Item 1. Business
General Southwest Developmental Drilling Fund 92-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on May 5, 1992. The offering of limited and general partner interests began August 11, 1992 as part of a shelf offering registered under the name Southwest Developmental Drilling Program 1991-92. Minimum capital requirements for the Partnership were met on December 28, 1992, with the offering of limited and general partner interests concluding December 31, 1992, with total investor partner contributions of $1,407,000. The Managing General Partner made a contribution to the capital of the Partnership at the conclusion of the offering period in an amount equal to 1% of its net capital contributions. The Managing General Partner contribution was $12,030, for total capital contributions of $1,419,030. 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 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 leasehold interests upon which drilling would be performed, and the marketing of future anticipated production from such properties. The Partnership has no employees.
Principal Products, Marketing and Distribution The Partnership has acquired undeveloped 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 will be 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 78% 22% 1999 77% 23% 1998 74% 26%
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 of 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 anticipates that it will be able to sell all of the expected future production of natural gas, either through contracts or on the spot market at the then prevailing spot market price.
Customer Dependence No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 94% of the Partnership's total oil and gas production during 2000: Plains Marketing LP for 63%, Navajo Refining Company, Inc. for 16% and Duke Energy Transport for 15%. Three purchasers accounted for 95% of the Partnership's total oil and gas production during 1999: Scurlock Permian LLC for 59%, Duke Energy Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%. Three purchasers accounted for 95% of the Partnership's total oil and gas production during 1998: Scurlock Permian Corporation for 59%, Duke Energy Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could 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 drilling prospects and drilling activities, 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 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 future expected 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, 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, 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 leasehold was to be acquired, the Managing General Partner considered such criteria as estimated drilling costs, estimated oil and gas reserves, estimated cash flow from the sale of future production, present and future prices of oil and gas, the extent of undeveloped and unproved reserves and the availability of markets.
As of December 31, 2000, the Partnership possessed an interest in oil and gas properties located in Ward County of Texas and Lea and Eddy Counties of New Mexico. These properties consist of various interests in 9 wells.
Due to the Partnership's objective of maintaining current operations without engaging in the additional 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 properties in which the Partnership has an interest:
Date Purchased No. of Proved Reserves* Name and Location and Interest Wells Oil (bbls) Gas (mcf)
Mobil Fee G #1 12/92 at 1 36,000 44,000 Ward County, 100% Texas working interest
Mobil Fee H #1 12/92 at 1 58,000 171,000 Ward County, 100% Texas working interest
*Ryder Scott Petroleum Engineer 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 $26.17 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 $9.99 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. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves.
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.
The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by Nations Bank, N.A. of Midland, Texas, plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion. In 2000, 5 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $181.86 per unit. As of December 31, 1999 and 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.
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 $224,640, with $199,930 distributed to the investor partners and $24,710 to the Managing General Partners. For the year ended December 31, 2000, distributions of $142.10 per investor partner unit were made, based upon 1,407 investor partner units outstanding. Distributions for 2000 increased significantly due to the record high oil and gas prices received during the year. During 1999, distributions were made totaling $85,000, with $75,650 distributed to the investor partners and $9,350 to the Managing General Partners. For the year ended December 31, 1999, distributions of $53.77 per investor partner unit were made, based upon 1,407 investor partner units outstanding. During 1998, distributions were made totaling $92,200, with $82,058 distributed to the investor partners and $10,142 to the Managing General Partners. For the year ended December 31, 1998, distributions of $58.32 per investor partner unit were made, based upon 1,407 investor partner units outstanding.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the year ended December 31, 2000, 1999, 1998, 1997 and 1996 should be read in conjunction with the financial statements included in Item 8:
Year ended December 31, ------------------------------------------------ 2000 1999 1998 1997 1996 ---- ---- ---- ---- ----
Revenues $ 372,553 249,965 201,370 335,791 425,671
Net income (loss) 217,640 112,767 (331,847) 93,437 178,706
Partners' share of net income (loss):
Managing General Partner 25,590 14,274 6,863 19,601 28,208
Investor partners 192,050 98,493 (338,710) 73,836 150,498
Investor partners' net income (loss) per unit 136.50 70.00 (240.73) 52.48 106.96
Investor partners' cash distributions per unit 142.10 53.77 58.32 129.99 158.14
Total assets $ 279,195 286,195 258,508 682,573 794,538
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
Southwest Developmental Drilling Fund 92-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on May 5, 1992. The offering of limited and general partner interests began August 11, 1992 as part of a shelf offering registered under the name Southwest Developmental Drilling Program 1991-92. Minimum capital requirements for the Partnership were met on December 28, 1992, with the offering of limited and general partner interests concluding December 31, 1992, with total investor partner contributions of $1,407,000. The Managing General Partner made a contribution to the capital of the Partnership at the conclusion of the offering period in an amount equal to 1% of its net capital contributions. The Managing General Partner contribution was $12,030.
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 to enhance production. The partnership will most likely experience the historical production decline of approximately 10% per year.
Results of Operations
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 Percentage December 31, Increase 2000 1999 (Decrease) ---- ---- ---------
Average price per barrel of oil $ 29.73 17.74 68% Average price per mcf of gas $ 3.98 2.35 69% Oil production in barrels 9,800 10,770 (9%) Gas production in mcf 20,200 24,940 (19%) Gross oil and gas revenue $ 371,824 249,636 49% Net oil and gas revenue $ 247,853 146,852 69% Partnership distributions $ 224,640 85,000 164% Limited partner distributions $ 199,930 75,650 164% Per unit distribution to limited partners $ 142.10 53.77 164% Number of limited partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues increased to $371,824 from $249,636 for the years ended December 31, 2000 and 1999, respectively, an increase of 49%. The principal factors affecting the comparison of the years ended December 31, 2000 and 1999 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2000 as compared to the year ended December 31, 1999 by 68%, or $11.99 per barrel, resulting in an increase of approximately $117,500 in revenues. Oil sales represented 78% of total oil and gas sales during the year ended December 31, 2000 as compared to 77% during the year ended December 31, 1999.
The average price for an mcf of gas received by the Partnership increased during the same period by 69%, or $1.63 per mcf, resulting in an increase of approximately $32,900 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $150,400. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 970 barrels or 9% during the year ended December 31, 2000 as compared to the year ended December 31, 1999, resulting in a decrease of approximately $17,200 in revenues.
Gas production decreased approximately 4,470 mcf or 19% during the same period, resulting in a decrease of approximately $11,100 in revenues.
The total decrease in revenues due to the change in production is approximately $28,300.
Costs and Expenses
Total costs and expenses increased to $154,913 from $137,198 for the years ended December 31, 2000 and 1999, respectively, an increase of 13%. The increase is the result of higher lease operating costs, partially offset by a decrease in depletion expense and general and administrative expense.
1. Lease operating costs and production taxes were 21% higher, or approximately $21,200 more during the year ended December 31, 2000 as compared to the year ended December 31, 1999. The increase in lease operating costs and production taxes is due in part to an increase in major repairs and maintenance, such as overhead and electrical repairs on two leases, and in part to the rise in production taxes directly associated with the rise in oil and gas prices received during the past year. The rise in oil and gas prices for 2000 has allowed the Partnership to perform these repairs and maintenance in the hopes of increasing production, thereby increasing revenues.
2. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs decreased 8% or approximately $1,500 during the year ended December 31, 2000 as compared to the year ended December 31, 1999.
3. Depletion expense decreased to $15,000 for the year ended December 31, 2000 from $17,000 for the same period in 1999. This represents a decrease of 12%. Depletion is calculated using the units of revenue method of amortization based on 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 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, 2001 as compared to 2000. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $3,000 as of December 31, 1999.
Results of Operations
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 Percentage December 31, Increase 1999 1998 (Decrease) ---- ---- ---------
Average price per barrel of oil $ 17.74 12.75 39% Average price per mcf of gas $ 2.35 1.93 22% Oil production in barrels 10,770 11,700 (8%) Gas production in mcf 24,940 26,800 (7%) Gross oil and gas revenue $ 249,636 200,761 24% Net oil and gas revenue $ 146,852 86,072 71% Partnership distributions $ 85,000 92,200 (8%) Limited partner distributions $ 75,650 82,058 (8%) Per unit distribution to limited partners $ 53.77 58.32 (8%) Number of limited partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues increased to $249,636 from $200,761 for the years ended December 31, 1999 and 1998, respectively, an increase of 24%. 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 39%, or $4.99 per barrel, resulting in an increase of approximately $58,400 in revenues. Oil sales represented 77% of total oil and gas sales during the year ended December 31, 1999 as compared to 74% 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 22%, or $.42 per mcf, resulting in an increase of approximately $11,300 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $69,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 930 barrels or 8% during the year ended December 31, 1999 as compared to the year ended December 31, 1998, resulting in a decrease of approximately $16,500 in revenues.
Gas production decreased approximately 1,860 mcf or 7% during the same period, resulting in a decrease of approximately $4,400 in revenues.
The total decrease in revenues due to the change in production is approximately $20,900.
Costs and Expenses
Total costs and expenses decreased to $137,198 from $533,217 for the years ended December 31, 1999 and 1998, respectively, a decrease of 74%. The decrease is the result of lower depletion expense, general and administrative expense, provision for impairment and lease operating costs.
2. Lease operating costs and production taxes were 10% lower, or approximately $11,900 less during the year ended December 31, 1999 as compared to the year ended December 31, 1998.
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 $6,900 during the year ended December 31, 1999 as compared to the year ended December 31, 1998. The decrease of general and administrative costs were due in part to additional accounting costs incurred in 1998 in relation to the outsourcing of K-1 tax package preparation and a change in auditors requiring opinions from both the predecessors and successor auditors. Additionally, the Managing General Partner in its effort to cut back on general and administrative costs whenever and wherever possible was able to reduce the cost of reserve reports and K-1 tax package preparation during 1999.
3. Depletion expense decreased to $17,000 for the year ended December 31, 1999 from $80,000 for the same period in 1998. This represents a decrease of 79%. 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 $34,000 as of December 31, 1998.
4. The Partnership reduced the net capitalized costs of oil and gas properties during 1998 by $314,240. 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 (loss) for the years ended December 31, 2000, 1999 and 1998 was $217,640, $112,767 and $(331,847), respectively. Excluding the effects of depreciation, depletion and amortization and provision for impairment, net income for the years ended December 31, 2000, 1999 and 1998, would have been $232,640, $129,767 and $62,393, respectively. Correspondingly, Partnership distributions for the years ended December 31, 2000, 1999 and 1998 were $224,640, $85,000 and $92,200, respectively. These differences are indicative of the changes in oil and gas prices, production and property during 2000, 1999 and 1998.
The sources for the 2000 distributions of $224,640 were oil and gas operations of approximately $228,800 and the change in oil and gas properties of approximately $(75), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1999 distributions of $85,000 were oil and gas operations of approximately $100,300 and the change in oil and gas properties of approximately $(20), resulting in excess cash for contingencies or subsequent distributions. The sources for the 1998 distributions of $92,200 were oil and gas operations of approximately $90,900 and the change in oil and gas properties of approximately $900, with the balance from available cash on hand at the beginning of the period.
Total distributions during the year ended December 31, 2000 were $224,640 of which $199,930 was distributed to the investor partners and $24,710 to the Managing General Partners. The per unit distribution to investor partners during the same period was $142.10. Total distributions during the year ended December 31, 1999 were $85,000 of which $75,650 was distributed to the investor partners and $9,350 to the Managing General Partners. The per unit distribution to investor partners during the same period was $53.77. Total distributions during the year ended December 31, 1998 were $92,200 of which $82,058 was distributed to the investor partners and $10,142 to the Managing General Partners. The per unit distribution to investor partners during the same period was $58.32.
Since inception of the Partnership, cumulative monthly cash distributions of $1,377,555 have been made to the partners. As of December 31, 2000, $1,226,400 or $871.64 per investor partner unit, has been distributed to the investor partners, representing a 87% 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 $228,800 in 2000 compared to $100,300 in 1999 and approximately $90,900 in 1998. The primary source of the 2000 cash flow from operating activities was profitable operations.
Cash flows (used in) provided by investing activities were approximately $(75) in 2000 compared to $(20) in 1999 and approximately $900 in 1998.
Cash flows used in financing activities were approximately $224,600 in 2000 compared to $85,100 in 1999 approximately $92,200 in 1998. The only use in the 2000 financing activities was the distributions to partners.
As of December 31, 2000, the Partnership had $67,900 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
Statement 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 92-A (A Delaware Limited Partnership):
We have audited the accompanying balance sheets of Southwest Developmental Drilling Fund 92-A (the "Partnership") as of December 31, 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 92-A 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 92-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 2000 and 1999
2000 1999 ---- ---- Assets
Current assets: Cash and cash equivalents $ 26,865 22,743 Receivable from Managing General Partner 41,053 37,250
- --------- --------- Total current assets 67,918 59,993
- --------- --------- Oil and gas properties - using the full- cost method of accounting 1,314,517 1,314,442 Less accumulated depreciation, depletion and amortization 1,103,240 1,088,240
- --------- --------- Net oil and gas properties 211,277 226,202
- --------- --------- $ 279,195 286,195
========= =========
Liabilities and Partners' Equity
Partners' equity: Managing General Partner $ 30,554 29,674 Investor partners 248,641 256,521
- --------- --------- Total partners' equity 279,195 286,195
- --------- --------- $ 279,195 286,195
========= =========
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 92-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 $ 371,824 249,636 200,761 Interest income from operations 729 329 609 ------- - ------- ------- 372,553 249,965 201,370 ------- - ------- -------
Expenses
Production 123,971 102,784 114,689 General and administrative 15,942 17,414 24,288 Depreciation, depletion and amortization 15,000 17,000 80,000 Provision for impairment of oil and gas properties - - 314,240 ------- - ------- ------- 154,913 137,198 533,217 ------- - ------- ------- Net income (loss) $ 217,640 112,767(331,847) ======= ======= ======= Net income (loss) allocated to:
Managing General Partner $ 25,590 14,274 6,863 ======= ======= ======= Investor partners $ 192,050 98,493(338,710) ======= ======= ======= Per investor partner unit $ 136.50 70.00 (240.73) ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 2000, 1999 and 1998
Managing General Investor Partner Partners Total -------- -------- -----
Balance at December 31, 1997 $ 28,029 654,446 682,475
Net income (loss) 6,863 (338,710)(331,847)
Distributions (10,142) (82,058) (92,200) ------ - --------- -------- Balance at December 31, 1998 24,750 233,678 258,428
Net income 14,274 98,493 112,767
Distributions (9,350) (75,650) (85,000) ------ - --------- -------- Balance at December 31, 1999 29,674 256,521 286,195
Net income 25,590 192,050 217,640
Distributions (24,710) (199,930)(224,640) ------ - --------- -------- Balance at December 31, 2000 $ 30,554 248,641 279,195 ====== ========= ========
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2000, 1999 and 1998
2000 1999 1998 ---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 361,584 223,480 223,677 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (133,476) (123,478)(133,373) Interest received 729 329 609 ------- - ------- ------- Net cash provided by operating activities 228,837 100,331 90,913 ------- - ------- ------- Cash flows from investing activities:
Addition to oil and gas properties (75) (20) - Sale of oil and gas properties - - 930 ------- - ------- ------- Net cash (used in) provided by investing activities(75) (20) 930 ------- - ------- ------- Cash flows from financing activities:
Distributions to partners (224,640) (85,080) (92,218) ------- - ------- ------- Net increase (decrease) in cash and cash equivalents 4,122 15,231 (375)
Beginning of period 22,743 7,512 7,887 ------- - ------- ------- End of period $ 26,865 22,743 7,512 ======= ======= =======
(continued)
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 92-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) $ 217,640 112,767(331,847)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 15,000 17,000 80,000 Provision for impairment of oil and gas properties - - 314,240 (Increase) decrease in receivables (10,240) (26,156) 22,916 Increase (decrease) in payables 6,437 (3,280) 5,604 ------- - ------- ------- Net cash provided by operating activities $ 228,837 100,331 90,913 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Developmental Drilling Fund 92-A, L.P. was organized under the laws of the state of Delaware on May 5, 1992, for the purpose of engaging primarily in the business of drilling developmental and exploratory wells, to produce and market crude oil and natural gas produced from such properties, and acquire leases which contain drilling prospects. The activities of the Partnership should continue for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership anticipates selling its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:
Managing General General 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 92-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 future gross revenue method, the Partnership computes the provision by multiplying the total unamortized cost of oil and gas properties by an overall rate determined by dividing (a) oil and gas revenues during the period by (b) the total future gross oil and gas revenues as estimated by the Partnership's independent petroleum consultants. It is reasonably possible that those estimates of anticipated future gross revenues, the remaining estimated economic life of the product, or both could be changed significantly in the near term due to the potential fluctuation of oil and gas prices or production. The depletion estimate would also be affected by this change.
Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2000 and 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 $314,240 was made to the financial statement.
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.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Environmental Costs The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs which improve a property as compared with the condition of the property when originally constructed or acquired and costs which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Gas Balancing The Partnership utilizes the sales method of accounting for over or under deliveries of gas. Under this method, the Partnership records revenues based on the payments it has received for sales from purchasers. As of December 31, 2000, 1999 and 1998, the Partnership was not over or under produced.
Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the Partnership's tax basis in its net oil and gas assets at December 31, 2000 and 1999 was $194,608 and $190,321, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
Cash and Cash Equivalents For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.
Investor Partner Units As of December 31, 2000, 1999 and 1998, there were 1,407 investor units outstanding held by 103, 103 and 104 partners.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Concentrations of Credit Risk The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors' ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.
3. Commitments and Contingent Liabilities The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by Nations Bank, N.A. of Midland, Texas, plus one percent (1%), which value shall be further reduced by a risk factor discount of no more than one-third (1/3) to be determined by the Managing General Partner in its sole and absolute discretion.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
3. Commitments and Contingent Liabilities - continued The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.
As of December 31, 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.
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 $22,700, $22,400 and $20,900 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 $3,700, $2,900 and $100 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 an administrative fee of $12,000 during 2000, 1999 and 1998 for reimbursement of indirect general and administrative overhead expenses.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
4. Related Party Transactions - continued In addition, a director and officer of the Managing General Partner is a partner in a law firm, with such firm providing legal services to the Partnership. There were no legal services for December 31, 2000, 1999 and 1998.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $41,100 and $37,250 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2000 and 1999, respectively.
5. Major Customers No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchaser, where the loss of one would have a material adverse impact on the Partnership. Three purchasers accounted for 94% of the Partnership's total oil and gas production during 2000: Plains Marketing LP for 63%, Navajo Refining Company, Inc. for 16% and Duke Energy Transport for 15%. Three purchasers accounted for 95% of the Partnership's total oil and gas production during 1999: Scurlock Permian LLC for 59%, Duke Energy Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%. Three purchasers accounted for 95% of the Partnership's total oil and gas production during 1998: Scurlock Permian Corporation for 59%, Duke Energy Transport and Trad. for 20% and Navajo Refining Company, Inc. for 16%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event this purchaser were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could 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.
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 118,000 288,000
Production (12,000) (27,000) Revisions of estimates in place (30,000) (93,000) ------- ------- December 31, 1998 76,000 168,000
Production (11,000) (25,000) Revisions of estimates in place 44,000 166,000 ------- ------- December 31, 1999 109,000 309,000
Production (10,000) (20,000) Revisions of estimates in place 11,000 (47,000) ------- ------- December 31, 2000 110,000 242,000 ======= =======
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil and Gas Reserves (unaudited) - continued
Oil (bbls) Gas (mcf) ---------- --------- Proved developed reserves -
December 31, 1998 76,000 168,000 ======= ======= December 31, 1999 109,000 309,000 ======= ======= December 31, 2000 110,000 242,000 ======= =======
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 $26.17 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 $9.99 per Mcf in the preparation of the reserve report as of January 1, 2001.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. Estimated Oil and Gas Reserves (unaudited) - continued The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves which are classified as proved developed producing. All of the proved reserves are included in the engineering reports which evaluate the Partnership's present reserves.
Southwest Developmental Drilling Fund 92-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 $ 5,290,000 3,328,000 1,160,000 Production and development costs 2,403,000 1,838,000 819,000 --------- --------- --------- Future net cash flows 2,887,000 1,490,000 341,000 10% annual discount for estimated timing of cash flows 1,309,000 603,000 98,000 --------- --------- --------- Standardized measure of discounted future net cash flows $ 1,578,000 887,000 243,000 ========= ========= =========
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 $ (248,000) (147,000) (86,000)) Changes in prices and production costs 866,000 374,000 (410,000) Changes of production rates (timing) and others (49,000) (3,000) 38,000 Revisions of previous quantities estimates 33,000 396,000 (106,000) Accretion of discount 89,000 24,000 73,000 Discounted future net cash flows - Beginning of year 887,000 243,000 734,000 --------- -------- -------- End of year $ 1,578,000 887,000 243,000 ========= ======== ========
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 92-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 $ 90,020 92,567 108,127 81,839 Total expenses 37,602 37,618 45,451 34,242 Net income 52,418 54,949 62,676 47,597 Net income per limited partners unit 32.77 34.52 39.25 29.95
1999: Total revenues $ 40,048 55,753 77,295 76,869 Total expenses 35,314 29,144 41,174 31,566 Net income 4,734 26,609 36,121 45,303 Net income per limited partners unit 2.60 16.52 22.61 28.27
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 $12,000 during 2000, 1999 and 1998 as an administrative fee for reimbursement of indirect general and administrative expenses.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
There are no investor partners who own of record, or are known by the Managing General Partner to beneficially own, more than five percent of the Partnership's investor partner 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 11.3%.
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 $12,000 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 $22,700 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 $3,700 for the period ended December 31, 2000.
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 Changes in Partners' Equity Statement of Cash Flows Notes to Financial Statements
(2) Schedules I through XIII are omitted because they are not applicable, or because the required information is shown in the financial statements or the notes thereto.
(3) Exhibits:
Exhibit 4(a): Certificate of Limited Partnership of Southwest Developmental Drilling Fund 92-A, L.P., dated May 5, 1992 (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1992).
Exhibit 4(b): Agreement of Limited Partnership of Southwest Developmental Drilling Fund 92-A, L.P. dated May 5, 1992 (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1992).
Exhibit 4(c): First Amendment to Amended and Restated Certificate of Limited Partnership of Southwest Developmental Drilling Fund 92-A. L.P., dated as of February 22, 1993 (Incorporated by reference from Partner ship's Form 10-K for the fiscal year ended December 31, 1993).
Exhibit 4(d): Second Amendment to Amended and Restated Certificate of Limited Partnership of Southwest Developmental Drilling Fund 92-A. L.P., dated as of March 26, 1993 (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1993).
Exhibit 4(e): Second Amended and Restated Certificate of Limited Partnership of Southwest Developmental Drilling Fund 92-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
Reports on Form 8-K
(b) No report on Form 8-K was filed 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 92-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