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 97 individuals, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of 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.
Oil prices experienced a year of recovery during 1999. After seeing prices languish near $10 per barrel in December 1998, a rebound occurred that would briefly push NYMEX pricing over $27 in late November 1999. Crude oil prices reached $20 per barrel in mid-July and would not fall below $21 the rest of the year. There were drastic improvements to the main factors that gave rise to the worst price depression in history. These improvements provoked a spike in crude oil prices to levels not seen since the Gulf War. First, OPEC has done a remarkable job of adhering to production cuts agreed to in March, despite the temptation to cheat given current pricing. As prices have risen over the last twelve months, OPEC has consistently maintained a compliance rate above 90 percent. Also, most foreign markets are well on their way to recovery, greatly increasing the demand for energy in those countries. These and other factors have eliminated the "oversupply" of crude oil that we experienced in 1998. The near month contract for crude oil settled at $25.60 per barrel on December 30, 1999.
In 1999 natural gas prices rose 10% to an average of $2.18/MMBtu, 18 cents higher than the $2.00/MMBtu average seen in 1998. Despite warmer-than- normal heating seasons at both ends of the year, 1999 was the fourth year in a row that prices averaged $2.00/MMBtu or above. Citing lower storage levels and a rising demand for natural gas, industry experts are predicting a "healthy jump" in prices for 2000. Although higher prices in 1999 fueled an increase in production, end of year gas in storage nationwide is only 75% of capacity as compared to 87% at the end of 1998. Further, gas demand is expected to continue to increase at a faster pace than the amount of gas being replaced. A record breaking 70% of single-family homes built in 1999 were equipped with natural gas services ranging from traditional heating to water heating, cooking and grilling. Based on these encouraging statistics, we remain optimistic in our expectation of slightly higher natural gas prices in the coming year, hopefully seeing an average above the $2.20/MMBtu level.
Following is a table of the ratios of revenues received from oil and gas production for the last three years:
Oil Gas
1999 77% 23% 1998 74% 26% 1997 76% 24%
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 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%. Three purchasers accounted for 94% of the Partnership's total oil and gas production during 1997: Scurlock Permian Corporation for 60%, Aquila Southwest Pipeline Corporation for 19% and Navajo Refining Company, Inc. for 15%. 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, 1999, there were 97 individuals directly employed by the Managing General Partner in various capacities.
Item 2.
Item 2. Properties
In determining whether an interest in a particular 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, 1999, the Partnership possessed an interest in oil and gas properties located in Ward County of Texas and Lea and Eddy Counties of New Mexico and Ward County of Texas. 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 1999, 1998 and 1997.
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 79,000 Ward County, 100% Texas working interest
Mobil Fee H #1 12/92 at 1 56,000 208,000 Ward County, 100% Texas working interest
*Donald R. Creamer, P.E., an Independent Registered Petroleum Engineer prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2000. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.
The New York Mercantile Exchange price at December 31, 1999 of $25.60 was used as the beginning basis for the oil price. Oil price adjustments from $25.60 per barrel were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results are an average price received at the lease of $24.16 per barrel in the preparation of the reserve report as of January 1, 2000.
In the determination of the gas price, the New York Mercantile Exchange price at December 31, 1999 of $2.33 was used as the beginning basis. Gas price adjustments from $2.33 per Mcf were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results are an average price received at the lease of $2.25 per Mcf in the preparation of the reserve report as of January 1, 2000.
As also discussed in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, oil and gas prices were subject to frequent changes in 1999.
The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. 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 undeveloped. 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 1999 through the solicitation of proxies or otherwise.
Part II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
Market Information 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. As of December 31, 1999, 1998 and 1997, no limited partner units were purchased by the Managing General Partner.
Number of Limited and General Partner Interest Holders As of December 31, 1999, there were 104 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 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. During 1997, twelve monthly distributions were made totaling $205,500, with $182,895 distributed to the investor partners and $22,605 to the Managing General Partners. For the year ended December 31, 1997, distributions of $129.99 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, 1999, 1998, 1997, 1996 and 1995 should be read in conjunction with the financial statements included in Item 8:
Year ended December 31, ------------------------------------------------ 1999 1998 1997 1996 1995 ---- ---- ---- ---- ----
Revenues $ 249,965 201,370 335,791 425,671 455,640
Net income (loss) 112,767 (331,847) 93,437 178,706 165,968
Partners' share of net income (loss):
Managing General Partner 14,274 6,863 19,601 28,208 29,338
Investor partners 98,493 (338,710) 73,836 150,498 136,630
Investor partners' net income (loss) per unit 70.00 (240.73) 52.48 106.96 97.11
Investor partners' cash distributions per unit 53.77 58.32 129.99 158.14 170.79
Total assets $ 286,195 258,508 682,573 794,538 865,832
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, 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.
1. 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.
Results of Operations
B. General Comparison of the Years Ended December 31, 1998 and 1997
The following table provides certain information regarding performance factors for the years ended December 31, 1998 and 1997:
Year Ended Percentage December 31, Increase 1998 1997 (Decrease) ---- ---- ---------
Average price per barrel of oil $ 12.75 20.06 (36%) Average price per mcf of gas $ 1.93 2.65 (27%) Oil production in barrels 11,700 12,700 (8%) Gas production in mcf 26,800 30,000 (11%) Gross oil and gas revenue $ 200,761 334,355 (40%) Net oil and gas revenue $ 86,072 195,115 (56%) Partnership distributions $ 92,200 205,500 (55%) Limited partner distributions $ 82,058 182,895 (55%) Per unit distribution to limited partners $ 58.32 129.99 (55%) Number of limited partner units 1,407 1,407
Revenues
The Partnership's oil and gas revenues decreased to $200,761 from $334,355 for the years ended December 31, 1998 and 1997, respectively, a decrease of 40%. The principal factors affecting the comparison of the years ended December 31, 1998 and 1997 are as follows:
1. The average price for a barrel of oil received by the Partnership decreased during the year ended December 31, 1998 as compared to the year ended December 31, 1997 by 36%, or $7.31 per barrel, resulting in a decrease of approximately $92,800 in revenues. Oil sales represented 74% of total oil and gas sales during the year ended December 31, 1998 as compared to 76% during the year ended December 31, 1997.
The average price for an mcf of gas received by the Partnership decreased during the same period by 27%, or $.72 per mcf, resulting in a decrease of approximately $21,600 in revenues.
The total decrease in revenues due to the change in prices received from oil and gas production is approximately $114,400. 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 1,000 barrels or 8% during the year ended December 31, 1998 as compared to the year ended December 31, 1997, resulting in a decrease of approximately $12,800 in revenues.
Gas production decreased approximately 3,200 mcf or 11% during the same period, resulting in a decrease of approximately $6,200 in revenues.
The total decrease in revenues due to the change in production is approximately $19,000.
Costs and Expenses
Total costs and expenses increased to $533,217 from $242,354 for the years ended December 31, 1998 and 1997, respectively, an increase of 120%. The increase is the result of higher depletion expense, general and administrative expense and provision for impairment, partially offset by a decrease in lease operating costs.
2. Lease operating costs and production taxes were 18% lower, or approximately $24,600 less during the year ended December 31, 1998 as compared to the year ended December 31, 1997. Decrease is due primarily to a decrease in advalorem and production taxes.
2. General and administrative costs consist of independent accounting and engineering fees, computer services, postage, and Managing General Partner personnel costs. General and administrative costs increased 32% or approximately $5,900 during the year ended December 31, 1998 as compared to the year ended December 31, 1997. The increase in general and administrative costs are the result of higher accounting fees due to the necessity of contracting out preparation of tax depletion and K- 1 schedules.
3. Depletion expense increased to $80,000 for the year ended December 31, 1998 from $76,000 for the same period in 1997. This represents an increase of 5%. Depletion is calculated using the units of revenue method of amortization based on a percentage of current period gross revenues to total future gross oil and gas revenues, as estimated by the Partnership's independent petroleum consultants.
A contributing factor to the increase in depletion expense between the comparative periods was the decrease in the price of oil and gas used to determine the Partnership's reserves for January 1, 1999 as compared to 1998. Another contributing factor was due to the impact of revisions of previous estimates on reserves. Revisions of previous estimates can be attributed to the changes in production performance, oil and gas price and production costs. The impact of the revision would have increased depletion expense approximately $16,000 as of December 31, 1997.
4. The Partnership reduced the net capitalized costs of oil and gas properties 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, 1999, 1998 and 1997 was $112,767, $(331,847) and $93,437, respectively. Excluding the effects of depreciation, depletion and amortization and provision for impairment, net income for the years ended December 31, 1999, 1998 and 1997, would have been $129,767, $62,393 and $178,193, respectively. Correspondingly, Partnership distributions for the years ended December 31, 1999, 1998 and 1997 were $85,000, $92,200 and $205,500, respectively. These differences are indicative of the changes in oil and gas prices, production and property during 1999, 1998 and 1997.
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. The sources for the 1997 distributions of $205,500 were oil and gas operations of approximately $195,400 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.
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. Total distributions during the year ended December 31, 1997 were $205,500 of which $182,895 was distributed to the investor partners and $22,605 to the Managing General Partners. The per unit distribution to investor partners during the same period was $129.99.
Since inception of the Partnership, cumulative monthly cash distributions of $1,152,915 have been made to the partners. As of December 31, 1999, $1,026,470 or $729.55 per investor partner unit, has been distributed to the investor partners, representing a 73% 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 $100,300 in 1999 compared to $90,900 in 1998 and approximately $195,400 in 1997. The primary source of the 1999 cash flow from operating activities was profitable operations.
Cash flows provided by (used in) investing activities were approximately $(20) in 1999 compared to $900 in 1998 and approximately $200 in 1997.
Cash flows used in financing activities were approximately $85,100 in 1999 compared to $92,200 in 1998 and approximately $205,400 in 1997. The only use in the 1999 financing activities was the distributions to partners.
As of December 31, 1999, the Partnership had $60,000 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.
Liquidity - Managing General Partner
The Managing General Partner has a highly leveraged capital structure with over $35.1 million principal and $17.5 million interest payments due in 2000 on its debt obligations. Due to the severely depressed commodity prices experienced during the last quarter of 1997, throughout 1998 and continuing through the second quarter of 1999 the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.
There can be no assurance that the Managing General Partner's debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner's ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values.
Information Systems for the Year 2000
The year 2000 issue referred to the risk of disruptions of operations caused by the failure of computer-controlled systems, including systems used by third parties, to properly recognize date sensitive information when the year changed from 1999 to 2000. During the year ended December 31, 1999, the Managing General Partners data processing subsidiary, Midland Southwest Software, Inc., installed new software as part of an on-going project to upgrade its financial and management information systems. The cost of upgrading the software occurred in the normal course of Midland Southwest Software's business and was not material to the results of operations or financial condition of the Partnership.
The Partnership has not experienced any significant business disruptions due to year 2000 issues causing processing errors in its systems, or a third party's systems, during the period of operations after January 1, 2000 until the filing of the 10-K.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Independent Auditors Report 19
Balance Sheets 20
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, 1999 and 1998, and the related statements of operations, changes in partners' equity and cash flows for each of the years in the three-year period ended December 31, 1999. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Developmental Drilling Fund 92-A as of December 31, 1999 and 1998 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1999 in conformity with generally accepted accounting principles.
KPMG LLP
Midland, Texas March 10, 2000
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 1999 and 1998
1999 1998 ---- ---- Assets
Current assets: Cash and cash equivalents $ 22,743 7,512 Receivable from Managing General Partner 37,250 7,814
- --------- --------- Total current assets 59,993 15,326
- --------- --------- Oil and gas properties - using the full- cost method of accounting 1,314,442 1,314,422 Less accumulated depreciation, depletion and amortization 1,088,240 1,071,240
- --------- --------- Net oil and gas properties 226,202 243,182
- --------- --------- $ 286,195 258,508
========= =========
Liabilities and Partners' Equity
Current liability - distribution payable $ - 80
- --------- --------- Partners' equity: Investor partners 256,521 233,678 Managing General Partner 29,674 24,750
- --------- --------- Total partners' equity 286,195 258,428
- --------- --------- $ 286,195 258,508
========= =========
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, 1999, 1998 and 1997
1999 1998 1997 ---- ---- ---- Revenues
Oil and gas sales $ 249,636 200,761 334,355 Interest income from operations 329 609 1,436 ------- - ------- ------- 249,965 201,370 335,791 ------- - ------- -------
Expenses
Production 102,784 114,689 139,240 General and administrative 17,414 24,288 18,358 Depreciation, depletion and amortization 17,000 80,000 84,756 Provision for impairment of oil and gas properties - 314,240 - ------- - ------- ------- 137,198 533,217 242,354 ------- - ------- ------- Net income (loss) $ 112,767 (331,847) 93,437 ======= ======= ======= Net income (loss) allocated to:
Managing General Partner $ 14,274 6,863 19,601 ======= ======= ======= Investor partners $ 98,493 (338,710) 73,836 ======= ======= ======= Per investor partner unit $ 70.00 (240.73) 52.48 ======= ======= =======
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, 1999, 1998 and 1997
Managing General Investor Partner Partners Total -------- -------- -----
Balance at December 31, 1996 $ 31,033 763,505 794,538
Net income 19,601 73,836 93,437
Distributions (22,605) (182,895)(205,500) ------ - --------- -------- 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 ====== ========= ==========
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, 1999, 1998 and 1997
1999 1998 1997 ---- ---- ----
Cash flows from operating activities:
Cash received from oil and gas sales $ 223,480 223,677 355,046 Cash paid to Managing General Partner for administrative fees and general and administrative overhead (123,478) (133,373)(161,103) Interest received 329 609 1,436 ------- - ------- ------- Net cash provided by operating activities 100,331 90,913 195,379 ------- - ------- ------- Cash flows from investing activities:
Addition to oil and gas properties (20) - - Sale of oil and gas properties - 930 180 ------- - ------- ------- Net cash provided by (used in) investing activities(20) 930 180 ------- - ------- ------- Cash flows used in financing activities:
Distributions to partners (85,080) (92,218)(205,402) ------- - ------- ------- Net increase (decrease) in cash and cash equivalents 15,231 (375) (9,843)
Beginning of period 7,512 7,887 17,730 ------- - ------- ------- End of period $ 22,743 7,512 7,887 ======= ======= =======
(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, 1999, 1998 and 1997
1999 1998 1997 ---- ---- ----
Reconciliation of net income (loss) to net cash provided by operating activities:
Net income (loss) $ 112,767 (331,847) 93,437
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 17,000 80,000 84,756 Provision for impairment of oil and gas properties - 314,240 - - (Increase) decrease in receivables (26,156) 22,916 20,691 (Decrease) increase in payables (3,280) 5,604 (3,505) ------- - ------- ------- Net cash provided by operating activities $ 100,331 90,913 195,379 ======= ======= =======
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, 1999 and 1997, 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, 1999, 1998 and 1997, 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, 1999 and 1998 was $190,321 and $172,613, 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, 1999, 1998 and 1997, there were 1,407 investor units outstanding held by 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. Liquidity - Managing General Partner The Managing General Partner has a highly leveraged capital structure with over $35.1 million principal and $17.5 million interest payments due in 2000 on its debt obligations. Due to the severely depressed commodity prices experienced during the last quarter of 1997, throughout 1998 and continuing through the second quarter of 1999 the Managing General Partner is experiencing difficulty in generating sufficient cash flow to meet its obligations and sustain its operations. The Managing General Partner is currently in the process of renegotiating the terms of its various obligations with its creditors and/or attempting to seek new lenders or equity investors. Additionally, the Managing General Partner would consider disposing of certain assets in order to meet its obligations.
There can be no assurance that the Managing General Partner's debt restructuring efforts will be successful or that the lenders will agree to a course of action consistent with the Managing General Partners requirements in restructuring the obligations. Even if such agreement is reached, it may require approval of additional lenders, which is not assured. Furthermore, there can be no assurance that the sales of assets can be successfully accomplished on terms acceptable to the Managing General Partner. Under current circumstances, the Managing General Partner's ability to continue as a going concern depends upon its ability to (1) successfully restructure its obligations or obtain additional financing as may be required, (2) maintain compliance with all debt covenants, (3) generate sufficient cash flow to meet its obligations on a timely basis, and (4) achieve satisfactory levels of future earnings. If the Managing General Partner is unsuccessful in its efforts, it may be unable to meet its obligations making it necessary to undertake such other actions as may be appropriate to preserve asset values.
4. Commitments and Contingent Liabilities The Managing General Partner has the right, but not the obligation, to purchase limited partnership units should an investor desire to sell. The value of the unit is determined by adding the sum of (1) current assets less liabilities and (2) the present value of the future net revenues attributable to proved reserves and by discounting the future net revenues at a rate not in excess of the prime rate charged by 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
4. 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, 1999, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry.
However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership's properties.
5. Related Party Transactions A significant portion of the oil and gas properties in which the Partnership has an interest are operated by and purchased from the Managing General Partner. As is usual in the industry and as provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts to Southwest Royalties, Inc. as operator approximating $22,400, $20,900 and $19,000 for the years ended December 31, 1999, 1998 and 1997, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.
Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $2,900, $100 and $1,400 for the years ended December 31, 1999, 1998 and 1997, respectively, and the Managing General Partner believes that these costs are comparable to similar charges paid by the Partnership to unrelated third parties.
Southwest Royalties, Inc., the Managing General Partner, was paid an administrative fee of $12,000 during 1999, 1998 and 1997 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
5. 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, 1999, 1998 and 1997.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $37,250 and $7,814 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 1999 and 1998, respectively.
6. 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 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%. Three purchasers accounted for 94% of the Partnership's total oil and gas production during 1997: Scurlock Permian Corporation for 60%, Aquila Southwest Pipeline Corporation for 19% and Navajo Refining Company, Inc. for 15%. 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.
7. Estimated Oil and Gas Reserves (unaudited)
The Partnership's interest in proved oil and gas reserves is as follows:
Oil (bbls) Gas (mcf) ---------- --------- Proved developed and undeveloped reserves -
January 1, 1997 164,000 336,000
Production (13,000) (30,000) Revisions of estimates in place (33,000) (18,000) ------- ------- December 31, 1997 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 ======= =======
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued
Oil (bbls) Gas (mcf) ---------- --------- Proved developed reserves -
December 31, 1997 117,000 288,000 ======= ======= December 31, 1998 76,000 168,000 ======= ======= December 31, 1999 109,000 309,000 ======= =======
All of the Partnership's reserves are located within the continental United States.
*Donald R. Creamer, P.E., an Independent Registered Petroleum Engineer prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2000. The reserve estimates were made in accordance with guidelines established by the Securities and Exchange Commission pursuant to Rule 4-10(a) of Regulation S-X. Such guidelines require oil and gas reserve reports be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.
The New York Mercantile Exchange price at December 31, 1999 of $25.60 was used as the beginning basis for the oil price. Oil price adjustments from $25.60 per barrel were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results are an average price received at the lease of $24.16 per barrel in the preparation of the reserve report as of January 1, 2000.
In the determination of the gas price, the New York Mercantile Exchange price at December 31, 1999 of $2.33 was used as the beginning basis. Gas price adjustments from $2.33 per Mcf were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results are an average price received at the lease of $2.25 per Mcf in the preparation of the reserve report as of January 1, 2000.
Southwest Developmental Drilling Fund 92-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Estimated Oil and Gas Reserves (unaudited) - continued The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. 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 undeveloped. 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
7. Estimated Oil & Gas Reserves (unaudited) - continued The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1999, 1998 and 1997 is presented below:
1999 1998 1997 ---- ---- ----
Future cash inflows $ 3,328,000 1,160,000 2,801,000 Production and development costs 1,838,000 819,000 1,637,000 --------- --------- --------- Future net cash flows 1,490,000 341,000 1,164,000 10% annual discount for estimated timing of cash flows 603,000 98,000 430,000 --------- --------- --------- Standardized measure of discounted future net cash flows $ 887,000 243,000 734,000 ========= ========= =========
The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 1999, 1998 and 1997 are as follows:
1999 1998 1997 ---- ---- ----
Sales of oil and gas produced, net of production costs $ (147,000) (86,000) (195,000) Changes in prices and production costs 374,000 (410,000) (754,000) Changes of production rates (timing) and others (3,000) 38,000 41,000 Revisions of previous quantities estimates 396,000 (106,000) (161,000) Accretion of discount 24,000 73,000 164,000 Discounted future net cash flows - Beginning of year 243,000 734,000 1,639,000 --------- -------- -------- End of year $ 887,000 243,000 734,000 ========= ======== ========
Future net cash flows were computed using year-end prices and costs that related to existing proved oil and gas reserves in which the Partnership has mineral interests.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Part III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as Managing General Partner. The names, ages, offices, positions and length of service of the directors and executive officers of Southwest Royalties, Inc. are set forth below. Each director and executive officer serves for a term of one year. The present directors of the Managing General Partner have served in their capacity since the Company's formation in 1983.
Name Age Position - -------------------- --- ----------------------------------- - ------- H. H. Wommack, III 44 Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
H. Allen Corey 43 Secretary and Director
Bill E. Coggin 45 Vice President and Chief Financial Officer
J. Steven Person 41 Vice President, Marketing
Paul L. Morris 58 Director
H. H. Wommack, III, is Chairman of the Board, President, Chief Executive Officer, Treasurer, principal stockholder and a director of the Managing General Partner, and has served as its President since the Company's organization in August, 1983. Prior to the formation of the Company, Mr. Wommack was a self-employed independent oil producer engaged in the purchase and sale of royalty and working interests in oil and gas leases, and the drilling of exploratory and developmental oil and gas wells. Mr. Wommack holds a J.D. degree from the University of Texas from which he graduated in 1980, and a B.A. from the University of North Carolina in 1977.
H. Allen Corey, a founder of the Managing General Partner, has served as the Managing General Partner's secretary and a director since its inception. Mr. Corey is President of Trolley Barn Brewery, Inc., a brew pub restaurant chain based in the Southeast. Prior to his involvement with Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in Chattanooga, Tennessee. He is currently of counsel to the law firm of Baker, Donelson, Bearman & Caldwell, with the offices in Chattanooga, Tennessee. Mr. Corey received a J.D. degree from the Vanderbilt University Law School and B.A. degree from the University of North Carolina at Chapel Hill.
Bill E. Coggin, Vice President and Chief Financial Officer, has been with the Managing General Partner since 1985. Mr. Coggin was Controller for Rod Ric Corporation of Midland, Texas, an oil and gas drilling company, during the latter part of 1984. He was Controller for C.F. Lawrence & Associates, Inc., an independent oil and gas operator also of Midland, Texas during the early part of 1984. Mr. Coggin taught public school for four years prior to his business experience. Mr. Coggin received a B.S. in Education and a B.B.A. in Accounting from Angelo State University.
J. Steven Person, Vice President, Marketing, assumed his responsibilities with the Managing General Partner as National Marketing Director in 1989. Prior to joining the Managing General Partner, Mr. Person served as Vice President of Marketing for CRI, Inc., and was associated with Capital Financial Group and Dean Witter (1983). He received a B.B.A. from Baylor University in 1982 and an M.D.A. from Houston Baptist University in 1987.
Paul L. Morris has served as a Director of Southwest Royalties Holdings, Inc. since August 1998 and Southwest Royalties, Inc. since September 1998. Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest independently owned oil and gas companies in the United States. Prior to his position with Wagner & Brown, Mr. Morris served as President of Banner Energy and in various managerial positions with Columbia Gas System, Inc.
Key Employees
Jon P. Tate, Vice President, Land and Assistant Secretary, age 42, assumed his responsibilities with the Managing General Partner in 1989. Prior to joining the Managing General Partner, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as Land Manager from 1981 through 1989. Mr. Tate is a member of the Permian Basin Landman's Association and received his B.B.S. degree from Hardin-Simmons University.
R. Douglas Keathley, Vice President, Operations, age 44, assumed his responsibilities with the Managing General Partner as a Production Engineer in October, 1992. Prior to joining the Managing General Partner, Mr. Keathley was employed for four (4) years by ARCO Oil & Gas Company as senior drilling engineer working in all phases of well production (1988- 1992), eight (8) years by Reading & Bates Petroleum Company as senior petroleum engineer responsible for drilling (1980-1988) and two (2) years by Tenneco Oil Company as drilling engineer responsible for all phases of drilling (1978-1980). Mr. Keathley received his B.S. in Petroleum Engineering in 1977 from the University of Oklahoma.
In certain instances, the Managing General Partner will engage professional petroleum consultants and other independent contractors, including engineers and geologists in connection with property acquisitions, geological and geophysical analysis, and reservoir engineering. The Managing General Partner believes that, in addition to its own "in-house" staff, the utilization of such consultants and independent contractors in specific instances and on an "as-needed" basis allows for greater flexibility and greater opportunity to perform its oil and gas activities more economically and effectively.
Item 11.
Item 11. Executive Compensation
The Partnership does not have any directors or executive officers. The executive officers of the Managing General Partner do not receive any cash compensation, bonuses, deferred compensation or compensation pursuant to any type of plan, from the Partnership. The Managing General Partner received $12,000 during 1999, 1998 and 1997 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 eleven percent interest as a general partner.
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 1999, 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 $22,400 for administrative overhead attributable to operating such properties during 1999.
Certain subsidiaries or affiliates of the Managing General Partner perform various oilfield services for properties in which the Partnership owns an interest. Such services aggregated approximately $2,900 for the period ended December 31, 1999.
In the opinion of management, the terms of the above transactions are similar to ones with unaffiliated third parties.
Part IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Independent Auditors Report Balance Sheet Statement of 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, 1999.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Southwest 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 31, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Partnership and in the capacities and on the dates indicated.
By: /s/ H. H. Wommack, III ----------------------------------- H. H. Wommack, III, Chairman of the Board, President, Chief Executive Officer, Treasurer and Director
Date: March 31, 2000
By: /s/ H. Allen Corey ----------------------------- H. Allen Corey, Secretary and Director
Date: March 31, 2000