approximately 16% lower than at the beginning of 1999 and summer vacationers made it through a travel season that saw gasoline prices top $2 per gallon in some U.S. markets. The lack of crude oil inventory in the U.S. was also magnified by the colder than normal winter that much of the country experienced. However, several production increases from OPEC coupled with President Clinton's release of 30 million barrels of oil from the U.S. Strategic Petroleum Reserve in September contributed to the slow in prices toward the end of the year. After averaging $30 per barrel for the year and over $32 from August through November, oil prices closed out the year 2000 at $26.80 per barrel.
Tighter supplies, rising demand, and the return of more seasonal summer and winter weather catapulted spot gas prices in 2000 to the highest levels since the market was deregulated in the mid-1980's. Average monthly spot prices rose an astounding 72.9% over 1999 levels to average $3.77/MMBTU. The climb in prices was fairly steady throughout the year, with the first- quarter spot prices averaging $2.44/MMBtu. After the winter season ended with a huge storage deficit of 306 BCF, a combination of factors contributed further to the upward trend in spot prices. As the summer temperatures heated up and the rate of storage injections remained sluggish, competition for gas supplies became fierce between power generators and gas utilities attempting to refill storage. Spot prices really took off in the fourth quarter as competition for storage gas in the waning days of the refill season became supercharged. And then came weeks of early heating-season cold, which caused gas utilities to scramble to meet the heating loads. A year of record high prices was capped off in December, with spot prices averaging $6.14/MMBtu, more than two-and-a-half times the previous five-year December average of $2.43/MMBtu.
Following is a table of the ratios of revenues received from oil and gas production for the last three years:
Oil Gas
2000 85% 15% 1999 86% 14% 1998 83% 17%
As the table indicates, the majority of the Partnership's revenue is from its oil production; therefore, Partnership revenues will be highly dependent upon the future prices and demands for oil.
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. Two purchasers accounted for 91% of the Partnership's total oil and gas production during 2000: Plains Marketing LP for 78% and Duke Energy Transport for 13%. Two purchasers accounted for 85% of the Partnership's total oil and gas production during 1999: Navajo Refining Company, Inc. for 52% and Scurlock Permian LLC for 33%. Three purchasers accounted for 93% of the Partnership's total oil and gas production during 1998: Navajo Refining Company, Inc. for 45%, Scurlock Permian Corporation 38% and Phillips 66 Natural Gas Company for 10%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's total oil and gas production.
Competition Because the Partnership has utilized all of its funds available for the acquisition of interests in producing oil and gas properties or drilling operations, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties.
Factors that may adversely affect the Partnership include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.
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 are regulated by administrative agencies under statutory provisions of the states where such activities are conducted and by certain agencies of the federal government for operations on Federal leases. Moreover, certain prices at which the 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 are subject to extensive federal, state and local laws and regulations governing the generation, storage, handling, emission, transportation and discharge of materials into the environment. Governmental authorities have the power to enforce compliance with their regulations, and violations carry substantial penalties. This regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. 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, land men 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, 2000 there were 92 individuals directly employed by the Managing General Partner in various capacities.
Item 2.
Item 2. Properties
In determining whether an interest in a particular property was to be acquired, the Managing General Partner considered such criteria as estimated oil and gas reserves, estimated drilling costs, 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, 2000, the Partnership possessed an interest in oil and gas properties located in Eddy County of New Mexico and Rains, Van Zandt and Ward County of Texas. These properties consist of various interests in 5 wells.
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 2000, 1999 and 1998.
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) - ----------------- ------------ ----- ---------- ---------
Carson E 6/92 1 9,000 23,000 Ward County, 90% Texas working interest
Carson F #1 6/92 1 37,000 36,000 Ward County, 89% Texas working interest
*Ryder Scott Petroleum Engineers prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2001. 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, 2000 of $26.80 was used as the beginning basis for the oil price. Oil price adjustments from $26.80 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 $26.18 per barrel in the preparation of the reserve report as of January 1, 2001.
In the determination of the gas price, the New York Mercantile Exchange price at December 31, 2000 of $9.78 was used as the beginning basis. Gas price adjustments from $9.78 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 $9.92 per Mcf in the preparation of the reserve report as of January 1, 2001.
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 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.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing and proved developed non-producing. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves.
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 2000 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 Investor partner interests, or units, in the Partnership were initially offered and sold for a price of $1,000. Investor 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 or general partner without the consent of the Managing General Partner.
Each Additional General Partner interest, whom elected at the time of subscription into the Partnership, has been converted into a limited partner effective January 1, 1994.
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, 2000, no limited partner units were purchased by the Managing General Partner. In 1999, 5 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $78.06 per unit. As of December 31, 1998, no limited partner units were purchased by the Managing General Partner.
Number of Limited and General Partner Interest Holders As of December 31, 2000, there were 103 holders of limited partner units and no holders of general partner units in the Partnership.
Distributions Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and Agreement of Limited Partnership, "Net Cash Flow" is distributed to the partners on a monthly basis. "Net Cash Flow" is defined as "the cash generated by the Partnership's drilling activities, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of the Partnership, including, but not limited to drilling cost overruns, as determined in the sole discretion of the Managing General Partner."
During 2000, quarterly distributions were made totaling $121,035, with $107,721 distributed to the investor partners and $13,314 to the Managing General Partner. For the year ended December 31, 2000, distributions of $94.12 per investor partner unit were made, based upon 1,144.50 investor partner units outstanding. During 1999, distributions were made totaling $85,000, with $75,650 distributed to the investor partners and $9,350 to the Managing General Partner. For the year ended December 31, 1999, distributions of $66.10 per investor partner unit were made, based upon 1,144.5 investor partner units outstanding. During 1998, distributions were made totaling $40,500, with $36,045 distributed to the investor partners and $4,455 to the Managing General Partner. For the year ended December 31, 1998, distributions of $31.49 per investor partner unit were made, based upon 1,144.50 investor partner units outstanding.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 2000, 1999, 1998, 1997 and 1996 should be read in conjunction with the financial statements included in Item 8:
Years ended December 31, ----------------------------------------------------- Restated 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- Revenues $ 162,884 252,026 172,847 307,526 480,994
Net income (loss) 58,242 119,990 (3,178) 126,704 278,970
Partners' share of net income (loss):
Managing General Partner 7,617 17,159 5,480 20,529 38,903
Investor partners 50,625 102,831 (8,658) 106,175 240,067
Investor partners' net income (loss) per unit 44.23 89.85 (7.57) 92.77 209.76
Investor partners' cash distributions per unit 94.12 66.10 31.49 225.51 196.74
Total assets $ 165,095 237,888 195,528 236,923 399,872
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General Southwest Developmental Drilling Fund 91-A, L.P. was organized as a Delaware limited partnership on January 7, 1991. The offering of limited and general partner interests began on September 17, 1991 as part of a shelf offering registered under the name Southwest Developmental Drilling Program 1991-92. Minimum capital requirements for the Partnership were met on April 22, 1992, with the offering of limited and general partner interests concluding on April 30, 1992, with total investor partner contributions of $1,144,500. The Managing General Partner made a contribution to the capital of the Partnership at the conclusion of its offering period in an amount equal to 1% of its net capital contributions. The Managing General Partner contribution was $9,800. Total capital contributions were $1,154,300.
The Partnership was formed to engage primarily in the business of drilling developmental and exploratory wells, to produce and market crude oil and natural gas produced from such properties, to distribute any net proceeds from operations to the general and limited partners and to the extent necessary, acquire leases which contain drilling prospects. Net revenues will not be reinvested in other revenue producing assets except to the extent that performance of remedial work is needed to improve a well's producing capabilities. The economic life of the Partnership thus depends on the period over which the Partnership's oil and gas reserves are economically recoverable.
Based on current conditions, management anticipates performing no workovers during 2001 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.
A. General Comparison of the Years Ended December 31, 2000 and 1999
The following table provides certain information regarding performance factors for the years ended December 31, 2000 and 1999:
Year Ended December 31, Percentage Increase 2000 1999 (Decrease) ---- ---- ---------
Average price per barrel of oil $ 29.88 16.88 77% Average price per mcf of gas $ 3.82 1.81 111% Oil production in barrels 4,600 12,800 (64%) Gas production in mcf 6,600 19,540 (66%) Gross oil and gas revenue $ 162,628 251,484 (35%) Net oil and gas revenue $ 83,755 171,878 (51%) Partnership distributions $ 121,035 85,000 42% Limited partner distributions $ 107,721 75,650 42% Per unit distribution to limited partners $ 94.12 66.10 42% Number of limited partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues decreased to $162,628 from $251,484 for the years ended December 31, 2000 and 1999, respectively, a decrease of 35%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 77%, or $13.00 per barrel, resulting in an increase of approximately $59,800 in revenues. Oil sales represented %85 of total oil and gas sales during the year ended December 31, 2000 as compared to 86% during the year ended December 31, 1999.
The average price for an mcf of gas received by the Partnership increased during the same period by 111%, or $2.01 per mcf, resulting in an increase of approximately $13,300 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $73,100. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 8,200 barrels or 64% during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $138,400 in revenues.
Gas production decreased approximately 12,940 mcf or 66% during the same period, resulting in a decrease of approximately $23,400 in revenues.
The total decrease in revenues due to the change in production is approximately $161,800. The sharp decrease in oil and gas production is in relation to a settlement of royalty on the Dagger Draw Lease. Production interest of approximately 5,000 bbls and 7,230 mcfs were held in suspense from 1993 through 1999. These dollars were received and recorded in the Partnership during the third quarter of 1999. Production without the settlement would be a decrease of 25% for oil and 29% for gas. This decrease was due to the occurrence of payout on the Dagger Draw. Upon occurrence of payout the percentage of ownership for the Partnership decrease significantly.
Costs and Expenses
Total costs and expenses decreased to $104,642 from $132,036 for the years ended December 31, 2000 and 1999, respectively, a decrease of 21%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative costs.
1. Lease operating costs and production taxes were 1% lower, or approximately $700 less during the year ended December 31, 2000 as compared to the year ended December 31, 1999.
2. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 10% or approximately $1,700 during the year ended December 31, 2000 as compared to the year ended December 31, 1999.
3. Depletion expense decreased to $11,000 for the year ended December 31, 2000 from $36,000 for the same period in 2000. This represents a decrease of 69%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by the Partnership's independent petroleum consultants.
The major factor to the decline in depletion expense between the comparative periods was the increase in oil and gas prices of the 2001 reserves as compared to 2000.
Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $4,000 as of December 31, 1999.
B. 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 December 31, Percentage Increase 1999 1998 (Decrease) ---- ---- ---------
Average price per barrel of oil $ 16.88 12.74 32% Average price per mcf of gas $ 1.81 1.60 13% Oil production in barrels 12,800 11,300 13% Gas production in mcf 19,540 17,800 10% Gross oil and gas revenue $ 251,484 172,545 46% Net oil and gas revenue $ 171,878 72,410 137% Partnership distributions $ 85,000 40,500 110% Limited partner distributions $ 75,650 36,045 110% Per unit distribution to limited partners $ 66.10 31.49 110% Number of limited partner units 1,144.5 1,144.5
Revenues
The Partnership's oil and gas revenues increased to $251,484 from $172,545 for the years ended December 31, 1999 and 1998, respectively, an increase of 46%. 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 32%, or $4.14 per barrel, resulting in an increase of approximately $46,800 in revenues. Oil sales represented 86% of total oil and gas sales during the year ended December 31, 1999 as compared to 83% 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 13%, or $.21 per mcf, resulting in an increase of approximately $3,700 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $50,500. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production increased approximately 1,500 barrels or 13% during the year ended December 31, 1999 as compared to the year ended December 31, 1998, resulting in an increase of approximately $25,300 in revenues.
Gas production increased approximately 1,740 mcf or 10% during the same period, resulting in an increase of approximately $3,100 in revenues.
The total increase in revenues due to the change in production is approximately $28,400. The increase in production is in relation to a settlement of royalty on the Dagger Draw lease. Production interest of approximately 5,000 bbls and 7,230 mcfs were held in suspense from 1993 through 1999. These dollars were received and recorded in the Partnership during the third quarter of 1999. Production without the settlement would have actually decreased oil by 31% and gas by 30%. This decrease was due primarily to a decrease of the Partnerships interest in the Dagger Draw lease in relation to a fairness letter.
Costs and Expenses
Total costs and expenses decreased to $132,036 from $176,025 for the years ended December 31, 1999 and 1998, respectively, a decrease of 25%. The decrease is the result of lower lease operating costs, depletion expense and general and administrative costs.
2. Lease operating costs and production taxes were 21% lower, or approximately $20,500 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 workover expenses incurred during 1998 and the issuance of a fairness letter, which decreased the Partnership's ownership percentage on the Dagger Draw.
2. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 28% or approximately $6,500 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.
3. Depletion expense decreased to $36,000 for the year ended December 31, 1999 from $53,000 for the same period in 1999. This represents a decrease of 32%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by the Partnership's independent petroleum consultants.
A contributing factor to the decline in depletion expense between the comparative periods was 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 $19,000 as of December 31, 1998.
C. Revenue and Distribution Comparison
Partnership net income (loss) for the years ended December 31, 2000, 1999 and 1998 was $58,242, $119,990 and $(3,178), respectively. Excluding the effects of depreciation, depletion and amortization, net income for the years ended December 31, 2000, 1999 and 1998 was $69,242, $155,990 and $49,822, respectively. Correspondingly, Partnership distributions for the years ended December 31, 2000, 1999 and 1998 were $121,035, $85,000 and $40,500, respectively.
The sources for the 2000 distributions of $121,035 were oil and gas operations of approximately $78,700 and the change in oil and gas properties of approximately $(200), with the balance from available cash on hand at the beginning of the period. The sources for the 1999 distributions of $85,000 were oil and gas operations of approximately $134,600 and the change in oil and gas properties of approximately $(900), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1998 distributions of $40,500 were oil and gas operations of approximately $67,300 and the change in oil and gas properties of approximately $(21,800), resulting in excess cash for contingencies or subsequent distributions.
Total distributions during the year ended December 31, 2000 were $121,035 of which $107,721 was distributed to the investor partners and $13,314 to the Managing General Partner. The per unit distribution to investor partners during the same period was $94.12. Total distributions during the year ended December 31, 1999 were $85,000 of which $75,650 was distributed to the investor partners and $9,350 to the Managing General Partner. The per unit distribution to investor partners during the same period was $66.10. Total distributions during the year ended December 31, 1998 were $40,500 of which $36,045 was distributed to the investor partners and $4,455 to the Managing General Partner. The per unit distribution to investor partners during the same period was $31.49.
Since inception of the Partnership, cumulative monthly cash distributions of $1,333,775 have been made to the partners. As of December 31, 2000, $1,188,971 or $1,038.86 per investor partner unit, has been distributed to the investor partners, representing a 104% return of the capital contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from oil and gas properties. The Partnership anticipates the primary source of cash to continue being from the oil and gas operations.
Cash flows provided by operating activities were approximately $78,700 in 2000 compared to $134,600 in 1999 and approximately $67,300 in 1998. The primary source of the 2000 cash flow from operating activities was profitable operations.
Cash flows used in investing activities were approximately $200 in 2000 compared to $900 in 1999 and approximately $21,800 in 1998. The principal use of the 2000 cash flow from investing activities was additions to oil and gas properties.
Cash flows used in financing activities were approximately $120,400 in 2000 compared to $88,200 in 1999 and approximately $38,200 in 1998. The only use in the 2000 financing activities was the distributions to partners.
As of December 31, 2000, the Partnership had approximately $26,500 in working capital. The Managing General Partner knows of no unusual contractual commitments and believes the revenue generated from operations are adequate to meet the needs of the Partnership.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership is not a party to any derivative or embedded derivative instruments.
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 Developmental Drilling Fund 91-A, L.P. (A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 91-A, L.P. (the "Partnership") as of December 31, 2000 and 1999, 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, 2000. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 91-A, L.P. as of December 31, 2000 and 1999 and the results of its operations and its cash flows for each of the years in the three- year period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP
Midland, Texas March 21, 2001
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 2000 and 1999
2000 1999 ---- ----
Assets
Current assets: Cash and cash equivalents $ 14,338 56,196 Receivable from Managing General Partner 12,165 21,634 Distribution receivable - 617
- --------- --------- Total current assets 26,503 78,447
- --------- --------- Oil and gas properties - using the full- cost method of accounting 1,098,592 1,098,441 Less accumulated depreciation, depletion and amortization 960,000 949,000
- --------- --------- Net oil and gas properties 138,592 149,441
- --------- --------- $ 165,095 227,888
========= ========= Liabilities and Partners' Equity
Partners' equity:
Managing General Partner $ 23,823 29,520 Investor partners 141,272 198,368
- --------- --------- Total partners' equity 165,095 227,888
- --------- --------- $ 165,095 227,888
========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership) Statements of Operations For the years ended December 31, 2000, 1999 and 1998
2000 1999 1998 ---- ---- ----
Revenues
Oil and gas sales $ 162,628 251,484 172,545 Interest income from operations 256 542 302 ------- - ------- ------- 162,884 252,026 172,847 ------- - ------- ------- Expenses
Production 78,873 79,606 100,135 General and administrative 14,769 16,430 22,890 Depreciation, depletion and amortization 11,000 36,000 53,000 ------- - ------- ------- 104,642 132,036 176,025 ------- - ------- ------- Net income (loss) $ 58,242 119,990 (3,178) ======= ======= ======= Net income (loss) allocated to:
Managing General Partner $ 7,617 17,159 5,480 ======= ======= ======= Investor partners $ 50,625 102,831 (8,658) ======= ======= ======= Per investor partner unit $ 44.23 89.85 (7.57) ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity For the years ended December 31, 2000, 1999 and 1998
Managing General Investor Partner Partners Total ------- -------- -----
Balance at December 31, 1997 $ 20,686 215,890 236,576
Net income (loss) 5,480 (8,658) (3,178)
Distributions (4,455) (36,045) (40,500) ------- - -------- -------- Balance at December 31, 1998 21,711 171,187 192,898
Net income 17,159 102,831 119,990
Distributions (9,350) (75,650) (85,000) ------- - -------- -------- Balance at December 31, 1999 29,520 198,368 227,888
Net income 7,617 50,625 58,242
Distributions (13,314) (107,721)(121,035) ------- - -------- -------- Balance at December 31, 2000 $ 23,823 141,272 165,095 ======= ======== ========
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership) Statements of Cash Flows For the years ended December 31, 2000, 1999 and 1998
2000 1999 1998 ---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 166,419 235,741 188,548 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (87,964) (101,686)(121,567) Interest received 256 542 302 -------- - -------- -------- Net cash provided by operating activities 78,711 134,597 67,283 -------- - -------- -------- Cash flows from investing activities:
Additions to oil and gas properties (151) (873) (21,824) -------- - -------- -------- Cash flows from financing activities:
Distributions to partners (120,418) (88,247) (38,217) -------- - -------- -------- Net (decrease) increase in cash and cash equivalents (41,858) 45,477 7,242
Beginning of period 56,196 10,719 3,477 -------- - -------- -------- End of period $ 14,338 56,196 10,719 ======== ======== ========
(continued)
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership) Statements of Cash Flows, continued Years ended December 31, 2000, 1999 and 1998
2000 1999 1998 ---- ---- ----
Reconciliation of net income (loss) to net cash provided by operating activities:
Net income (loss) $ 58,242 119,990 (3,178)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 11,000 36,000 53,000 Decrease (increase) in receivables 3,791 (15,743) 16,003 Increase (decrease) in payables 5,678 (5,650) 1,458 ------- - ------- ------- Net cash provided by operating activities $ 78,711 134,597 67,283 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Developmental Drilling Fund 91-A, L.P. was organized under the laws of the state of Delaware on January 7, 1991 for the purpose of drilling developmental and exploratory wells and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:
Managing General Investor Partner Partners -------- -------- Interest income on capital contributions - 100% Oil and gas sales* 11% 89% All other revenues* 11% 89% Organization and offering costs (1) - 100% Syndication costs - 100% Amortization of organization costs - 100% Lease acquisition costs 1% 99% Gain/loss on property disposition* 11% 89% Operating and administrative costs*(2) 11% 89% Depreciation, depletion and amortization of oil and gas properties - 100% Intangible drilling and development costs - 100% All other costs* 11% 89%
*After the Investor Partners have received distributions totaling 150% of their capital contributions, the allocation will change to 15% Managing General Partner and 85% Investor Partners.
(1) All organization costs in excess of 4% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 4% of initial capital contributions for such organization costs.
(2) Administrative costs in any year which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies
Oil and Gas Properties Oil and gas properties are accounted for at cost under the full-cost method. Under this method, all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are involved.
The Partnership's policy for depreciation, depletion and amortization of oil and gas properties is computed under the units of revenue method. Under the units of revenue method, depreciation, depletion and amortization is computed on the basis of current gross revenues from production in relation to future gross revenues, based on current prices, from estimated production of proved oil and gas reserves.
Under the units of revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership's independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.
Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2000, 1999 and 1998 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
Estimates and Uncertainties The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Syndication Costs Syndication costs are accounted for as a reduction of partnership equity.
Environmental Costs The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Gas Balancing The Partnership utilizes the sales method of accounting for gas- balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2000, 1999 and 1998, there were no significant amounts of imbalance in terms of units and value.
Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Partnership's tax basis in its net oil and gas properties at December 31, 2000 and 1999 is $130,818 and $131,815, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
Cash and Cash Equivalents For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Number of Investor Partner Units As of December 31, 2000, 1999 and 1998, there were 1,144.5 investor partner units outstanding held by 103, 103 and 99 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.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
3. Commitments and Contingent Liabilities The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by NationsBank, N.A. of Midland, Texas plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one- third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion.
The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.
As of December 31, 2000, 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 Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
4. 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 $11,400, $13,000 and $13,400 for the years ended December 31, 2000, 1999 and 1998, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.
Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $4,300, $7,300 and $3,200 for the years ended December 31, 2000, 1999 and 1998, 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 $10,800 in 2000, $11,000 in 1999 and $10,793 in 1998 for indirect general and administrative overhead expenses.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $12,200 and $21,600 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2000 and 1999, respectively.
In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services. The Partnership had no legal services for the years ended December 31, 2000, 1999 and 1998, respectively.
5. Major Customers No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 91% of the Partnership's total oil and gas production during 2000: Plains Marketing LP for 78% and Duke Energy Transport for 13%. Two purchasers accounted for 85% of the Partnership's total oil and gas production during 1999: Navajo Refining Company, Inc. for 52% and Scurlock Permian LLC for 33%. Three purchasers accounted for 93% of the Partnership's total oil and gas production during 1998: Navajo Refining Company, Inc. for 45%, Scurlock Permian Corporation 38% and Phillips 66 Natural Gas Company for 10%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's total oil and gas production.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. 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, 1998 55,000 70,000
Revisions of estimates in place 2,000 16,000 Production (11,000) (18,000) ------- ------- December 31, 1998 46,000 68,000
Revisions of estimates in place 11,000 13,000 Production (13,000) (20,000) ------- ------- December 31, 1999 44,000 61,000
Revisions of estimates in place 10,000 15,000 Production (5,000) (7,000) ------- ------- December 31, 2000 49,000 69,000 ======= =======
Proved developed reserves -
December 31, 1998 46,000 68,000 ======= ======= December 31, 1999 44,000 61,000 ======= ======= December 31, 2000 49,000 69,000 ======= =======
All of the Partnership's reserves are located within the continental United States.
*Ryder Scott Petroleum Engineers prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2001. 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, 2000 of $26.80 was used as the beginning basis for the oil price. Oil price adjustments from $26.80 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 $26.18 per barrel in the preparation of the reserve report as of January 1, 2001.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil and Gas Reserves (unaudited) - continued In the determination of the gas price, the New York Mercantile Exchange price at December 31, 2000 of $9.78 was used as the beginning basis. Gas price adjustments from $9.78 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 $9.92 per Mcf in the preparation of the reserve report as of January 1, 2001.
The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing and proved developed non-producing. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. 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, 2000, 1999 and 1998 is presented below:
2000 1999 1998 ---- ---- ----
Future cash inflows $ 1,966,000 1,179,000 602,000 Production and development costs 1,129,000 686,000 374,000 --------- --------- --------- Future net cash flows 837,000 493,000 228,000 10% annual discount for estimated timing of cash flows 275,000 142,000 (47,000) --------- --------- --------- Standardized measure of discounted future net cash flows $ 562,000 351,000 275,000 ========= ========= =========
The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2000, 1999 and 1998 are as follows:
2000 1999 1998 ---- ---- ----
Sales of oil and gas produced, net of production costs $ (84,000) (172,000) (73,000) Changes in prices and production costs 157,000 167,000 (339,000) Changes of production rates (timing) and others (28,000) (20,000) 169,000 Revisions of previous quantities estimates 116,000 89,000 23,000 Changes in estimated future development costs 15,000 (16,000) - Accretion of discount 35,000 28,000 45,000 Discounted future net cash flows - Beginning of year 351,000 275,000 450,000 --------- -------- --------- End of year $ 562,000 351,000 275,000 ========= ======== =========
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.
Southwest Developmental Drilling Fund 91-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Selected Quarterly Financial Results - (unaudited)
Quarter ---------------------------------------------- First Second Third Fourth ------ ------- ------ ------ 2000: Total revenues $ 36,095 43,158 50,190 33,441 Total expenses 27,399 23,166 26,858 27,219 Net income 8,696 19,992 23,332 6,222 Net income per limited partners unit 6.38 15.35 17.76 4.74
1999: Total revenues $ 39,183 45,317 127,659 39,867 Total expenses 28,837 26,757 36,724 39,718 Net income 10,346 18,560 90,935 149 Net income (loss) per limited partners unit 7.37 13.99 69.91 (1.42)
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 45 Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
H. Allen Corey 44 Secretary and Director
Bill E. Coggin 46 Vice President and Chief Financial Officer
J. Steven Person 42 Vice President, Marketing
Paul L. Morris 59 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.B.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 the Columbia Gas System, Inc.
Key Employees
Jon P. Tate, Vice President, Land and Assistant Secretary, age 43, 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 American Association of Petroleum Landmen. Mr. Tate received his B.B.S. degree from Hardin-Simmons University.
R. Douglas Keathley, Vice President, Operations, age 45, 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 $10,800 during 2000, $11,000 during 1999 and $10,793 during 1998 as an annual administrative fee for reimbursement of indirect general and administrative costs.
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 an 11 percent interest as a Managing General Partner. Through prior purchases, the Managing General Partner also owns 5 limited partner units, or .4% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 11.4%.
No officer or director of the Managing General Partner owns Units in the Partnership. 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 2000, the Managing General Partner received $10,800 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 $11,400 for administrative overhead attributable to operating such properties during 2000.
Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $4,300 for the year ended December 31, 2000.
The law firm of Baker, Donelson, Bearman & Caldwell, of which H. Allen Corey, an officer and director of the Managing General Partner, is a partner, is counsel to the Partnership. Baker, Donelson, Bearman & Caldwell provided services totaling approximately. There were no legal services for the year ended December 31, 2000, which constitutes an immaterial portion of that firm's business.
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 Sheets 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 Developmental Drilling Fund 91-A, L.P., dated January 9, 1991. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1991.)
(b) Agreement of Limited Partnership of Southwest Developmental Drilling Fund 91-A, L.P. dated January 9, 1991. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1991.)
(c) Second Amended and Restated Certificate of Limited Partnership of Southwest Developmental Drilling Fund 91-A. L.P., dated as of February 1, 1993. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1993.)
(d) Second Amended and Restated Certificate of Limited Partnership of Southwest Developmental Drilling Fund 91-A. L.P., dated as of January 12, 1994. (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, 2000.
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 Developmental Drilling Fund 91- 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 30, 2001
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 30, 2001
By: /s/ H. Allen Corey ----------------------------- H. Allen Corey, Secretary and Director
Date: March 30, 2001