Item 1. Business
General Southwest Oil & Gas Income Fund VIII-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on November 30, 1987. The offering of limited partnership interests began March 31, 1988, minimum capital requirements were met July 6, 1988 and the offering concluded March 31, 1989. The Partnership has no subsidiaries.
The Partnership has expended its capital and acquired interests in producing oil and gas properties. After such acquisitions, the Partnership has produced and marketed the crude oil and natural gas produced from such properties. In most cases, the Partnership purchased working interests in oil and gas properties, with an occasional purchase of a royalty or overriding royalty interest. The Partnership purchased either all or part of the rights and obligations under various oil and gas leases.
The principal executive offices of the Partnership are located at 407 N. Big Spring, Suite 300, Midland, Texas, 79701. The Managing General Partner of the Partnership, Southwest Royalties, Inc. (the "Managing General Partner") and its staff of 81 individuals, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of oil and gas properties and the marketing of production from such properties. H. H. Wommack, III, Chairman, Director, President and Chief Executive Officer of the Managing General Partner, was also a general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. The Partnership has no employees.
Introductory Note - Statement of Financial Accounting Standard No. 143 The Partnership implemented SFAS No. 143 effective January 1, 2003 (See Note 3 to the Partnership's financial statements).
Introductory Note - Depletion Method During 2002, the Partnership changed its method of providing for depletion from the units-of-revenue method to the units-of-production method as described in Note 4 to the Partnership's financial statements. This change in depletion method was applied as a cumulative effect of a change in accounting principle effective as of January 1, 2002.
Principal Products, Marketing and Distribution The Partnership has acquired and holds working interests in oil and gas properties located in New Mexico and Texas. All activities of the Partnership are confined to the continental United States. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business.
The revenues generated from the Partnership's oil and gas activities are dependent upon the current market for oil and gas. 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.
Following is a table of the ratios of revenues received from oil and gas production for the last three years:
Oil Gas ----- ----- 2003 84% 16% 2002 86% 14% 2001 80% 20%
As the table indicates, the majority of the Partnership's revenue is from its oil production; therefore, Partnership revenues will be highly dependent upon the future prices and demands for oil.
Seasonality of Business Although the demand for natural gas can be effected by seasonality, with higher demand in the colder winter months and in very hot summer months, the Partnership has not experienced material price and volume changes due to seasonality and has been able to sell all of its natural gas, either through contracts in place or on the spot market at the then prevailing spot market price.
Customer Dependence No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 78% of the Partnership's total oil and gas production during 2003: Plains Marketing LP for 61% and Exxon Company for 17%. Contracts for 2003 with these major purchasers are month-to-month contracts. Prices received from these major purchasers ranged from a low of $28.83 per Bbl to a high of $29.27 per Bbl. Two purchasers accounted for 82% of the Partnership's total oil and gas production during 2002: Plains Marketing LP for 64% and Exxon Company for 18%. Contracts for 2002 with these major purchasers cover time periods for month-to-month contracts. Prices received from these major purchasers ranged from a low of $22.75 per Bbl to a high of $22.76 per Bbl. Three purchasers accounted for 78% of the Partnership's total oil and gas production during 2001: Plains Marketing LP for 58%, Mobil Corporation for 10% and Duke Energy Field Services for 10%. Contracts for 2001 with these major purchasers cover time periods ranging from month-to-month contracts up to year-to-year contract periods. Prices received from these major purchasers ranged from a low of $25.96 per Bbl to a high of $26.79 per Bbl and $6.04 per mcf. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's sales of oil and gas production.
Competition Because the Partnership has utilized all of its funds available for the acquisition of interests in producing oil and gas properties, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties.
Factors that may adversely affect the Partnership include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.
Regulation
Oil and Gas Production - The production and sale of oil and gas is subject to federal and state governmental regulation in several respects, such as existing price controls on natural gas and possible price controls on crude oil, regulation of oil and gas production by state and local governmental agencies, pollution and environmental controls and various other direct and indirect regulation. Many jurisdictions have periodically imposed limitations on oil and gas production by restricting the rate of flow for oil and gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of wells. The federal government has the power to permit increases in the amount of oil imported from other countries and to impose pollution control measures. Various aspects of the Partnership's oil and gas activities 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. The regulatory burden on the oil and gas industry increases the Partnership's cost of doing business, and, consequently, affects its profitability.
Regulation of Sales and Transportation of Natural Gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. While the United States Court of Appeals upheld most of Order No. 636, certain related FERC orders, including the individual pipeline restructuring proceedings, are still subject to judicial review and may be reversed or remanded in whole or in part. While the outcome of these proceedings cannot be predicted with certainty, we do not believe that we will be affected materially differently than its competitors.
The FERC has also announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of- service rate making methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. In February 1997, the FERC announced a broad inquiry into issues facing the natural gas industry to assist the FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. Similarly, the Texas Railroad Commission has been reviewing changes to its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes being considered by these federal and state regulators would affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters, however, we do not believe that it will be affected by any action taken materially differently than other natural gas producers with which it competes.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.
Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and gas liquids by us are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market.
Environmental and Health Controls. Extensive federal, state and local regulatory and common laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment affect our oil and natural gas operations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position. Additionally, given the intense litigation environment in the United States, a threat exists of lawsuits alleging personal injury and property damage from environmental contamination alleged to be created by us or related entities. Potential liability in such lawsuits can include not only compensatory, but substantial punitive damages as well. We are not aware of any such suits currently pending or threatened.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault on certain classes of persons that are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA such persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. Potential liability also exists under CERCLA for natural resource damage. A Natural Resource Damage Action (NRDA) could result in liability being assessed for restoration to natural resources.
The Federal Oil Pollution Act of 1990 ("OPA") regulates the release of oil into water or other areas designated by the statute. A release could result in our being held responsible for the cost of remediating the release, OPA specified damages and natural resource damages. The extent of such liability could be extensive. A release of oil in harmful quantities or other materials into water or other specified areas could also result in our being held responsible under the Clean Water Act ("CWA") for the costs of remediation, and any civil and criminal fines and penalties.
The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation, transportation, storage, treatment and disposal of solid and hazardous wastes and can require cleanup of abandoned hazardous waste disposal sites as well as waste management areas operating facilities. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as "hazardous waste." Disposal of such non-hazardous oil and natural gas exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of "hazardous wastes" thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted it could have a significant impact on the operating costs of Southwest and Sierra, as well as the oil and natural gas industry and well servicing industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted. In addition, if our operations were to trigger regulation under RCRA, we could be required to satisfy certain financial criteria to ensure financial ability to comply with RCRA regulations. Proof of financial responsibility could be required in the form of dedicated trust funds, irrevocable letters of credit, posting of bonds, etc.
The Federal Clean Water Act ("CWA") contains provisions that may result in the imposition of certain water pollution control requirements with respect to water releases from our operations. We may be required to incur certain capital expenditures in the next several years for water pollution control equipment in connection with obtaining and maintaining National Pollutant Discharge Elimination Systems ("NPDES") permits. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities or well surfacing activities.
Our operations are also subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities or well servicing activities.
We maintain insurance against "sudden and accidental" occurrences, which may cover some, but not all, of the environmental risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such costs or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.
Limited partners should be aware that the assessment of liability associated with environmental liabilities is not always correlated to the value of a particular project. Accordingly, liability associated with the environment under local, state, or federal regulations, particularly clean ups under CERCLA, can exceed the value of our investment in the associated site.
Regulation of Oil and Natural Gas Exploration and Production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the utilization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and natural gas can be produced from our properties.
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, 2003, there were 81 individuals directly employed by the Managing General Partner in various capacities.
Item 2.
Item 2. Properties
In determining whether an interest in a particular producing property was to be acquired, the Managing General Partner considered such criteria as estimated oil and gas reserves, estimated cash flow from the sale of production, present and future prices of oil and gas, the extent of undeveloped and unproved reserves, the potential for secondary, tertiary and other enhanced recovery projects and the availability of markets.
As of December 31, 2003, the Partnership possessed an interest in oil and gas properties located in Glasscock, Midland, Stonewall, Terry, Ward, Winkler and Yoakum Counties of Texas. These properties consist of various interests in approximately 85 wells and units.
Due to the Partnership's objective of maintaining current operations without engaging in the drilling of any developmental or exploratory wells, or additional acquisitions of producing properties, there have not been any significant changes in properties during 2003, 2002 and 2001.
During 2003, five leases were sold for approximately $110,200. There were no leases sold during 2002. During 2001, three leases were sold for approximately $200.
Significant Properties The following table reflects the significant properties in which the Partnership has an interest:
Date Purchased No. of Proved Reserves* Name and Location and Interest Wells Oil Gas (bbls) (mcf) - ------------------ ------------ ------ -------- -------- - -------- ----- ----- North American 3/89 at 50% 3 255,000 - Royalties Yoakum County, working 3 255,000( - Texas interest 1)
Ramsey-Sell 3/89 at 11% 4 108,000 33,000 Acquisition to 52% Winkler County, working 4 108,000( 33,000(1 Texas interest 1) )
(1)Amounts represent proved developed reserves from currently producing zones.
*Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2004. 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.
Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2004 are an average price of $31.21 per barrel.
Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2004 are an average price of $5.70 per Mcf.
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 2003.
The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves, which are classified as proved developed and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm- out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out.
The Partnership or the owners of properties in which the Partnership owns an interest can engage in workover projects or supplementary recovery projects, for example, to extract behind the pipe reserves. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 3.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is a party.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of security holders during the fourth quarter of 2003 through the solicitation of proxies or otherwise.
Part II
Item 5.
Item 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information Limited partnership interests, or units, in the Partnership were initially offered and sold for a price of $500. Limited partner units are not traded on any exchange and there is no public or organized trading market for them. The Managing General Partner has become aware of certain limited and sporadic transfers of units between limited partners and third parties, but has no verifiable information regarding the prices at which such units have been transferred. Further, a transferee may not become a substitute limited partner without the consent of the Managing General Partner.
After completion of the Partnership's first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner's interest in the Partnership in accordance with the obligations set forth in the partnership agreement. The pricing mechanism used to calculate the repurchase is based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner's obligation to purchase limited partner units under the partnership agreement is limited to an annual expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.
Issuer Purchases of Equity Securities Maximum Total Number (or Number of Units Approximat e Purchased Value) of as Units Part of that May Publicly Yet Be Total Announced Purchased Number of Units Average Plans or Under the Price Plans Period(1) Purchased Paid Per Programs or Unit Programs October 1- 31, 2003 - - - N/A November 1- 30, 2003 - - - N/A December 1- 31, 2003 - - - N/A TOTALS - -
(1) In April and July 2003, the Managing General Partner purchased a total of 172 limited partner units from limited partners at an average base price of $160.36 per unit. As of December 31, 2002, no limited partner units were purchased by the Managing General Partner. In 2001, 957 limited partner units were tendered to and purchased by the Managing General Partner at an average base price of $256.07 per unit. These repurchases were part of the obligations under the partnership agreement.
Number of Limited Partner Interest Holders As of December 31, 2003, there were 515 holders of limited partner units in the Partnership.
Distributions Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and Agreement of Limited Partnership "Net Cash Flow" is distributed to the partners on a quarterly basis. "Net Cash Flow" is defined as "the cash generated by the Partnership's investments in producing oil and gas properties, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of the Partnership, as determined in the sole discretion of the Managing General Partner."
During 2003, distributions were made totaling $653,703, with $591,703 distributed to the limited partners and $62,000 to the general partner. For the year ended December 31, 2003, distributions of $43.52 per limited partner unit were made, based upon 13,596 limited partner units outstanding. During 2002, distributions were made totaling $167,000, with $150,300 distributed to the limited partners and $16,700 to the general partner. For the year ended December 31, 2002, distributions of $11.05 per limited partner unit were made, based upon 13,596 limited partner units outstanding. During 2001, distributions were made totaling $620,063, with $558,057 distributed to the limited partners and $62,006 to the general partners. For the year ended December 31, 2001, distributions of $41.05 per limited partner unit were made, based upon 13,596 limited partner units outstanding.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 should be read in conjunction with the financial statements included in Item 8:
2003 2002 2001 2000 1999 ----- ----- ----- ----- ----- Revenues $ 1,420,35 1,040,77 1,207,82 1,450,80 908,182 6 6 1 3
Net income from continuing operations 541,818 255,179 378,433 666,839 232,764
Results from 19,951 23,860 43,235 46,656 13,933 discontinued operations
Net income before cumulative effects of accounting changes 561,769 279,039 421,668 713,495 246,697
Net income 402,850 274,039 421,668 713,495 246,697
Partners' share of net income :
General partners 41,985 30,704 46,667 73,550 26,969
Limited partners 360,865 243,335 375,001 639,946 219,728
Limited partners' net income per unit before discontinued operations and cumulative effects of accounting changes 35.74 16.71 24.75 43.99 15.25
Discontinued operations per limited partner unit 1.32 1.56 2.84 3.08 .91
Limited partners' net income per unit 26.54 17.90 27.58 47.07 16.16
Limited partners' cash distributions per unit 43.52 11.05 41.05 40.74 10.80
Total assets $ 524,180 521,285 414,368 612,621 514,637
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General The Partnership was formed to acquire interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute any net proceeds from operations to the general and limited partners. Net revenues from producing oil and gas properties are not reinvested in other revenue producing assets except to the extent that producing facilities and wells are reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves. The economic life of the Partnership thus depends on the period over which the Partnership's oil and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, lease operating expenses, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements and on the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately. Net income available for distribution to the limited partners is therefore expected to decline in later years based on these factors.
Based on current conditions, management does not anticipate performing development drilling projects and workovers during the year 2004 to enhance production. The partnership will most likely continue to experience the historical production decline, which has approximated 8% per year. Accordingly, if commodity prices remain unchanged, the Partnership expects future earnings to decline due to anticipated production declines.
Critical Accounting Policies Full cost ceiling calculations The Partnership follows the full cost method of accounting for its oil and gas properties. The full cost method subjects companies to quarterly calculations of a "ceiling", or limitation on the amount of properties that can be capitalized on the balance sheet. If the Partnership's capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense.
The Partnership's discounted present value of its proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. The Partnership's reserve estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than the Partnership's long-term price forecast that is a barometer for true fair value.
In 2002, the Partnership changed methods of accounting for depletion of capitalized costs from the units-of-revenue method to the units-of- production method. The newly adopted accounting principle is preferable in the circumstances because the units-of-production method results in a better matching of the costs of oil and gas production against the related revenue received in periods of volatile prices for production as have been experienced in recent periods. Additionally, the units-of-production method is the predominant method used by full cost companies in the oil and gas industry, accordingly, the change improves the comparability of the Partnership's financial statements with its peer group.
Results of Operations
A. General Comparison of the Years Ended December 31, 2003 and 2002
The following table provides certain information regarding performance factors for the years ended December 31, 2003 and 2002:
Year Ended Percenta ge December 31, Increase 2003 2002 (Decreas e) ------- ------- -------- -------
Average price per $ 29.57 19% barrel of oil 24.78 Average price per mcf $ 5.03 55% of gas 3.24 Oil production in 39,500 35,900 10% barrels Gas production in mcf 46,000 46,300 (1%) Oil and gas revenue $ 1,398,17 1,039,52 35% 6 5 Production expense $ 728,887 654,743 11% Partnership $ 653,703 167,000 291% distributions Limited partner $ 591,703 150,300 294% distributions Per unit distribution $ 43.52 294% to limited partners 11.05
Number of limited 13,596 13,596 partner units
Revenues
The Partnership's oil and gas revenues increased to $1,398,176 from $1,039,525 for the years ended December 31, 2003 and 2002, respectively, an increase of 35%. The principal factors affecting the comparison of the years ended December 31, 2003 and 2002 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2003 as compared to the year ended December 31, 2002 by 19%, or $4.79 per barrel, resulting in an increase of approximately $189,200 in revenues. Oil sales represented 83% of total oil and gas sales during the year ended December 31, 2003 as compared to 86% during the year ended December 31, 2002.
The average price for an mcf of gas received by the Partnership increased during the same period by 55%, or $1.79 per mcf, resulting in an increase of approximately $82,300 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $271,500. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production increased approximately 3,600 barrels or 10% during the year ended December 31, 2003 as compared to the year ended December 31, 2002, resulting in an increase of approximately $89,200 in revenues.
Gas production decreased approximately 300 mcf or 1% during the same period, resulting in a decrease of approximately $1,000 in revenues.
The net total increase in revenues due to the change in production is approximately $88,200.
3. Other income in the amount of $20,821 for 2003 primarily represents litigation settlement income from a class action lawsuit, where two purchasers were underpaying for certain types of oil in certain locations for the time periods of 1988-1998.
Costs and Expenses
Total costs and expenses increased to $878,538 from $785,597 for the years ended December 31, 2003 and 2002, respectively, an increase of 12%. The increase is the result of accretion expense, higher lease operating costs and general and administrative expense, partially offset by a decrease in depletion expense,.
1. Lease operating costs and production taxes were 11% higher, or approximately $74,100 more during the year ended December 31, 2003 as compared to the year ended December 31, 2002. The increase is due to well workover costs of a casing leak on one well, costs replacing the tubing in a salt water disposal well and higher production taxes due to an increase in oil and gas commodity prices from prior year.
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 7% or approximately $7,200 during the year ended December 31, 2003 as compared to the year ended December 31, 2002.
3. Depletion expense decreased to $16,500 for the year ended December 31, 2003 from $26,000 for the same period in 2002. This represents a decrease of 34%. The contributing factor to the decrease in depletion expense is in relation to the BOE depletion rate for the year ended December 30, 2003, which was $0.35 applied to 47,100 BOE as compared to $0.60 applied to 43,600 BOE for the same period in 2002.
Cumulative effect of change in accounting principle - SFAS No. 143 On January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required for all companies with fiscal years beginning after June 15, 2002. The new standard requires the Partnership to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset and depreciate the additional cost over the estimated useful life of the asset. On January 1, 2003, the Partnership recorded additional costs, net of accumulated depreciation, of approximately $191,308, a long term liability of approximately $350,227 and a loss of approximately $158,919 for the cumulative effect on depreciation of the additional costs and accretion expense on the liability related to expected abandonment costs of its oil and natural gas producing properties. At December 31, 2003, the asset retirement obligation was $253,843. The decrease in the balance from January 1, 2003 is due to the sale of oil and gas properties, which decreased the asset retirement obligation by $117,656 offset slightly by accretion expense of $21,104 plus the addition of a new well due to a farm- out arrangement for $168. The pro forma amounts of the asset retirement obligation as of December 31, 2002, 2001 and 2000, were approximately $350,227, $324,450 and $300,570, respectively. The pro forma amounts of the asset retirement obligation were measured using information, assumptions and interest rates as of the adoption date of January 1, 2003.
Results of Operations
B. General Comparison of the Years Ended December 31, 2002 and 2001
The following table provides certain information regarding performance factors for the years ended December 31, 2002 and 2001:
Year Ended Percenta ge December 31, Increase 2002 2001 (Decreas e) ------- ------- -------- -------
Average price per $ 24.78 3% barrel of oil 23.99 Average price per mcf $ 3.24 (24%) of gas 4.29 Oil production in 35,900 39,600 (9%) barrels Gas production in mcf 46,300 59,200 (22%) Oil and gas revenue $ 1,039,52 1,203,74 (14%) 5 5 Production expense $ 654,743 681,751 (4%) Partnership $ 167,000 620,063 (73%) distributions Limited partner $ 150,300 558,057 (73%) distributions Per unit distribution $ 11.05 (73%) to limited partners 41.05 Number of limited 13,596 13,596 partner units
Revenues
The Partnership's oil and gas revenues decreased to $1,039,525 from $1,203,745 for the years ended December 31, 2002 and 2001, respectively, a decrease of 14%. The principal factors affecting the comparison of the years ended December 31, 2002 and 2001 are as follows:
1. The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2002 as compared to the year ended December 31, 2001 by 3%, or $.79 per barrel, resulting in an increase of approximately $28,400 in revenues. Oil sales represented 86% of total oil and gas sales during the year ended December 31, 2002 as compared to 79% during the year ended December 31, 2001.
The average price for an mcf of gas received by the Partnership decreased during the same period by 24%, or $1.05 per mcf, resulting in a decrease of approximately $48,600 in revenues.
The net total decrease in revenues due to the change in prices received from oil and gas production is approximately $20,200. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
2. Oil production decreased approximately 3,700 barrels or 9% during the year ended December 31, 2002 as compared to the year ended December 31, 2001, resulting in a decrease of approximately $88,800 in revenues.
Gas production decreased approximately 12,900 mcf or 22% during the same period, resulting in a decrease of approximately $55,300 in revenues.
The total decrease in revenues due to the change in production is approximately $144,100. The decrease in gas production is primarily due to a lease that had a well shut in during the third quarter of 2001 and another lease that had a well with a casing leak resulting in downtime which is currently under assessment for repairing or plugging.
Costs and Expenses
Total costs and expenses decreased to $785,597 from $829,388 for the years ended December 31, 2002 and 2001, respectively, a decrease of 5%. The decrease is the result of lower depletion expense, lease operating costs and general and administrative expense.
2. Lease operating costs and production taxes were 4% lower, or approximately $27,000 less during the year ended December 31, 2002 as compared to the year ended December 31, 2001.
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 1% or approximately $800 during the year ended December 31, 2002 as compared to the year ended December 31, 2001.
3. Depletion expense decreased to $26,000 for the year ended December 31, 2002 from $42,000 for the same period in 2001. This represents a decrease of 38%. In the fourth quarter of 2002, the Partnership changed methods of accounting for depletion of capitalized costs from the units-of-revenue method to the units-of-production method. The newly adopted accounting principle is preferable in the circumstances because the units-of-production method results in a better matching of the costs of oil and gas production against the related revenue received in periods of volatile prices for production as have been experienced in recent periods. Additionally, the units-of-production method is the predominant method used by full cost companies in the oil and gas industry, accordingly, the change improves the comparability of the Partnership's financial statements with its peer group. The effect of this change in method was to increase 2002 depletion expense by $1,000 and decrease 2002 net income by $6,000. See Note 4 of the notes to the Partnership's financial statements.
The major factor in 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, 2003 as compared to 2002, which provided more economically recoverable proved reserves at January 1, 2003 which caused the depletion rate per equivalent unit produced to decline. Also, as discussed above, the total equivalent units produced in 2002 declined from 2001.
C. Revenue and Distribution Comparison
Partnership net income for the years ended December 31, 2003, 2002 and 2001 was $402,850, $274,039 and $421,668. Partnership distributions for the years ended December 31, 2003, 2002 and 2001 were $653,703, $167,000 and $620,063, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2003, 2002 and 2001.
The sources for the 2003 distributions of $653,703 were oil and gas operations of approximately $607,300 and the change in oil and gas properties of approximately $100,900, resulting in excess cash for contingencies or subsequent distributions. The sources for the 2002 distributions of $167,000 were oil and gas operations of approximately $233,500 and the change in oil and gas properties of approximately $(47,100), resulting in excess cash for contingencies or subsequent distributions. The sources for the 2001 distributions of $620,063 were oil and gas operations of approximately $582,800 and the change in oil and gas properties of approximately $(37,400), with the balance from available cash on hand at the beginning of the period.
Total distributions during the year ended December 31, 2003 were $653,703 of which $591,703 was distributed to the limited partners and $62,000 to the general partner. The per unit distribution to limited partners during the same period was $43.52. Total distributions during the year ended December 31, 2002 were $167,000 of which $150,300 was distributed to the limited partners and $16,700 to the general partner. The per unit distribution to limited partners during the same period was $11.05. Total distributions during the year ended December 31, 2001 were $620,063 of which $558,057 was distributed to the limited partners and $62,006 to the general partners. The per unit distribution to limited partners during the same period was $41.05.
Cumulative cash distributions of $9,239,627 have been made to the general and limited partners as of December 31, 2003. As of December 31, 2003, $8,363,906 or $615.17 per limited partner unit has been distributed to the limited partners, representing a 100% return of capital and a 23% return on capital contributed.
Liquidity and Capital Resources
The primary source of cash is from operations, the receipt of income from interests in oil and gas properties. The Partnership knows of no material change, nor does it anticipate any such change.
Cash flows provided by operating activities were approximately $607,300 in 2003 compared to $233,500 in 2002 and approximately $582,800 in 2001.
Cash flows provided by (used in) investing activities were approximately $100,900 in 2003 compared to $(47,100) in 2002 and approximately $(37,400) in 2001. The principal source of the 2003 cash flow from investing activities was the proceeds from the sale of oil and gas properties.
Cash flows used in financing activities were approximately $653,800 in 2003 compared to $167,100 in 2002 and approximately $619,900 in 2001. The only use in financing activities was the distributions to partners.
As of December 31, 2003, the Partnership had approximately $236,900 in working capital. The Managing General Partner knows of no unusual contractual commitments. Although the Partnership held many long-lived properties at inception, because of the restrictions on property development imposed by the partnership agreement, the Partnership cannot develop its non-producing properties, if any. Without continued development, the producing reserves continue to deplete. Accordingly, as the Partnership's properties have matured and depleted, the net cash flows from operations for the Partnership has steadily declined, except in periods of substantially increased commodity pricing. Maintenance of properties and administrative expenses for the Partnership are increasing relative to production. As the properties continue to deplete, maintenance of properties and administrative costs as a percentage of production are expected to continue to increase.
Liquidity - Managing General Partner
As of December 31, 2003, the Managing General Partner is in violation of several covenants pertaining to their Amended and Restated Revolving Credit Agreement due June 1, 2006 and their Senior Second Lien Secured Credit Agreement due October 15, 2008. Due to the covenant violations, the Managing General Partner is in default under their Amended and Restated Revolving Credit Agreement and the Senior Second Lien Secured Credit Agreement, and all amounts due under these agreements have been classified as a current liability on the Managing General Partner's balance sheet at December 31, 2003. The significant working capital deficit and debt being in default at December 31, 2003, raise substantial doubt about the Managing General Partner's ability to continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the Managing General Partner announced its decision to explore a merger, sale of the stock or other transaction involving the Managing General Partner. The Board has formed a Special Committee of independent directors to oversee the sales process. The Special Committee has retained independent financial and legal advisors to work closely with the management of the Managing General Partner to implement the sales process. There can be no assurance that a sale of the Managing General Partner will be consummated or what terms, if consummated, the sale will be on.
Recent Accounting Pronouncements
The EITF is considering two issues related to the reporting of oil and gas mineral rights. Issue No. 03-O, "Whether Mineral Rights Are Tangible or Intangible Assets," is whether or not mineral rights are intangible assets pursuant to SFAS No. 141, "Business Combinations." Issue No. 03-S, "Application of SFAS No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies," is, if oil and gas drilling rights are intangible assets, whether those assets are subject to the classification and disclosure provisions of SFAS No. 142. The Partnership classifies the cost of oil and gas mineral rights as properties and equipment and believes that this is consistent with oil and gas accounting and industry practice. The disclosures required by SFAS Nos. 141 and 142 would be made in the notes to the financial statements. There would be no effect on the statement of income or cash flows as the intangible assets related to oil and gas mineral rights would continue to be amortized under the full cost method of accounting.
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 21
Balance Sheets 22
Statements of Operations 23
Statement of Changes in Partners' Equity 25
Statements of Cash Flows 26
Notes to Financial Statements 28
INDEPENDENT AUDITORS' REPORT
The Partners Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware Limited Partnership)
We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund VIII-A, L.P. (the "Partnership") as of December 31, 2003 and 2002, 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, 2003. 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 Oil & Gas Income Fund VIII-A, L.P. as of December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 4 to the financial statements, the Partnership changed its method of computing depletion in 2002. Also, as discussed in Note 3 to the financial statements, the Partnership changed its method of accounting for asset retirement obligations as of January 1, 2003.
KPMG LLP
Midland, Texas March 19, 2004, except as to Note 10, which is as of May 3, 2004
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 2003 and 2002
2003 2002 ---- ---- Assets - ---------
Current assets: Cash and cash equivalents $ 111,117 56,709 Receivable from Managing 125,868 133,263 General Partner -------- -------- ---- ---- Total current assets 236,985 189,972 -------- -------- ---- ----
Oil and gas properties - using the full- cost method of accounting 5,342,41 5,438,77 3 9 Less accumulated depreciation, depletion and 5,055,21 5,107,46 amortization 8 6 -------- -------- ---- ---- Net oil and gas 287,195 331,313 properties -------- -------- ---- ---- $ 524,180 521,285 ======= =======
Liabilities and Partners' Equity - ---------------------------- - ------------
Current liability - $ 104 199 distribution payable -------- -------- ---- ----
Asset retirement obligation 253,843 - -------- -------- ---- ---- Partners' equity - General partner (605) 19,410 Limited partners 270,838 501,676 -------- -------- ---- ---- Total partners' equity 270,233 521,086 -------- -------- ---- ---- $ 524,180 521,285 ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 2003, 2002 and 2001
2003 2002 2001 ------ ------ ------ Revenues - ------------- Oil and gas revenue $ 1,398,17 1,039,52 1,203,74 6 5 5 Interest 1,359 646 4,076 Other 20,821 605 - -------- -------- -------- ----- ---- ---- 1,420,35 1,040,77 1,207,82 6 6 1 -------- -------- -------- ---- ---- ---- Expenses - ------------- Production 728,887 654,743 681,751 General and administrative 112,047 104,854 105,637 Accretion of asset retirement 21,104 - - obligation Depreciation, depletion and 16,500 26,000 42,000 amortization -------- -------- -------- ---- ---- ---- 878,538 785,597 829,388 -------- -------- -------- ---- ---- ---- Net income from continued 541,818 255,179 378,433 operations
Results from discontinued operations- sale of oil and gas leases - 19,951 23,860 43,235 See Note 5 -------- -------- -------- ---- ---- ---- Net income before cumulative effects of accounting changes 561,769 279,039 421,668
Cumulative effect of change in accounting principle - SFAS No. 143 - (158,919 - - See Note 3 ) Cumulative effect of change in accounting principle - change in depletion method - (5,000) - - - See Note 4 -------- -------- -------- ---- ---- ---- Net income $ 402,850 274,039 421,668 ======= ======= ======= continue d
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 2003, 2002 and 2001 (continued)
2003 2002 2001 ------ ------ ------ Net income allocated to: Managing General Partner $ 41,985 30,704 42,000 ======= ======= ======= General Partner $ - - 4,667 ======= ======= ======= Limited partners $ 360,865 243,335 375,001 ======= ======= ======= Per limited partner unit before discontinued operations and cumulative $ 35.74 effects 16.71 24.75 Discontinued operations per 1.32 1.56 2.84 limited partner unit Cumulative effects per (10.52) (.37) - limited partner unit -------- -------- -------- ---- ---- ---- Per limited partner unit $ 26.54 17.90 27.58 ======= ======= =======
Pro forma amounts assuming changes are applied retroactively (See Notes 3 and 4 for details): Net income before cumulative $ - 253,262 401,789 effects ======= ======= ======= Per limited partner unit $ - (13,596.0 units) 16.56 26.29 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 2003, 2002 and 2001
General Limited Partner Partners Total -------- -------- -------- ----- ---- - Balance at $ 20,745 591,697 612,442 December 31, 2000
Net income 46,667 375,001 421,668
Distributions (62,006) (558,057 (620,063 ) ) -------- -------- -------- -- --- --- Balance at 5,406 408,641 414,047 December 31, 2001
Net income 30,704 243,335 274,039
Distributions (16,700) (150,300 (167,000 ) ) -------- -------- -------- -- --- --- Balance at 19,410 501,676 521,086 December 31, 2002
Net income 41,985 360,865 402,850
Distributions (62,000) (591,703 (653,703 ) ) -------- -------- -------- -- --- --- Balance at $ (605) 270,838 270,233 December 31, 2003 ====== ====== ======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2003, 2002 and 2001
2003 2002 2001 ---- ---- ---- Cash flows from operating activities: Cash received from oil and $ 1,396,74 968,567 1,340,78 gas sales 4 8 Cash paid to Managing General Partner for production expense, administrative fees and general and (831,608 (760,178 (805,290 administrative overhead ) ) ) Cash received from 19,951 23,860 43,235 discontinued operations Interest received 1,359 646 4,076 Miscellaneous settlement 20,821 605 - -------- -------- -------- -- -- -- Net cash provided by 607,267 233,500 582,809 operating activities -------- -------- -------- -- -- -- Cash flows from investing activities: Additions to oil and gas (9,230) (47,054) (37,600) properties Sale of oil and gas 110,169 - 160 properties -------- -------- -------- -- -- -- Net cash provided by (used 100,939 (47,054) (37,440) in) investing activities -------- -------- -------- -- -- -- Cash flows used in financing activities: Distributions to partners (653,798 (167,122 (619,921 ) ) ) -------- -------- -------- -- -- -- Net increase (decrease) in 54,408 19,324 (74,552) cash and cash equivalents
Beginning of year 56,709 37,385 111,937 -------- -------- -------- -- -- -- End of year $ 111,117 56,709 37,385 ====== ====== ====== (continu ed)
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2003, 2002 and 2001 (continued)
2003 2002 2001 ---- ---- ---- Reconciliation of net income to net cash provided by operating activities:
Net income $ 402,850 274,039 421,668
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and 16,500 26,000 42,000 amortization Accretion of asset retirement 21,104 - - obligation Cumulative effects of change 158,919 5,000 - in accounting principle (Increase) decrease in (1,432) (70,958) 137,043 receivables (Decrease) increase in 9,326 (581) (17,902) payables -------- -------- -------- -- -- -- Net cash provided by operating $ 607,267 233,500 582,809 activities ====== ====== ====== Noncash investing and financing activities: Increase in oil and gas properties - Adoption of SFAS No. 143 $ 191,308 - - ====== ====== ====== Increase in oil and gas properties - SFAS No. 143 additional well due to farm- $ 168 - - out arrangement ====== ====== ====== Decrease in oil and properties - SFAS No. 143 sale of property $ 117,656 - - ====== ====== ======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Oil & Gas Income Fund VIII-A, L.P. was organized under the laws of the state of Delaware on November 30, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc. serves as the Managing General Partner and H. H. Wommack, III, was the individual general partner. Effective December 31, 2001, Mr. Wommack sold his general partner interest to the Managing General Partner. Revenues, costs and expenses are allocated as follows:
Limited General Partners Partners -------- -------- -- -- Interest income on capital 100% - contributions Oil and gas sales 90% 10% All other revenues 90% 10% Organization and offering costs 100% - (1) Amortization of organization 100% - costs Syndication costs 100% - Property acquisition costs 100% - Gain/loss on property disposition 90% 10% Operating and administrative 90% 10% costs (2) Depreciation, depletion and amortization of oil and gas properties 100% - All other costs 90% 10%
(1)All organization costs in excess of 3% 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 3% 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.
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.
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. In applying the units-of-revenue method for the year ended December 31, 2001, we have not excluded royalty and net profit interest payments from gross revenues as all of our royalty and net profit interests have been purchased and capitalized to the depletion basis of our proved oil and gas properties. As of December 31, 2003, 2002 and 2001 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
Estimates and Uncertainties The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnerships depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserves estimates, which are inherently imprecise. Actual results could differ from those estimates.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Syndication Costs Syndication costs are accounted for as a reduction of partnership equity.
Environmental Costs The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs, which improve a property as compared with the condition of the property when originally constructed or acquired and costs, which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Revenue Recognition We recognize oil and gas sales when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or transport vehicle.
Gas Balancing The Partnership utilizes the sales method of accounting for gas- balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2003 and 2002, there were no significant amounts of imbalance in terms of units or value.
Income Taxes No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes, the Partnership's tax basis in its net oil and gas properties at December 31, 2003 and 2002 is $302,051 and $367,892, respectively, more 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.
Number of Limited Partner Units As of December 31, 2003, 2002 and 2001, there were 13,596 limited partner units outstanding held by 515, 518 and 518 partners.
Concentrations of Credit Risk The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors' ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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.
Recent Accounting Pronouncements The EITF is considering two issues related to the reporting of oil and gas mineral rights. Issue No. 03-O, "Whether Mineral Rights Are Tangible or Intangible Assets," is whether or not mineral rights are intangible assets pursuant to SFAS No. 141, "Business Combinations." Issue No. 03-S, "Application of SFAS No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Companies," is, if oil and gas drilling rights are intangible assets, whether those assets are subject to the classification and disclosure provisions of SFAS No. 142. The Partnership classifies the cost of oil and gas mineral rights as properties and equipment and believes that this is consistent with oil and gas accounting and industry practice. The disclosures required by SFAS Nos. 141 and 142 would be made in the notes to the financial statements. There would be no effect on the statement of income or cash flows as the intangible assets related to oil and gas mineral rights would continue to be amortized under the full cost method of accounting.
Depletion Policy In 2002, the Partnership changed methods of accounting for depletion of capitalized costs from the units-of-revenue method to the units-of- production method. (See Note 4)
3. Cumulative effect of change in accounting principle - SFAS No. 143 On January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). Adoption of SFAS No. 143 is required for all companies with fiscal years beginning after June 15, 2002. The new standard requires the Partnership to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a cost of the asset and depreciate the additional cost over the estimated useful life of the asset. On January 1, 2003, the Partnership recorded additional costs, net of accumulated depreciation, of approximately $191,308, a long term liability of approximately $350,227 and a loss of approximately $158,919 for the cumulative effect on depreciation of the additional costs and accretion expense on the liability related to expected abandonment costs of its oil and natural gas producing properties. At December 31, 2003, the asset retirement obligation was $253,843. The decrease in the balance from January 1, 2003 is due to the sale of oil and gas properties, which decreased the asset retirement obligation by $117,656 offset slightly by accretion expense of $21,104 plus the addition of a new well due to a farm-out arrangement for $168. The pro forma amounts of the asset retirement obligation as of December 31, 2002, 2001 and 2000, were approximately $350,227, $324,450 and $300,571, respectively. The pro forma amounts of the asset retirement obligation were measured using information, assumptions and interest rates as of the adoption date of January 1, 2003. The pro forma amounts for the years ended December 30, 2002 and 2001, which are presented below, reflect the effect of retroactive application of SFAS No. 143.
2002 2001 ------ ------ Pro forma amounts assuming change is applied retroactively : Net income (loss) before cumulative effect for change in depletion $ 253,262 397,788 method ======= ======= Per limited partner unit $ 16.56 26.00 (13,596.0 units) ======= ======= Net income (loss) $ 248,262 397,788 ======= ======= Per limited partner unit $ 16.19 26.00 (13,596.0 units) ======= =======
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
4. Cumulative effect of a change in accounting principle In 2002, the Partnership changed methods of accounting for depletion of capitalized costs from the units-of-revenue method to the units-of- production method. The newly adopted accounting principle is preferable in the circumstances because the units-of-production method results in a better matching of the costs of oil and gas production against the related revenue received in periods of volatile prices for production as have been experienced in recent periods. Additionally, the units-of-production method is the predominant method used by full cost companies in the oil and gas industry, accordingly, the change improves the comparability of the Partnership's financial statements with its peer group. The Partnership adopted the units-of-production method through the recording of a cumulative effect of a change in accounting principle in the amount of $5,000 effective as of January 1, 2002. The Partnership's depletion for the years ended 2003 and 2002 have been calculated using the units-of-production method, however, 2001 has not been restated. The pro forma amounts for 2001, which are presented below, reflect the effect of retroactive application of the units-of-production method. See Note 12 for the effects of the change in depletion method on the individual quarters of 2002.
------ Pro forma amounts assuming change is applied retroactively: Net income $ 425,668 ======= Per limited partner unit $ 27.88 (13,596.0 units) =======
5. Discontinued Operations - Sale of oil and gas leases During the three months ended June 30, 2003, the Partnership sold its interest in certain oil, gas and salt water disposal wells for $110,169 sales proceeds and retired $117,656 of asset retirement obligation associated with the properties. Since the Partnership is under the full cost pool method of accounting, the sales proceeds and asset retirement obligation liability were taken against the oil and gas properties asset account and therefore, no gain or loss was recorded and shown on the statement of operations as part of the discontinued operations. Pursuant to the requirements of SFAS No. 144, the historical operating results from these properties have been reported as discontinued operations in the accompanying statements of operations. The following table summarizes certain historical operating information related to the discontinued operations:
2003 2002 2001
Revenues $34,987 70,776 86,788 Net income 19,951 23,860 43,235
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
6. Liquidity - Managing General Partner As of December 31, 2003, the Managing General Partner is in violation of several covenants pertaining to their Amended and Restated Revolving Credit Agreement due June 1, 2006 and their Senior Second Lien Secured Credit Agreement due October 15, 2008. Due to the covenant violations, the Managing General Partner is in default under their Amended and Restated Revolving Credit Agreement and the Senior Second Lien Secured Credit Agreement, and all amounts due under these agreements have been classified as a current liability on the Managing General Partner's balance sheet at December 31, 2003. The significant working capital deficit and debt being in default at December 31, 2003, raise substantial doubt about the Managing General Partner's ability to continue as a going concern.
Subsequent to December 31, 2003, the Board of Directors of the Managing General Partner announced its decision to explore a merger, sale of the stock or other transaction involving the Managing General Partner. The Board has formed a Special Committee of independent directors to oversee the sales process. The Special Committee has retained independent financial and legal advisors to work closely with the management of the Managing General Partner to implement the sales process. There can be no assurance that a sale of the Managing General Partner will be consummated or what terms, if consummated, the sale will be on.
7. Commitments and Contingent Liabilities After completion of the Partnership's first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner's interest in the Partnership. The pricing mechanism used to calculate the repurchase is based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one- third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner's obligation to purchase limited partner units is limited to an annual expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.
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, 2003, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations, which would have a material adverse effect upon capital expenditures, earnings or the competitive position in the oil and gas industry. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not reliably determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of Partnership's properties.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
8. 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 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 $121,900, $135,100 and $139,100 for the years ended December 31, 2003, 2002 and 2001 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.
Southwest Royalties, Inc., the Managing General Partner, was paid $98,400 during 2003, 2002 and 2001 as an administrative fee for indirect general and administrative overhead expenses. The administrative fees are included in general and administrative expense on the statement of operations.
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $125,900 and $133,300 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2003 and 2002, respectively.
9. Major Customers No material portion of the Partnership's business is dependent on a single purchaser, or a very few purchasers, where the loss of one would have a material adverse impact on the Partnership. Two purchasers accounted for 78% of the Partnership's total oil and gas production during 2003: Plains Marketing LP for 61% and Exxon Company for 17%. Two purchasers accounted for 82% of the Partnership's total oil and gas production during 2002: Plains Marketing LP for 64% and Exxon Company for 18%. Three purchasers accounted for 78% of the Partnership's total oil and gas production during 2001: Plains Marketing LP for 58%, Mobil Corporation for 10% and Duke Energy Field Services for 10%. All purchasers of the Partnership's oil and gas production are unrelated third parties. In the event any of these purchasers were to discontinue purchasing the Partnership's production, the Managing General Partner believes that a substitute purchaser or purchasers could be located without undue delay. No other purchaser accounted for an amount equal to or greater than 10% of the Partnership's sales of oil and gas production.
10. Subsequent Event Subsequent to December 31, 2003, the Managing General Partner announced that its Board of Directors had decided to explore a merger or sale of the stock of the Company. The Board formed a Special Committee of independent directors to oversee the sale process. The Special Committee retained independent financial and legal advisors to work closely with management to implement the sale process.
On May 3, 2004, the Managing General Partner entered into a cash merger agreement to sell all of its stock to Clayton Williams Energy, Inc. The cash merger price is being negotiated, but is expected to be approximately $45 per share. The transaction, which is subject to approval by the Managing General Partner's shareholders, is expected to close no later than May 21, 2004.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
11. Estimated Oil and Gas Reserves (unaudited) The Partnership's interest in proved oil and gas reserves is as follows:
Oil Gas (bbls) (mcf) -------- -------- -- - Total Proved - January 1, 2001 535,000 912,000
Revisions of previous (151,000 (484,000 estimates ) ) Production from continuing (40,000) (59,000) operations Production from (3,000) (1,000) discontinued operations -------- -------- --- ----- December 31, 2001 341,000 368,000
Revisions of previous 185,000 4,000 estimates Production from continuing (36,000) (46,000) operations Production from (3,000) (1,000) discontinued operations -------- -------- --- ----- December 31, 2002 487,000 325,000
Sale of reserves in place (14,000) (1,000) Revisions of previous 99,000 151,000 estimates Production from continuing (40,000) (46,000) operations Production from (1,000) - discontinued operations -------- -------- --- ----- December 31, 2003 531,000 429,000 ====== ======= Proved developed reserves -
December 31, 2001 316,000 365,000 ======= ======= December 31, 2002 461,000 322,000 ======= ======= December 31, 2003 527,000 424,000 ======= =======
All of the Partnership's reserves are located within the continental United States.
*Ryder Scott Company, L.P. prepared the reserve and present value data for the Partnership's existing properties as of January 1, 2004. 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.
Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The results of the reserve report as of January 1, 2004, 2003 and 2002 are an average price of $31.21, $29.24 and $17.92 per barrel, respectively.
Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The results of the reserve report as of January 1, 2004, 2003 and 2002 are an average price of $5.70, $4.67 and $2.58 per Mcf, respectively.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
11. Estimated Oil & Gas Reserves (unaudited) - continued The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Partnership has reserves, which are classified as proved developed and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2003, 2002 and 2001 is presented below:
2003 2002 2001 ----- ----- ----- Future cash inflows $ 19,012,0 15,762,0 7,053,00 00 00 0 Production, development and abandonment costs 10,660,0 8,864,00 4,474,00 00 0 0 -------- -------- -------- ------ ------ ----- Future net cash flows 8,352,00 6,898,00 2,579,00 0 0 0 10% annual discount for estimated timing of cash flows 3,990,00 3,055,00 982,000 0 0 -------- -------- -------- ------ ------ ----- Standardized measure of discounted future net cash flows $ 4,362,00 3,843,00 1,597,00 0 0 0 ======== ======== ========
The principal sources of change in the standardized measure of discounted future net cash flows for the years ended December 31, 2003, 2002 and 2001 are as follows:
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
11. Estimated Oil & Gas Reserves (unaudited) - continued
2003 2002 2001 ----- ----- ----- Sales of oil and gas produced, net of production costs $ (690,000 (411,000 (568,000 ) ) ) Changes in prices and 282,000 1,349,00 (3,781,0 production costs 0 00) Changes of production rates (timing) and others (263,000 (171,000 388,000 ) ) Revisions of previous 889,000 1,319,00 (920,000 quantities estimates 0 ) Accretion of discount 384,000 160,000 589,000 Sales of minerals in place (83,000) - - Discounted future net cash flows - Beginning of year 3,843,00 1,597,00 5,889,00 0 0 0 -------- -------- -------- ----- ---- ------ End of year $ 4,362,00 3,843,00 1,597,00 0 0 0 ======= ======= ========
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.
12. Selected Quarterly Financial Results - (unaudited)
Quarter -------------------------------------- -------------------------------------- - First Second Third Fourth ------ -------- ------- -------- --- - 2003: Total revenues $ 428,725 321,326 340,009 330,296 Total expenses 211,287 207,905 195,739 263,607 -------- -------- -------- -------- ---- ---- ---- ---- Net income from 217,438 113,421 144,270 66,689 continuing operations Results from discontinued 7,791 12,053 107 - operations Cumulative effect of change in accounting principle - SFAS No. 143 (158,919 - - - ) -------- -------- -------- -------- ---- ---- ---- ---- Net income $ 66,310 125,474 144,377 66,689 ======= ======= ======= ======= Per limited partner unit amounts: Net income from $ 14.87 continuing operations 7.48 9.53 3.86 Discontinued operations .51 .80 .01 - Cumulative effects (10.52) - - - -------- -------- -------- -------- ---- ---- ---- ---- Net income $ 4.86 8.28 9.54 3.86 ======= ======= ======= =======
Discontinued operations relating to disposed properties were reclassed out of revenues and expenses.
Southwest Oil & Gas Income Fund VIII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
12. Selected Quarterly Financial Results - (unaudited) - continued As discussed in Note 4, in 2002 the Partnership changed methods of accounting for depletion of capitalized costs from the units-of- revenue method to the units-of-production method. The 2002 quarterly financial results presented below reflect the change in depletion method effective as of January 1, 2002.
Quarter -------------------------------------- -------------------------------------- - First Second Third Fourth ------ -------- ------- -------- --- - 2002: Total revenues $ 217,491 239,013 294,358 289,914 Total expenses 178,453 190,638 211,303 205,203 -------- -------- -------- -------- ---- ---- ---- ---- Net income from 39,038 48,375 83,055 84,711 continuing operations Results from discontinued 4,871 5,597 8,572 4,820 operations Cumulative effect of change in accounting principle - SFAS No. 143 (5,000) - - - -------- -------- -------- -------- ---- ---- ---- ---- Net income $ 38,909 53,972 91,627 89,531 ======= ======= ======= ======= Per limited partner unit amounts: Net income from $ 2.54 continuing operations 3.15 5.45 5.57 Discontinued operations .32 .37 .56 .31 Cumulative effects (.37) - - - -------- -------- -------- -------- ---- ---- ---- ---- Net income $ 2.49 3.52 6.01 5.88 ======= ======= ======= =======
Discontinued operations relating to disposed properties were reclassed out of revenues and expenses.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures As of the year ended December 31, 2003, H.H. Wommack, III, President and Chief Executive Officer of the Managing General Partner, and Bill E. Coggin, Executive Vice President and Chief Financial Officer of the Managing General Partner, evaluated the effectiveness of the Partnership's disclosure controls and procedures. Based on their evaluation, they believe that:
The disclosure controls and procedures of the Partnership were effective in ensuring that information required to be disclosed by the Partnership in the reports it files or submits under the Exchange Act was recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and
The disclosure controls and procedures of the Partnership were effective in ensuring that material information required to be disclosed by the Partnership in the report it filed or submitted under the Exchange Act was accumulated and communicated to the Managing General Partner's management, including its President and Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Internal Control Over Financial Reporting There has not been any change in the Partnership's internal control over financial reporting that occurred during the year ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, it internal control over financial reporting.
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 of the Managing General Partner serves for a term of one year.
Name Age Position - ----------------------- --- ----------------------------- - ---------------------- -- ----------------------------- H. H. Wommack, III 48 Chairman of the Board, President, Director and Chief Executive Officer James N. Chapman(1) 41 Director William P. Nicoletti(2) 58 Director Joseph J. Radecki, Jr. 45 Director (2) Richard D. Rinehart(1) 68 Director John M. White(2) 48 Director Herbert C. Williamson, 55 Director III(1) Bill E. Coggin 49 Executive Vice President and Chief Financial Officer J. Steven Person 45 Vice President, Marketing
(1) Member of the Compensation Committee
(2) Member of the Audit Committee
H. H. Wommack, III has served as Chairman of the Board, President, Chief Executive Officer and a director since Southwest's founding in 1983. Since 1997 Mr. Wommack has served as President, Chief Executive Officer and Chairman of SRH, Southwest's former parent and current holder of 10% of its voting share capital. SRH holds an equity investment in Southwest and in Basic Energy Services. Since 1997 Mr. Wommack has served as chairman of the board of directors of Midland Red Oak Realty, Inc. Midland Red Oak Realty owns and manages commercial real estate properties, including shopping centers and office buildings, in secondary real estate markets in the Southwestern United States. From 1997 until December 2000, Mr. Wommack served as chairman of the board of directors of Basic Energy Services, Inc. and since December 2000 has continued to serve on Basic's board of directors. Basic provides certain well services for oil and gas companies. Prior to Southwest's formation, Mr. Wommack was a self-employed independent oil and gas producer engaged in the purchase and sale of royalty and working interests in oil and gas leases and the drilling of wells. Mr. Wommack graduated from the University of North Carolina at Chapel Hill and received his law degree from the University of Texas.
James N. Chapman has served as a director since April 19, 2002. Mr. Chapman is associated with Regiment Capital Advisors, LLC, which he joined in January 2003. Prior to Regiment, Mr. Chapman acted as a capital markets and strategic planning consultant with private and public companies, as well as hedge funds, across a range of industries. Prior to establishing an independent consulting practice, Mr. Chapman worked for The Renco Group, Inc. from December 1996 to December 2001. Prior to Renco, Mr. Chapman was a founding principal of Fieldstone Private Capital Group in August 1990. Prior to joining Fieldstone, Mr. Chapman worked for Bankers Trust Company from July 1985 to August 1990, most recently in the BT Securities capital markets area. Mr. Chapman serves as a member of the board of directors of Anchor Glass Container Corporation, Davel Communications, Inc., Coinmach Corporation, as well as a number of private companies.
William P. Nicoletti has served as a director since April 19, 2002. Mr. Nicoletti is Managing Director of Nicoletti & Company Inc., an investment banking and financial advisory firm he founded in 1991. He was previously a senior officer and head of the Energy Investment Banking Groups of E. F. Hutton & Company Inc. and Paine Webber, Incorporated. From March 1998 until June 1990 he was a managing director and co-head of Energy Investment Banking at McDonald Investments Inc. Mr. Nicoletti is a director and Chairman of the Audit Committee of Star Gas Partners, L.P., the nation's largest retail distributor of home heating oil and a major retail distributor of propane gas. He is also a director of MarkWest Energy Partners, L.P., a business engaged in the gathering and processing of natural gas and the fractionation and storage of natural gas liquids, and Russell-Stanley Holdings, Inc., a manufacturer and marketer of steel and plastic industrial containers. Mr. Nicoletti is a graduate of Seton Hall University and received an MBA degree from Columbia University Graduate School of Business.
Joseph J. Radecki, Jr. has served as a director since April 19, 2002. Mr. Radecki is currently a Managing Director in the Leveraged Finance Group of CIBC World Markets where he is principally responsible for the firm's financial restructuring and distressed situation advisory practice. Prior to joining CIBC World Markets in 1998, Mr. Radecki was an Executive Vice President and Director of the Financial Restructuring Group of Jefferies & Company, Inc. beginning in 1990. From 1983 until 1990, Mr. Radecki was First Vice President in the International Capital Markets Group at Drexel Burnham Lambert, Inc., where he specialized in financial restructurings and recapitalizations. Over the past fourteen years, Mr. Radecki has been integrally involved in over 120 transactions totaling nearly $50 billion in recapitalized securities. Mr. Radecki currently serves as a Director of RBX Corporation, a manufacturer of rubber and plastic foam and other polymer products. He previously served as a Director of Wherehouse Entertainment, Inc., a music and video specialty retailer, as Chairman of the Board of American Rice, Inc., an international rice miller and marketer, as a member of the Board of Directors of Service America Corporation, a national food service management firm, Bucyrus International, Inc., a mining equipment manufacturer, and ECO-Net, a non- profit engineering related network firm. Mr. Radecki graduated magna cum laude in 1980 from Georgetown University with a B.A. in Government.
Richard D. Rinehart has served as a director since April 19, 2002. Mr. Rinehart is a founding principal of PetroCap, Inc. and president of Kestrel Resources, Inc. PetroCap, Inc. provides investment and merchant banking services to a variety of clients active in the oil and gas industry. Kestrel Resources, Inc. is a privately owned oil and gas operating company. He served as Director of Coopers & Lybrand's Energy Systems and Services Division prior to the founding of Kestrel Resources, Inc. in 1992. Prior to joining Coopers & Lybrand, he was chief executive officer/founder of Dawn Information Resources, Inc., formed in 1986 and acquired by Coopers & Lybrand in early 1991. Mr. Rinehart served as CEO of Terrapet Energy Corporation during the period 1982 through 1986. Prior to the formation of Terrapet in 1982, he was employed as President of the Terrapet Division of E.I. DuPont de Nemours and Company. Before its acquisition by DuPont, he served as CEO and President of Terrapet Corp., a privately owned E & P company. Before the formation of Terrapet Corp. in 1972, he was manager of supplementary recovery methods and senior evaluation engineer with H. J. Gruy and Associates, Inc., Dallas, Texas.
John White has served as a director since April 19, 2002. Mr. White became an equity analyst for Harris Nesbitt Gerard following the acquisition by BMO Financial Group in 2003. He had joined BMO Nesbitt Burns in 1998, responsible for high yield research on oil, gas and energy companies. Previously, Mr. White worked at John S. Herold, Inc., an independent oil and gas research and consulting firm, where he was responsible for fixed income research on the oil and gas industry. His prior experience also included four years managing a portfolio of oil and gas loans for The Bank of Nova Scotia. Before entering financial services, Mr. White was with BP, where he worked in exploration and production for seven years. At BP, his experience was primarily in the basins of the Mid-Continent and Rocky Mountain regions. Mr. White is a graduate of The University of Oklahoma.
Herbert C. Williamson, III has served as a director since April 19, 2002. At present, Mr. Williamson is self-employed as a consultant. From March 2001 to March 2002 Mr. Williamson served as an investment banker with Petrie Parkman & Co. From April 1999 to March 2001 Mr. Williamson served as chief financial officer and from August 1999 to March 2001 as a director of Merlon Petroleum Company, a private oil and gas company involved in exploration and production in Egypt. Mr. Williamson served as executive vice president, chief financial officer and director of Seven Seas Petroleum, Inc., a publicly traded oil and gas exploration company, from March 1998 to April 1999. From 1995 through April 1998, he served as director in the Investment Banking Department of Credit Suisse First Boston. Mr. Williamson served as vice chairman and executive vice president of Parker and Parsley Petroleum Company, a publicly traded oil and gas exploration company (now Pioneer Natural Resources Company) from 1985 through 1995.
Bill E. Coggin has served as Vice President and Chief Financial Officer since joining the Managing General Partner in 1985. Previously, Mr. Coggin was Controller for Rod Ric Corporation, an oil and gas drilling company, and for C.F. Lawrence & Associates, a large independent oil and gas operator. Mr. Coggin received a B.S. in Education and a B.A. in Accounting from Angelo State University.
J. Steven Person has served as Vice President, Marketing since joining the Managing General Partner in 1989. Mr. Person began in the investment industry with Dean Witter in 1983. Prior to joining the Managing General Partner, Mr. Person was a senior wholesaler with Capital Realty, Inc. While at Capital Realty, he was involved in the syndication of mortgage based securities through the major brokerage houses. Mr. Person received a B.B.A. degree from Baylor University and an M.B.A. from Houston Baptist University.
Key Employees
Jon P. Tate, age 46, has served as Vice President, Land and Assistant Secretary of the Managing General Partner since 1989. From 1981 to 1989, Mr. Tate was employed by C.F. Lawrence & Associates, Inc., an independent oil and gas company, as land manager. Mr. Tate is a member of the Permian Basin Landman's Association.
R. Douglas Keathley, age 48, has served as Vice President, Operations of the Managing General Partner since 1992. Before joining us, Mr. Keathley worked as a senior drilling engineer for ARCO Oil and Gas Company and in similar capacities for Reading & Bates Petroleum Co. and Tenneco Oil Co.
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.
Code of Ethics
Neither the Partnership nor the Managing General Partner has adopted a code of ethics for employees, or any principal executive officers, principal financial officers, principal accounting officers or the Board of Directors of the Managing General Partner. The Board of the Managing General Partner believes that the Partnership's existing internal control procedures and current business practices are adequate to promote ethical conduct and to deter wrongdoing on the part of these executives. The Managing General Partner of the Partnership intends to implement during 2004 a code of ethics that will apply to these executives. In accordance with applicable SEC rules, the code of ethics will be made publicly available.
Audit Committee
The current members of the Audit Committee of the Managing General Partner are William P. Nicoletti, John M. White and Joseph J. Radecki, Jr. The Board of Directors of the Managing General Partner has determined that Mr. Nicoletti, the Chairman of the Audit Committee, meets the definition of an "audit committee financial expert" under Item 401(h)(2) of Regulation S-K and has also determined that all of the members of the Audit Committee, including Mr. Nicoletti, meet the independence requirements of Section 10A(m)(3) of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.
Item 11.
Item 11. Executive Compensation
The Partnership does not employ any directors, executive officers or employees. The Managing General Partner receives an administrative fee for the management of the Partnership. The Managing General Partner received $98,400 during 2003, 2002 and 2001 as an annual administrative fee. The executive officers of the Managing General Partner do not receive any form of compensation, from the Partnership; instead, their compensation is paid solely by Southwest. The executive officers, however, may occasionally perform administrative duties for the Partnership but receive no additional compensation for this work.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
There are no limited partners who own of record, or are known by the Managing General Partner to beneficially own, more than five percent of the Partnership's limited partnership interests.
The Managing General Partner owns a ten percent interest in the Partnership as a general partner. Through repurchase offers to the limited partners, the Managing General Partner also owns 3,466.5 limited partner units, a 22.9% limited partner interest. The Managing General Partner total percentage interest ownership in the Partnership is 32.9%.
No officer or director of the Managing General Partner directly owns units in the Partnership. The officers and directors of the Managing General Partner are considered beneficial owners of the limited partner units acquired by the Managing General Partner by virtue of their status as such. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and includes voting or investment power with respect to the limited partner units. To our knowledge, except under applicable community property laws or as otherwise indicated, the persons named in the table have sole voting and sole investment control with regard to all limited partner units beneficially owned. We are presenting ownership information as of December 31, 2003. A list of beneficial owners of limited partner units, known to the Managing General Partner, is as follows:
Amount and Nature of Percen t Name and Address of Beneficial of Title of Class Beneficial Owner Ownership Class - ------------------- --------------------- ---------- ------ -------------- -------------- --------- ------ Limited Partnership Southwest Royalties, Directly 22.9% Interest Inc. Owns Managing General 3,466.5 Partner Units 407 N. Big Spring Street Midland, TX 79701
Limited Partnership H. H. Wommack, III Indirectly 22.9% Interest Owns Chairman of the 3,466.5 Board, Units President, and CEO of Southwest Royalties, Inc., the Managing General Partner 407 N. Big Spring Street Midland, TX 79701
There are no arrangements known to the Managing General Partner which may at a subsequent date result in a change of control of the Partnership.
Item 13.
Item 13. Certain Relationships and Related Transactions
In 2003, the Managing General Partner received $98,400 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 $121,900 for administrative overhead attributable to operating such properties during 2003.
The terms of the above transaction are similar to ones, which would have been obtained through arm's length negotiations with unaffiliated third parties.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table presents fees for professional audit services rendered by KPMG, LLP for the audit of the Partnership's annual financial statements for the years ended December 31, 2003 and 2002 and fees billed for other services rendered by KPMG during those periods.
For the Year Ended December 2003 31, 2002
Audit Fees $8,761 $ 4,763 Audit Related Fees - - Tax Fees - - All Other Fees - -
TOTAL $8,761 $ 4,763
The Audit Committee of the Managing General Partner reviewed and approved, in advance, all audit and non-audit services provided by KPMG, LLP.
Part IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)(1) Financial Statements:
Included in Part II of this report --
Independent Auditors Report Balance Sheets Statements of Operations Statement of Changes in Partners' Equity Statements of Cash Flows Notes to Financial Statements
(2) Schedules required by Article 12 of Regulation S- X are either omitted because they are not applicable or because the required information is shown in the financial statements or the notes thereto.
(3) Exhibits:
4 (a) Certificate of Limited Partnership of Southwest Oil & Gas Income Fund VIII-A, L.P., dated November 30, 1987. (Incorporated by reference from Partnership's S-1 Registration Statement File Number 33-18847 effective March 31, 1988.)
(b) Agreement of Limited Partnership of Southwest Oil & Gas Income Fund VIII-A, L.P. dated July 6, 1988. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
31.1 Rule 13a-14(a)/15d-14(a) Certification 31.2 Rule 13a-14(a)/15d-14(a) Certification 32.1 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 32.2 Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
(b) Reports on Form 8-K
There were no reports filed on Form 8-K during the quarter ended December 31, 2003.
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 Oil & Gas Income Fund VIII-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: May 12, 2004
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ H. H. Wommack, III /s/ Bill E. Coggin - --------------------------- ------------------------ - -------------------- ----------------------- H. H. Wommack, III, Bill E. Coggin, Chairman of the Board, Executive Vice President President, Director and and Chief Financial Chief Executive Officer Officer
Date: May 12, 2004 Date: May 12, 2004
/s/ William P. Nicoletti /s/ James N. Chapman - --------------------------- ------------------------ - -------------------- ----------------------- William P. Nicoletti, James N. Chapman, Director Director
Date: May 10, 2004 Date: May 12, 2004
/s/ Richard D. Rinehart /s/ Joseph J. Radecki, Jr. - --------------------------- ------------------------ - -------------------- ----------------------- Richard D. Rinehart, Joseph J. Radecki, Jr., Director Director
Date: May 12, 2004 Date: May 12, 2004
/s/ Herbert C. Williamson, III - --------------------------- ------------------------ - -------------------- ----------------------- Herbert C. Williamson, III, John M. White, Director Director
Date: May 11, 2004 Date:
SECTION 302 CERTIFICATION Exhibit 31.1
I, H.H. Wommack, III, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil and Gas Income Fund VIII-A, L.P.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting.
Date: May 12, 2004 /s/ H. H. Wommack, III H. H. Wommack, III Chairman, President and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VIII-A, L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Bill E. Coggin, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil and Gas Income Fund VIII-A, L.P.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting.
Date: May 12, 2004 /s/ Bill E. Coggin Bill E. Coggin Executive Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VIII-A, L.P.
CERTIFICATION PURSUANT TO Exhibit 32.1 19 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Oil & Gas Income Fund VIII-A, L.P. (the "Company") on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, H.H. Wommack, III, Chief Executive Officer of the Managing General Partner of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.
Date: May 12, 2004
/s/ H.H. Wommack, III H. H. Wommack, III Chairman, President, Director and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VIII-A, L.P.
CERTIFICATION PURSUANT TO Exhibit 32.2 19 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Southwest Oil & Gas Income Fund VIII-A, L.P. (the "Company") on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Bill E. Coggin, Chief Financial Officer of the Managing General Partner of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.
Date: May 12, 2004
/s/ Bill E. Coggin Bill E. Coggin Executive Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VIII-A, L.P.