Item 1. Business
General Southwest Oil & Gas Income Fund VII-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on January 30, 1987. The offering of limited partnership interests began March 4, 1987, reached minimum capital requirements on April 28, 1987 and concluded September 21, 1987. The Partnership has no subsidiaries. The Managing General Partner of the Partnership is Southwest Royalties, Inc. (the "Managing General Partner"), a Delaware corporation.
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.
During 2004, the Managing General Partner was acquired by Clayton Williams Energy, Inc. ("CWEI"), a Delaware corporation, and is now a wholly owned subsidiary of CWEI. CWEI is an oil and gas company based in Midland, Texas, and its common stock is traded on the Nasdaq Stock Market's National Market under the symbol "CWEI". All of the directors and executive officers of the Managing General Partner are employees of CWEI. CWEI maintains an internet website at www.claytonwilliams.com from which public information about CWEI may be obtained.
The principal executive offices of the Partnership are located at 6 Desta Drive, Suite 6500, Midland, Texas, 79705. The Managing General Partner and its staff, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of oil and gas properties and the marketing of production from such properties. The Partnership has no employees.
Operations
The business objective of the Partnership is to maximize the production and related net cash flow from the properties it currently owns without engaging in the drilling of any development or exploratory wells except through farm-out arrangements. If additional drilling is necessary to fully develop a Partnership property, the Partnership will enter into a farmout agreement with the Managing General Partner to assign a portion of the Partnership's interest in the property to the Managing General Partner in exchange for retaining an interest in the one or more new wells at no cost to the Partnership. The Managing General Partner obtains a fairness opinion from an unaffiliated petroleum engineer with respect to the terms of each farmout agreement with the Partnership.
During 2004, the Partnership entered into one farmout agreement with the Managing General Partner through which the Managing General Partner drilled the VT Amacker 62 8H well and completed it as a producer. The Partnership retained 10 % of its original interest in the well and paid none of the cost to drill and complete the well.
Principal Products and Markets The Partnership has acquired and holds working interest in oil and gas properties located in Texas, New Mexico, Oklahoma and Louisiana. All activities of the Partnership are confined to the continental United States. During 2004, 59% of the Partnership's revenues were derived from the sale of oil production and 41% were derived from gas production. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business. The Partnership believes that the loss of any of its purchasers would not have a material adverse affect on its results of operations due to the availability of other purchasers.
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. The Partnership is unable to accurately predict future prices of oil and natural gas.
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
The Partnership's oil and gas production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Partnership's cost of doing business and affects the Partnership's profitability. Because such rules and regulations are frequently amended or reinterpreted, the Partnership is unable to predict the future cost or impact of complying with such laws.
All of the states in which the Partnership conducts business generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from the Partnership's properties.
The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas produced by the Partnership, as well as the revenues the Partnership receives for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance the Partnership's ability to market and transport its gas, although this framework may also subject the Partnership to competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
The Partnership's sales of oil production are not presently regulated and are made at market prices. The price the Partnership receives from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. The Partnership is not able to predict with any certainty what effect, if any, these regulations will have on the Partnership, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Environmental Matters
The Partnership's operations pertaining to oil and gas production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to or in connection with drilling activities, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production, restrict or prohibit drilling activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells, and impose substantial liabilities for pollution resulting from the Partnership's operations. Such laws and regulations may substantially increase the cost of developing, producing or processing oil and gas and may prevent or delay the commencement or continuation of a given project and thus generally could have a material adverse effect upon the Partnership's cash flow and earnings. The Partnership believes that it is in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2005. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on the Partnership's operations, as well as the oil and gas industry in general. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as "hazardous wastes," which reclassification would make exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements. State initiatives to further regulate the disposal of oil and gas wastes and naturally occurring radioactive materials, if adopted, could have a similar impact on the Partnership.
The United States Oil Pollution Act of 1990 ("OPA `90"), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA `90 and such similar legislation and related regulations impose on us a variety of obligations related to the prevention of oil spills and liability for damages resulting from such spills. OPA `90 imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil removal costs and a variety of public and private damages.
The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The failure of an operator of a property owned by the Partnership to comply with applicable environmental regulations may, in certain circumstances, be attributed to the Partnership. The Partnership does not believe that it will be required to incur any material expenditures to comply with existing environmental requirements.
The Resource Conservation and Recovery Act ("RCRA"), and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, the Partnership does not expect to experience more burdensome costs than similarly situated companies
State water discharge regulations and federal waste discharge permitting requirements adopted pursuant to the Federal Water Pollution Control Act prohibit or are expected in the future to prohibit the discharge of produced water and sand and some other substances related to the oil and gas industry, into coastal waters. Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and the Partnership does not believe that these costs will have a material adverse impact on its financial condition and operations.
The Partnership maintains 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 the Partnership's investment in the associated site.
Partnership Employees The Partnership has no employees; however the Managing General Partner and CWEI have 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, the Partnership engages independent consultants such as petroleum engineers and geologists as needed.
Item 2.
Item 2. Properties
As of December 31, 2004, the Partnership possessed an interest in oil and gas properties located in Cameron Parish of Louisiana; Chaves and Lea Counties of New Mexico; Pottawatomie County of Oklahoma; Howard, Leon, Upton, Ward and Winkler Counties of Texas. These properties consist of various interests in approximately 81wells and units.
Reserves
The following table sets forth certain information as of December 31, 2004 with respect to the Partnership's estimated proved oil and gas reserves pursuant to SEC guidelines, present value of proved reserves and standardized measure of discounted future net cash flows.
Proved Developed Proved Total ------------------- ------- ------- ------------------- ------- ---- --------- ---- Produci Nonprod Undevel Proved ng ucing oped ------- ------- ------- ------- ------- ------- ------- ---- ----- ---- ---- Oil (Bbls) 194,000 1,000 39,000 234,000 Gas (Mcf) 829,000 50,000 465,000 1,344,0 Total (BOE) 332,000 9,000 117,000 458,000 Present value of $3,834, $87,000 $2,042,0 $5,963, proved reserves 000 00 000 Standardized measure of discounted future net cash $5,866, flows 000
The following table sets forth certain information as of December 31, 2004 regarding the Partnership's proved oil and gas reserves for certain significant properties.
Proved Reserves Percen t ----------------------- Present of ----------------------- Presen ---------- t Total Percen Value of Value Oil t of of Oil Gas Equiva Total Proved Proved lent Oil (Bbls (Mcf) (BOE) Equiva Reserves Reserv ) lent es ----- ----- ------ ------ ------------ ------ ----- ----- ------ ------ ---------- ------ --- - --- --- ---
Mobil 49,00 1,196 248,00 54.1% 3,649,00 61.2% Acquisition 0 ,000 0 0 BHP- 95,00 24,00 99,000 21.6% 1,116,00 18.7% Hendricks 0 0 0 Other 90,00 124,0 111,00 24.3% 1,198,00 20.1% 0 00 0 0 ----- ----- ------ ------ -------- ------ ----- ----- ------ ------ ------ ------ - -- - --- Total 234,0 1,344 458,00 100.0% $5,963, 100.0% 00 ,000 0 000 ===== ===== ====== ====== ======== ====== = == = == ===
The estimates of proved reserves at December 31, 2004 and the present value of proved reserves were derived from a report prepared by Ryder Scott Company, L.P., petroleum consultants. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service (if any) and depletion, depreciation and amortization.
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of the Partnership's proved reserves and the present value of proved reserves set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and gas prices. The average prices utilized for the purposes of estimating the Partnership's proved reserves and the present value of proved reserves as of December 31, 2004 were $40.55 per Bbl of oil and natural gas liquids and $5.39 per Mcf of gas, as compared to $30.21 per Bbl of oil and $5.63 per Mcf of gas as of December 31, 2003.
The reserve information shown is estimated. The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although the Partnership believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
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.
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 2004 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.
Number of Limited Partner Interest Holders As of December 31, 2004, there were 519 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 2004, distributions were made totaling $611,662, with $550,474 (36.70 per unit) distributed to the limited partners and $61,188 to the general partners.
Issuer Purchases of Equity Securities 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. The following table sets forth certain information regarding purchases of limited partnership units by the Managing General Partner during the year of 2004.
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 Purchase Paid Per Programs or d Unit Programs - ------------- -------- -------- ---------- ---------- - ------------- -------- -------- ---------- ---------- -- - -- --- --- January 2004 - $ - - (1) February 2004 - - - (1) March 2004 - - - (1) April 2004 - - - (1) May 2004 - - - (1) June 2004 - - - (1) July 2004 - - - (1) August 2004 - - - (1) September - - - (1) October 2004 794.67 210.80 - (1) November 2004 - - - (1) December 2004 - - - (1) ------- ------- ------- --- TOTALS 794.67 $210.80 - ==== ====== ====
(1) Not determinable.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 2004, 2003, 2002, 2001 and 2000 should be read in conjunction with the financial statements included in Item 8:
Years Ended December 31, 2004 2003 2002 2001 2000 ------ ------ ------ ------ ------ Revenues $ 1,182,04 944,893 751,555 748,950 935,534
Net income before cumulative effects of accounting changes 633,852 426,915 257,580 255,471 469,763
Net income 633,852 336,766 252,580 255,471 469,763
Partners' share of net income:
General partners 63,385 33,677 25,258 25,547 46,976
Limited partners 570,467 303,089 227,322 229,924 422,787
Limited partners' net income per unit before cumulative effects of accounting changes 38.03 25.62 15.45 15.33 28.19
Limited partners' net income per unit 38.03 20.21 15.15 15.33 28.19
Limited partners' cash distributions 36.70 per unit 26.15 15.69 25.53 26.10
Total assets $ 629,676 595,976 516,986 525,666 696,110
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 the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.
Well operating costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately. Net income available for distribution to the limited partners has fluctuated over the past few years and is expected to decline in later years based on these factors.
Critical Accounting Policies 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 depletion, depreciation, and amortization ("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.
Results of Operations
General Comparison of the Years Ended December 31, 2004 and 2003
The following table provides certain information regarding performance factors for the years ended December 31, 2004 and 2003:
Percenta ge Year Ended Increase December 31, 2004 2003 (Decreas e) ------ ------ -------- ----- Oil production in 17,995 17,500 3% barrels Gas production in mcf 79,611 86,500 (8%) Total (BOE) 31,264 31,917 (2%) Average price per barrel $ 38.52 32% of oil 29.13 Average price per mcf of $ 6.12 24% gas 4.93 Oil and gas revenue $ 1,180,61 936,280 26% Production expense $ 386,319 342,567 13% Partnership $ 611,662 435,882 40% distributions Limited partner $ 550,474 392,294 40% distributions Per unit distribution to $ 36.70 40% limited partners 26.15
Number of limited 15,000 15,000 partner units
Revenues
The Partnership's oil and gas revenues increased to $1,180,619 from $936,280 for the years ended December 31, 2004 and 2003, respectively, an increase of 26%. The principal factors affecting the comparison of the years ended December 31, 2004 and 2003 are as follows:
The average price for a barrel of oil received by the Partnership increased during the year ended December 31, 2004 as compared to the year ended December 31, 2003 by 32%, or $9.39 per barrel, resulting in an increase of approximately $169,000 in revenues. Oil sales represented 59% of total oil and gas sales during the year ended December 31, 2004 as compared to 54% during the year ended December 31, 2003.
The average price for an mcf of gas received by the Partnership increased during the same period by 24%, or $1.19 per mcf, resulting in an increase of approximately $94,700 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $263,700. The market price for oil and gas has been extremely volatile over the past decade and management expects a certain amount of volatility to continue in the foreseeable future.
Oil production increased approximately 495 barrels or 3% during the year ended December 31, 2004 as compared to the year ended December 31, 2002, resulting in an increase of approximately $14,400 in revenues.
Gas production decreased approximately 6,889 mcf or 8% during the same period, resulting in a decrease of approximately $34,000 in revenues.
The net total decrease in revenues due to the change in production is approximately $19,600.
Costs and Expenses
Total costs and expenses increased to $548,287 from $517,978 for the years ended December 31, 2004 and 2003, respectively, an increase of 6%. The increase is the result of higher lease operating costs, partially offset by a decrease in depletion expense and accretion expense.
Lease operating costs and production taxes were 13% higher, or approximately $43,800 more during the year ended December 31, 2004 as compared to the year ended December 31, 2003. The increase in lease operating costs and production taxes is due to the increased property taxes and production taxes from higher oil and gas prices.
Depletion expense decreased to $26,707 for the year ended December 31, 2004 from $38,000 for the same period in 2003. This represents a decrease of 29%. The contributing factor to the decrease in depletion expense is in relation to the BOE depletion rate for the year ended December 31, 2004, which was $.85 applied to 31,264 BOE as compared to $1.19 applied to 31,917 BOE for the same period. Oil and gas reserves increases from extensions and discoveries and high prices resulted in lower depletion rates per BOE.
Accretion expense decreased to $10,475 for the year ended December 31, 2004 from $13,154 for the same period in 2003. This represents a decrease of 20%. The decrease in accretion is from discontinuing accretion on several wells that reached their projected end of life in 2004.
Results of Operations
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:
Percenta ge Year Ended Increase December 31, 2003 2002 (Decreas e) ------ ------ -------- ----- Oil production in 17,500 18,600 (6%) barrels Gas production in mcf 86,500 101,300 (15%) Total (BOE) 31,917 35,483 (10%) Average price per barrel $ 29.13 22% of oil 23.94 Average price per mcf of $ 4.93 67% gas 2.96 Oil and gas revenue $ 936,280 745,590 26% Production expense $ 342,567 333,897 3% Partnership $ 435,882 261,469 66% distributions Limited partner $ 392,294 235,322 66% distributions Per unit distribution to $ 26.15 66% limited partners 15.69
Number of limited 15,000 15,000 partner units
Revenues
The Partnership's oil and gas revenues increased to $936,280 from $745,590 for the years ended December 31, 2003 and 2002, respectively, an increase of 26%. The principal factors affecting the comparison of the years ended December 31, 2003 and 2002 are as follows:
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 22%, or $5.19 per barrel, resulting in an increase of approximately $90,800 in revenues. Oil sales represented 54% of total oil and gas sales during the year ended December 31, 2003 as compared to 60% 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 67%, or $1.97 per mcf, resulting in an increase of approximately $170,400 in revenues.
The total increase in revenues due to the change in prices received from oil and gas production is approximately $261,200. 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.
Oil production decreased approximately 1,100 barrels or 6% during the year ended December 31, 2003 as compared to the year ended December 31, 2002, resulting in a decrease of approximately $26,300 in revenues.
Gas production decreased approximately 14,800 mcf or 15% during the same period, resulting in a decrease of approximately $43,800 in revenues.
The total decrease in revenues due to the change in production is approximately $70,100. The decrease in gas volume is the result of a lower net revenue interest on a lease offset by larger volumes from new wells drilled on that lease through a farm-out arrangement.
Costs and Expenses
Total costs and expenses increased to $517,978 from $493,975 for the years ended December 31, 2003 and 2002, respectively, an increase of 5%. The increase is the result of the addition of accretion expense, higher general and administrative expense and lease operating costs, partially offset by a decrease in depletion expense.
Lease operating costs and production taxes were 3% higher, or approximately $8,700 more during the year ended December 31, 2003 as compared to the year ended December 31, 2002.
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 $8,200 during the year ended December 31, 2003 as compared to the year ended December 31, 2002.
Depletion expense decreased to $38,000 for the year ended December 31, 2003 from $44,000 for the same period in 2002. This represents a decrease of 14%. 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 $1.19 applied to 31,917 BOE as compared to $1.24 applied to 35,483 BOE for the same period.
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 $73,903, a long term liability of approximately $164,052 and a loss of approximately $90,149 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 $177,971. The increase in the asset retirement obligation from January 1, 2003 is due to accretion expense of $13,154 and the addition of a well due to a farm-out arrangement for $765. The pro forma amount of the asset retirement obligation as of December 31, 2002 was approximately $164,052. 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.
Revenue and Distribution Comparison Partnership net income for the years ended December 31, 2004, 2003 and 2002 was $633,852, $336,766 and $252,580, respectively. Partnership distributions for the years ended December 31, 2004, 2003 and 2002 were $611,662, $435,882 and $261,469, respectively. These differences are indicative of the changes in oil and gas prices, production and properties during 2004, 2003 and 2002.
The sources for the 2004 distributions of $611,662 were oil and gas operations of approximately $616,700 and the change in oil and gas properties of approximately $(10,300), with the balance from available cash on hand at the beginning of the period. The sources for the 2003 distributions of $435,882 were oil and gas operations of approximately $490,000 and the change in oil and gas properties of approximately $(15,200), with the balance available for subsequent distributions. The sources for the 2002 distributions of $261,469 were oil and gas operations of approximately $238,900 and the change in oil and gas properties of approximately $3,200, with the balance from available cash on hand at the beginning of the period.
Total distributions during the year ended December 31, 2004 were $611,662 of which $550,474 ($36.70 per unit) was distributed to the limited partners and $61,188 to the general partners. Total distributions during the year ended December 31, 2003 were $435,882 of which $392,294 ($26.15 per unit) was distributed to the limited partners and $43,588 to the general partner. Total distributions during the year ended December 31, 2002 were $261,469, of which $235,322 ($15.69 per unit) was distributed to the limited partners and $26,147 to the general partner.
Cumulative cash distributions of $12,113,325 have been made to the general and limited partners as of December 31, 2004. As of December 31, 2004, $10,920,185 or $728.01 per limited partner unit has been distributed to the limited partners, representing 146% of contributed capital.
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 $616,700 compared to $490,000 in 2003 and approximately $238,900 in 2002.
Cash flows (used in) provided by investing activities were approximately $(10,300) in 2004 compared to ($15,200) in 2003 and approximately $3,200 in 2002. The principal use of the 2004 cash flows from investing activities was additions to oil and gas properties.
Cash flows used in financing activities were approximately $610,000 in 2004 compared to $435,700 in 2003 and approximately $261,300 in 2002. The only use in financing activities is the distributions to partners.
As of December 31, 2004, the Partnership had approximately $210,600 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.
Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 153 "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29" ("SFAS 153"). SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Partnership will adopt this statement in the third quarter of 2005, and it is not expected to have a material effect on the financial statements when adopted.
In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC staff's views regarding SFAS No. 143 and its impact on both the full-cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the first quarter of 2005, undiscounted abandonment costs for wells to be drilled in the future to develop proved reserves should be included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing depreciation, depletion and amortization ("DD&A"). The effect of including undiscounted abandonment costs of future wells to the undiscounted cost of oil and gas properties may increase DD&A expense in future periods, however, the Partnership currently does not believe SAB 106 will have a material impact on our financial statements.
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
Report of Independent Registered Public Accounting Firm 20
Balance Sheets 21
Statements of Operations 22
Statement of Changes in Partners' Equity 23
Statements of Cash Flows 24
Notes to Financial Statements 26
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Partners Southwest Oil & Gas Income Fund VII-A, L.P. (A Delaware Limited Partnership)
We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund VII-A, L.P. (the "Partnership") as of December 31, 2004 and 2003, and the related statements of operations, partners' equity, and cash flows for each of the years in the three-year period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 VII-A, L.P. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three- year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
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 Dallas, Texas March 26, 2005
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership) Balance Sheets December 31, 2004 and 2003
2004 2003 ------ ------ Assets - ---------- Current assets: Cash and cash equivalents $ 69,020 72,631 Receivable from Managing 144,290 90,640 General Partner Oklahoma withholding 639 - prepayment -------- -------- ---- ---- Total current assets 213,949 163,271 -------- -------- ---- ---- Oil and gas properties - using the full- cost method of accounting 4,580,20 4,570,47 6 7 Less accumulated depreciation, depletion and 4,164,47 4,137,77 amortization 9 2 -------- -------- ---- ---- Net oil and gas 415,727 432,705 properties -------- -------- ---- ---- $ 629,676 595,976 ======= ======= Liabilities and Partners' Equity - ---------------------------- - ------------
Current liability - $ 3,327 1,704 distribution payable -------- -------- ---- ----
Asset retirement obligation 187,858 177,971 -------- -------- ---- ---- Partners' equity: General partner (590,627 (592,824 ) ) Limited partners 1,029,11 1,009,12 8 5 -------- -------- ---- ---- Total partners' equity 438,491 416,301 -------- -------- ---- ---- $ 629,676 595,976 ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership) Statements of Operations Years ended December 31, 2004, 2003 and 2002
2004 2003 2002 ------ ------ ------ Revenues - ------------- Oil and gas revenue $ 1,180,61 936,280 745,590 Interest income from 745 721 681 operations Other 684 7,892 5,284 -------- -------- -------- --- --- --- 1,182,04 944,893 751,555 -------- -------- -------- --- --- --- Expenses - ------------ Production 386,319 342,567 333,897 Depreciation, depletion and 26,707 38,000 44,000 amortization Accretion expense 10,475 13,154 - General and administrative 124,695 124,257 116,078 -------- -------- -------- ---- --- --- 548,196 517,978 493,975 -------- -------- -------- ---- --- --- Net income before cumulative effects of accounting changes 633,852 426,915 257,580
Cumulative effect of change in accounting principle - SFAS No. 143 - See - (90,149) - Note 3 Cumulative effect of change in accounting principle - change in depletion method - - - (5,000) See Note 4 -------- -------- -------- ---- --- --- Net income $ 633,852 336,766 252,580 ======= ====== ====== Net income allocated to: Managing General Partner $ 63,385 33,677 25,258 ======= ====== ====== Limited partners $ 570,467 303,089 227,322 ======= ====== ====== Per limited partner unit $ 38.03 before cumulative effects 25.62 15.45 Cumulative effect per limited - (.30) partner unit (5.41) -------- -------- -------- ---- --- --- Per limited partner unit $ 38.03 20.21 15.15 ======= ====== ======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership) Statement of Changes in Partners' Equity Years ended December 31, 2004, 2003 and 2002
General Limited Partner Partners Total -------- -------- -------- --- ---- -
Balance at $ (582,024 1,106,33 524,306 December 31, 2001 ) 0
Net income 25,258 227,322 252,580
Distribution (26,147) (235,322 (261,469 ) ) -------- -------- -------- --- ----- ---- Balance at (582,913 1,098,33 515,417 December 31, 2002 ) 0
Net income 33,677 303,089 336,766
Distribution (43,588) (392,294 (435,882 ) ) -------- -------- -------- --- ----- ---- Balance at (592,824 1,009,12 416,301 December 31, 2003 ) 5
Net income 63,385 570,467 633,852
Distribution (61,188) (550,474 (611,662 ) ) -------- -------- -------- --- ----- ---- Balance at $ (590,627 1,029,11 438,491 December 31, 2004 ) 8 ====== ======== =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2004, 2003 and 2002
2004 2003 2002 ------ ------ ------ Cash flows from operating activities: Cash received from oil and $ 1,110,19 930,623 701,182 gas sales 6 Cash paid for production expenses, administrative fees and general and (494,880 (449,200 (468,217 administrative overhead ) ) ) Interest received 745 721 681 Other 684 7,892 5,284 -------- -------- -------- ---- ---- ---- Net cash provided by 616,745 490,036 238,930 operating activities -------- -------- -------- ---- ---- ---- Cash flows from investing activities: Additions to oil and gas (10,317) (15,276) - properties Sale of oil and gas - 38 3,241 properties -------- -------- -------- ---- ---- ---- Net cash (used in) provided (10,317) (15,238) 3,241 by investing activities -------- -------- -------- ---- ---- ---- Cash flows used in financing activities: Distributions to partners (610,039 (435,747 (261,260 ) ) ) -------- -------- -------- ---- ---- ---- Net (decrease) increase in (3,611) 39,051 (19,089) cash and cash equivalents
Beginning of year 72,631 33,580 52,669 -------- -------- -------- ---- ---- ---- End of year $ 69,020 72,631 33,580 ======= ======= ======= (continu ed)
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership) Statements of Cash Flows Years ended December 31, 2004, 2003 and 2002
2004 2003 2002 ------ ------ ------ Reconciliation of net income to net cash provided by operating activities:
Net income $ 633,852 336,766 252,580
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and 26,707 38,000 44,000 amortization Accretion expense 10,475 13,154 - Cumulative effect of change - 90,149 5,000 in accounting principle Increase in receivables (70,423) (5,657) (44,408) Increase (decrease) in 16,134 17,624 (18,242) payables -------- -------- -------- ---- ---- ---- Net cash provided by operating $ 616,745 490,036 238,930 activities ======= ======= ======= Noncash investing and financing activities: Increase in oil and gas properties - Adoption of SFAS No. 143 $ - 73,903 - ======= ======= ======= Decrease in oil and gas properties - SFAS No. 143 sale of properties $ - 765 - ======= ======= ======= Decrease in oil and gas properties - SFAS No. 143 plug and abandoned wells $ 588 - - ======= ======= =======
The accompanying notes are an integral part of these financial statements.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
1. Organization Southwest Oil & Gas Income Fund VII-A, L.P. was organized under the laws of the state of Delaware on January 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., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as 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 100% - costs (1) Amortization of organization 100% - costs Property acquisition costs 100% - Gain/loss on property 90% 10% dispositions Operating and administrative 90% 10% costs (2) Depreciation, depletion and amortization of oil and gas properties 90% 10% 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. As of December 31, 2004, 2003 and 2002, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
Estimates and Uncertainties The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership's 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.
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, 2004 and 2003 the Partnership was under produced by 2,368 and 2,101 mcf of gas, respectively.
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, 2004 and 2003 is $78,127 and $76,914, more than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
2. Summary of Significant Accounting Policies - continued
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, 2004, 2003 and 2002, there were 15,000 limited partner units outstanding held by 519, 569 and 566 partners.
Concentrations of Credit Risk The Partnership is subject to credit risk through trade receivables. Although a substantial portion of its debtors' ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the partnership.
Fair Value of Financial Instruments The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.
Net Income (loss) per limited partnership unit The net income (loss) per limited partnership unit is calculated by using the number of outstanding limited partnership units.
Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 153 "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29" ("SFAS 153"). SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Partnership will adopt this statement in the third quarter of 2005, and it is not expected to have a material effect on the financial statements when adopted.
In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC staff's views regarding SFAS No. 143 and its impact on both the full- cost ceiling test and the calculation of depletion expense. In accordance with SAB 106, beginning in the first quarter of 2005, undiscounted abandonment costs for wells to be drilled in the future to develop proved reserves should be included in the unamortized cost of oil and gas properties, net of related salvage value, for purposes of computing depreciation, depletion and amortization ("DD&A"). The effect of including undiscounted abandonment costs of future wells to the undiscounted cost of oil and gas properties may increase DD&A expense in future periods, however, the Partnership currently does not believe SAB 106 will have a material impact on our financial statements.
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)
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
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 $73,903, a long term liability of approximately $164,052 and a loss of approximately $90,149 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, 2004, the asset retirement obligation was $187,858. The increase in the asset retirement obligation from January 1, 2004 is due to accretion expense of $10,475 and the addition of a well due to a farm- out arrangement for $14 less $602 for wells plugged and abandoned. The pro forma amount of the asset retirement obligation as of December 31, 2002 was approximately $164,052. 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 year ended December 31, 2002, which is presented below, reflect the effect of retroactive application of SFAS No. 143.
------ Pro forma amounts assuming change is applied retroactively: Net income before cumulative effect for change in depletion $ 245,506 method ====== Per limited partner unit $ 14.73 (15,000.0 units) ====== Net income $ 240,506 ====== Per limited partner unit $ 14.43 (15,000.0 units) ======
4. Cumulative effect of a change in accounting principle - change in depletion method 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 subsequent to 2001 has been calculated using the units-of-production method.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
5. 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, 2004, 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.
6. 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 $34,300, $34,500 and $36,100 for the years ended December 31, 2004, 2003 and 2002, 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 $108,000 during 2004, 2003 and 2002, 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 $144,300 and $90,600 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2004 and 2003, respectively.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Oil and Gas Reserves Information (unaudited)
The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under economic and operating conditions existing at the registrant's year end with no provision for price and cost escalations except by contractual arrangements. Future cash inflows were computed by applying year-end prices to the year-end quantities of proved reserves. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing, producing, and abandoning proved oil and gas reserves at the end of the year, based on year-end costs. All of the Partnership's reserves are located in the United States. For information about the Partnership's results of operations from oil and gas producing activities, see the accompanying statements of operations.
The Partnership's interest in proved oil and gas reserves is as follows:
Oil Gas (bbls) (mcf) -------- -------- ---- ---- Total Proved -
January 1, 2002 153,000 795,000
Revisions of previous 46,000 (84,000) estimates Production (19,000) (101,000 ) -------- -------- -- ---- December 31, 2002 180,000 610,000
Revisions of previous 84,000 400,000 estimates Production (18,000) (87,000) -------- -------- -- ---- December 31, 2003 246,000 923,000
New discoveries and extensions 8,000 312,000 Revisions of previous (2,000) 189,000 estimates Production (18,000) (80,000) -------- -------- -- ---- December 31, 2004 234,000 1,344,00 ====== =======
Proved developed reserves -
December 31, 2002 178,000 599,000 ====== ======= December 31, 2003 212,000 690,000 ====== ======= December 31, 2004 195,000 879,000 ====== =======
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Oil & Gas Reserves Information (unaudited) - continued 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 December 31, 2004, 2003 and 2002 are an average price of $40.55, $30.21 and $29.76 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 December 31, 2004, 2003 and 2002 are an average price of $5.39, $5.63 and $4.72 per Mcf.
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.
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
7. Oil & Gas Reserves Information (unaudited) - continued The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2004, 2003 and 2002 is presented below:
2004 2003 2002 ------ ------ ------
Future cash inflows $ 16,736,0 12,623,0 7,902,00 00 00 0 Production, development and abandonment costs 5,471,00 4,585,00 3,355,00 0 0 0 -------- -------- -------- ----- ------ ----- Future net cash flows 11,265,0 8,038,00 4,547,00 00 0 0 10% annual discount for estimated timing of cash flows 5,399,00 3,943,00 2,236,00 0 0 0 -------- -------- -------- ----- ------ ----- Standardized measure of discounted future net $ 5,866,00 4,095,00 2,311,00 cash flows 0 0 0 ======== ======== =======
Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2004, 2003 and 2002 are as follows:
2004 2003 2002 ------ ------ ------
Sales of oil and gas produced, net of production $ (795,000 (594,000 (412,000 costs ) ) ) Extensions and 991,000 - - discoveries Changes in prices and 917,000 548,000 1,133,00 production costs 0 Changes of production rates (timing) and others (127,000 55,000 (129,000 ) ) Revisions of previous quantities estimates 375,000 1,544,00 263,000 Accretion of discount 410,000 231,000 132,000 Discounted future net cash flows - Beginning of year 4,095,00 2,311,00 1,324,00 0 0 0 -------- -------- -------- ------ ------ ----- End of year $ 5,866,00 4,095,00 2,311,00 0 0 0 ======== ======== =======
Southwest Oil & Gas Income Fund VII-A, L.P. (a Delaware limited partnership)
Notes to Financial Statements
8. Selected Quarterly Financial Results - (unaudited)
Quarter -------------------------------------- -------------------------------------- - First Second Third Fourth ------ -------- ------- -------- --- - 2004: Total revenues $ 276,793 265,157 279,458 360,640 Total expenses 129,689 138,348 124,651 155,508 -------- -------- -------- -------- ---- ---- ---- ---- Net income $ 147,104 126,809 154,807 205,132 ======= ======= ======= =======
Net income per limited $8.83 7.61 9.29 12.30 partners unit ======= ======= ======= =======
Quarter -------------------------------------- -------------------------------------- - First Second Third Fourth ------ -------- ------- -------- --- - 2003: Total revenues $ 291,487 211,046 227,507 214,853 Total expenses 140,270 135,913 124,931 116,864 Net income before cumulative effect of a change in accounting 151,217 75,133 102,576 97,989 principle Cumulative effect of SFAS (90,149) - - - No. 143 -------- -------- -------- -------- ---- ---- ---- ---- Net income $ 61,068 75,133 102,576 97,989 ======= ======= ======= ======= Income before cumulative effect of a change in accounting $ 9.07 4.51 6.15 5.89 principle Cumulative effect of SFAS (5.41) - - - No. 143 -------- -------- -------- -------- ---- ---- ---- ---- Net income per limited $ 3.66 4.51 6.15 5.89 partners unit ======= ======= ======= =======
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
The Managing General Partner has established disclosure controls and procedures that are adequate to provide reasonable assurance that management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in the Partnership's reports to the SEC. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and is accumulated and communicated to management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.
With respect to these disclosure controls and procedures:
management has evaluated the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report;
this evaluation was conducted under the supervision and with the participation of management, including the chief executive and chief financial officers of the Managing General Partner; and
it is the conclusion of chief executive and chief financial officers of the Managing General Partner that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Partnership in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.
Internal Control Over Financial Reporting There has not been any change in the Partnership's internal control over financial reporting that occurred during the quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
Part III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Management of the Partnership is provided by Southwest Royalties, Inc., as Managing General Partner. Since the Managing General Partner is a wholly owned subsidiary of CWEI, the directors of the Managing General Partner are elected by management of CWEI. Each director the Managing General Partner serves for a term of one year. Following is certain information concerning each of the directors and executive officers of the Managing General Partner.
CLAYTON W. WILLIAMS, age 73, is Chairman of the Board and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Williams also serves as Chairman of the Board, President, Chief Executive Officer and a director of CWEI.
L. PAUL LATHAM, age 53, is President, Chief Executive Officer and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Latham also serves as Executive Vice President, Chief Operating Officer and a director of CWEI.
MEL G. RIGGS, age 50, is Vice President, Chief Financial Officer, Treasurer and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Riggs also serves as Senior Vice President and Chief Financial Officer of CWEI.
JERRY F. GRONER, age 42, is Vice President - Land and Lease Administration of the Managing General Partner, having served in this capacity since May 2004. Mr. Groner also serves as Vice President - Land and Lease Administration of CWEI.
D. GREGORY BENTON, age 43, is Vice President - Engineering of the Managing General Partner, having served in this capacity since May 2004. Mr. Benton also serves as Exploitation Manager of CWEI.
ROBERT C. LYON, age 68, is Vice President - Gas Gathering and Marketing of the Managing General Partner, having served in this capacity since May 2004. Mr. Lyon also serves as Vice President - Gas Gathering and Marketing of CWEI.
T. MARK TISDALE, age 48, is Vice President and Secretary of the Managing General Partner, having served in this capacity since May 2004. Mr. Tisdale also serves as Vice President and General Counsel of CWEI.
There are no family relationships among the directors and officers of the Managing General Partner except that Mr. Groner is the son-in-law of Mr. Williams.
Code of Ethics
As a wholly owned subsidiary of CWEI, the Managing General Partner is subject to a Code of Conduct and Ethics ("Code") that applies to all directors, executive officers and employees of CWEI and the Managing General Partner. This Code assists employees in complying with the law, in resolving ethical issues that may arise, and in complying with policies established by CWEI. This Code is also designed to promote, among other things, ethical handling of actual or apparent conflicts of interest; full, fair, accurate and timely disclosure in filings with the SEC; compliance with law; and prompt internal reporting of violations of the Code. This Code is available on the website of CWEI at www.claytonwilliams.com under "Investor Relations/Documents".
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 $108,000 during 2004, 2003 and 2002 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
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, other than the Managing General Partner.
Through repurchase offers to the limited partners, the Managing General Partner owns 5,501.67 limited partner units, a 33.0% limited partner interest. The Managing General Partner's total percentage interest ownership in the Partnership is 43.0%.
No officer or director of the Managing General Partner directly owns units in the Partnership. CWEI is considered to be a beneficial owner of the limited partner units acquired by the Managing General Partner by virtue of its ownership of the Managing General Partner. 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.
Item 13.
Item 13. Certain Relationships and Related Transactions
In 2004, the Managing General Partner received $108,000 as an administrative fee. This amount is part of the general and administrative expenses incurred by the Partnership.
In some instances, the Managing General Partner and its affiliates may be working interest owners in an oil and gas property in which the Partnership also has a net profits interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $34,300 for administrative overhead attributable to operating such properties during 2004.
The terms of the above transactions are similar to ones, which would have been obtained through arm's length negotiations with unaffiliated third parties.
Item 14.
Item 14. Principal Accounting 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, 2004 and 2002 and fees billed for other services rendered by KPMG during those periods.
For the Year Ended December 2004 2003 31, ------- ------ Audit Fees $12,865 $ 8,499 Audit Related Fees - - Tax Fees - - All Other Fees - - ------ ------ ----- ----- TOTAL $12,865 $ 8,499 ====== ======
The Audit Committee of CWEI reviewed and approved, in advance, all audit and non-audit services provided by KPMG LLP.
Part IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)(1) Financial Statements:
Included in Part II of this report --
Report of Independent Registered Public Accounting Firm 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 VII-A, L.P., dated January 28, 1987. (Incorpo rated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(b) Agreement of Limited Partnership of Southwest Oil & Gas Income Fund VII-A, L.P. dated April 28, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
(c) Certificate of Amendment of Limited Partnership of Southwest Oil & Gas Income Fund VII-A, L.P., dated July 21, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1987.)
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 and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 VII-A, L.P., a Delaware limited partnership
By: Southwest Royalties, Inc., Managing General Partner
By: /s/ L. Paul Latham L. Paul Latham President and Chief Executive Officer
Date: March 31, 2005
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/ Clayton W Williams /s/ L. Paul Latham Clayton W. Williams, L. Paul Latham, Chairman of the Board President and a Director and a Director
Date: March 31, 2005 Date: March 31, 2005
/s/ Mel G. Riggs Mel G. Riggs, Vice President - Finance, Treasurer and a Director
Date: March 31, 2005
SECTION 302 CERTIFICATION Exhibit 31.1
I, L. Paul Latham, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil & Gas Income Fund VII-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 15d-15(e)) 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)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
c)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 control 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 control over financial reporting.
Date: March 31, 2005 /s/ L. Paul Latham L. Paul Latham President and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VII-A, L.P.
SECTION 302 CERTIFICATION Exhibit 31.2
I, Mel G. Riggs, certify that:
1. I have reviewed this annual report on Form 10-K of Southwest Oil & Gas Income Fund VII-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 15d-15(e)) 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)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
c)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 control 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 control over financial reporting.
Date: March 31, 2005 /s/ Mel G. Riggs Mel G. Riggs Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VII-A, L.P.
Exhibit 32.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
Pursuant to 18 U.S.C. 1350 and in connection with the accompanying report on Form 10-K for the period ended December 31, 2004 that is being filed concurrently with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned officers of Southwest Oil & Gas Income Fund VII-A, L.P. (the "Company"), hereby certifies 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.
/s/ L. Paul Latham L. Paul Latham President and Chief Executive Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VII- A, L.P.
March 31, 2005
/s/ Mel G. Riggs Mel G. Riggs Vice President and Chief Financial Officer of Southwest Royalties, Inc., the Managing General Partner of Southwest Oil & Gas Income Fund VII- A, L.P.
March 31, 2005