UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, ~~2008~~2009

¨ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File Number 0-17707

Southwest Oil & Gas Income Fund VIII-A, L.P.

(Exact name of registrant as specified in

its limited partnership agreement)

Delaware		75-2220097
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

6 Desta Drive, Suite 6500, Midland, Texas		79705
(Address of principal executive office)		(Zip Code)

Registrant's telephone number, including area code (432) 682-6324

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

limited partnership interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.	¨ Yes	x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.	¨ Yes	x No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.	x Yes	¨ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).	¨ Yes	¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer x		Smaller reporting company¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

¨ Yes

x No

The registrant's outstanding securities consist of Units of limited partnership interests for which there exists no established public market from which to base a calculation of aggregate market value.

Table of Contents

		Page
Part I
Item 1.	Business	3

Item 1A.	Risk Factors	7

Item 1B.	Unresolved Staff Comments	8

Item 2.	Properties	9

Item 3.	Legal Proceedings	10

Item 4.	Submission of Matters to a Vote of Security Holders	10

Part II
Item 5.	Market for Registrant's Common Equity, Related
	Stockholder Matters and Issuer Purchases of Equity Securities	11

Item 6.	Selected Financial Data	12

Item 7.	Management's Discussion and Analysis of
	Financial Condition and Results of Operations	13

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	15

Item 8.	Financial Statements and Supplementary Data	16

Item 9.	Changes in and Disagreements with Accountants
	on Accounting and Financial Disclosure	29

Item 9A.	Controls and Procedures	29

Item 9B.	Other Information	30

Part III
Item 10.	Directors, Executive Officers and Corporate Governance	31

Item 11.	Executive Compensation	31

Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	32

Item 13.	Certain Relationships and Related Transactions, and Director Independence	32

Item 14.	Principal Accounting Fees and Services	32


Part IV
Item 15.	Exhibits and Financial Statement Schedules	33

Glossary of Oil and Gas Terms		34

Signatures		36

Part I

Item 1. Business

General

Southwest Oil & Gas Income Fund VIII-A, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on November 30, 1987. The offering of limited partnership interests began March 31, 1988, minimum capital requirements were met July 6, 1988 and the offering concluded March 31, 1989. The Partnership has no subsidiaries. The 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 Global 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 farm-out 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 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 farm-out agreement with the Partnership.

During 2008, the Partnership entered into farm-out agreements with the Managing General Partner through which the Managing General Partner drilled the Pattee #3, Pattee #4, and Paul Williams #4 wells. These wells are expected to be completed in 2009. The partnership retained a 10% interest in each of these wells and will pay none of the cost to drill and complete these wells.

Principal Products, Marketing and Distribution

The Partnership has acquired and holds working interests in oil and gas properties located in Texas. All activities of the Partnership are confined to the continental United States. During ~~2008~~2009, 9093% of the Partnership’s revenues were derived from the sale of oil production and 107% 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

Generally. 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. 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. Although the regulatory burden on the oil and gas industry increases the Partnership cost of doing business and, consequently, affects the Partnership’s profitability, these burdens generally do not affect the Partnership any differently or to any greater or lesser extent than they affect others in the Partnership’s industry with similar types, quantities and locations of production.

Regulations affecting production. All of the states in which the Partnership conducts business generally require permits for drilling operations, require 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, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas the Partnership can produce from its wells and may limit the number of wells or the locations at which the Partnership can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

In the event the Partnership conducts operations on federal, state or Indian oil and natural gas leases, its operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.

Regulations affecting sales. The sales prices of oil, natural gas liquids and natural gas are not presently regulated, but rather are set by the market. The Partnership cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

Under the Energy Policy Act of 2005, the Federal Energy Regulatory Commission (“FERC”) possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity.” The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to its physical purchases and sales of natural gas, natural gas liquids and crude oil, its gathering of these energy commodities, and any related hedging activities that the Partnership undertakes, the Partnership is required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should the Partnership violate the anti-market manipulation laws and regulations, the Partnership could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

The price the Partnership receives from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas the Partnership produces, as well as the revenues the Partnership receives for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. The Partnership does not believe that it will be affected by any such FERC action in a manner materially differently than other natural gas producers in its areas of operation.

Interstate transportation rates for oil, natural gas liquids and other products is also regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. 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 operations pertaining to oil and gas exploration, 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 the Partnership’s operations, restrict or prohibit the types, quantities and concentration of substances that the Partnership can release into the environment, restrict or prohibit 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 its operations. Such laws and regulations may substantially increase the cost of the Partnership’s operations 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 capital expenditures, earnings, or competitive position. Violation of these laws and regulations could result in significant fines or penalties. The Partnership has experienced accidental spills, leaks and other discharges of contaminants at some of its properties, as have other similarly situated oil and gas companies, and some of the properties that the Partnership has acquired, operated or sold, or in which the Partnership may hold an interest but not operational control, may have past or ongoing contamination for which the Partnership may be held responsible. The Partnership’s environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, the Partnership does not believe these costs would have a material adverse impact on the Partnership’s financial condition and operations.

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 ~~2009~~2010. The Partnership does not believe that it will be required to incur any material capital expenditures to comply with existing environmental requirements. 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, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have a material adverse impact on the Partnership’s operations.

Hazardous Substances. 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 Partnership is able to control directly the operation of only those wells with respect to which the Partnership acts as operator. Notwithstanding its lack of direct control over wells operated by others, 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 is not aware of any liabilities for which it may be held responsible that would materially and adversely affect the Partnership.

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies as solid wastes. 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 believe that its costs in this regard are materially more burdensome than those for similarly situated companies.

Air Emissions. The Federal Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Partnership obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions. The Partnership’s failure to comply with these requirements could subject the Partnership to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by the Partnership. The Partnership does not believe that its operations will be materially adversely affected by any such requirements.

Water Discharges. The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills. OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.

Global Warming and Climate Change. In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the current session of the U.S. Congress is considering adoption of climate change-related legislation that would restrict emissions of “greenhouse gases.” One bill recently approved by the Senate Committee on Environment and Public Works would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, at least 20 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In California, for example, the California Global Warming Solutions Act of 2006 requires the California Air Resources Board to adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.

Depending on the legislation or regulatory program that may be adopted to address emissions of greenhouse gases, the Partnership could be required to reduce greenhouse gas emissions resulting from its operations or the Partnership could be required to purchase and surrender allowances for greenhouse gas emissions associated with its operations or the oil and gas the Partnership produces. Although the Partnership would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on its cost of doing business and could reduce demand for the oil and gas the Partnership produces.

OSHA and Other Laws and Regulation. The Partnership is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that the Partnership organize and/or disclose information about hazardous materials used or produced in its operations. The Partnership believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of 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 1A. Risk Factors

There are many factors that affect the Partnership’s business, some of which are beyond the Partnership’s control. The Partnership’s business, financial condition and results of operations could be materially adversely affected by any of these risks. The risks described below are not the only ones facing the Partnership. Additional risks not presently known to the Partnership or that the Partnership currently deems immaterial individually or in the aggregate may also impair the Partnership’s business operations.

The Partnership’s oil and gas reserves will decline as they are produced.

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. The implied life of the Partnership’s proved reserves at December 31, ~~2008~~2009 is approximately 109.28 years, based on ~~2008~~2009 production levels.

Volatility of oil and gas prices significantly affects the Partnership’s cash flow and ability to produce oil and gas economically.

Historically, the markets for oil and gas have been volatile, and the Partnership believes that they are likely to continue to be volatile. Significant changes in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond the Partnership’s control. The Partnership cannot predict, with any degree of certainty, future oil and natural gas prices. Changes in oil and natural gas prices significantly affect the Partnership’s revenues, operating results, profitability and the value of the Partnership’s oil and gas reserves. Those prices also affect the amount of cash flow available for distribution to partners and the amount of oil and natural gas that the Partnership can produce economically.

Changes in oil and gas prices impact both the Partnership’s estimated future net revenue and the estimated quantity of proved reserves. Price increases may permit additional quantities of reserves to be produced economically, and price decreases may render uneconomic the production of reserves previously classified as proved. Thus, the Partnership may experience material increases and decreases in reserve quantities solely as a result of price changes and not as a result of well performance.

Information concerning the Partnership’s reserves and future net revenues estimates is inherently uncertain.

The estimated proved reserve information is based upon reserve reports prepared by independent engineers. The accuracy of proved reserves estimates and estimated future net revenues from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although the Partnership believes that the Partnership’s estimated proved reserves represent reserves that the Partnership is reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of the Partnership’s oil and gas reserves, which in turn could adversely affect the Partnership’s cash flow and results of operations. In addition, the Partnership may adjust estimates of proved reserves to reflect production history, results of development, prevailing oil and gas prices and other factors, many of which are beyond the Partnership’s control. Downward adjustments to the Partnership’s estimated proved reserves could require the Partnership to write down the carrying value of the Partnership’s oil and gas properties, which would reduce the Partnership’s earnings and partners' equity.

The present value of proved reserves will not necessarily equal the current fair market value of the Partnership’s estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

The Partnership may not be insured against all of the operating hazards to which the Partnership’s business is exposed.

The Partnership’s operations are subject to the usual hazards incident to the production of oil and gas, such as windstorms, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial loss. The Partnership maintains insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, the Partnership cannot be assured of the continued availability of insurance at premium levels that justify its purchase.

The Partnership’s business depends on oil and natural gas transportation facilities, most of which are owned by others.

The marketability of the Partnership’s oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells. Although the Partnership has some contractual control over the transportation of the Partnership’s product, material changes in these business relationships could materially affect the Partnership’s operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect the Partnership’s ability to produce, gather and transport oil and natural gas.

The Partnership’s industry is highly competitive.

The oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect the Partnership’s revenue.

The market for the Partnership’s oil, gas and natural gas liquids production depends on factors beyond the Partnership’s control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

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 operates generally require reports concerning operations and impose other requirements relating to the 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.

FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas the Partnership produces, 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 the Partnership’s gas, although it may also subject the Partnership to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

The Partnership’s sales of oil and natural gas liquids 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.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

As of December 31, ~~2008~~2009, the Partnership possessed an interest in oil and gas properties located in Glasscock, Pecos, Stonewall, Ward, Winkler and Yoakum Counties of Texas. These properties consist of various interests in approximately 82 wells and units.

Reserves

~~The following~~Rule ~~table~~Changes ~~sets~~Applicable ~~forth certain information as of December 31, 2008 with respect~~ to ~~the~~Reserve ~~Partnership’s~~Estimates ~~estimated proved oil~~ and ~~gas reserves pursuant to SEC guidelines and standardized measure of discounted future net cash flows~~Disclosures.

	Proved Developed				Proved		Total
	Producing		Nonproducing		Undeveloped		Proved
Oil (Bbls)		402,000		2,000		3,000		407,000
Gas (Mcf)		319,000		4,000		3,000		326,000
Total (BOE)		455,000		3,000		4,000		462,000
Standardized measure of discounted
future net cash flows							$	4,174,000

In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the Financial Accounting Standards Board (“FASB”) adopted conforming changes to Accounting Standards Codification (“ASC”) Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC. The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009. As it affects the Partnership's reserve estimates and disclosures, the final rule:

~~The following~~· ~~table~~amends ~~sets~~the ~~forth~~definition ~~certain~~of ~~information~~proved asreserves to require the use of ~~December~~average ~~31,~~commodity ~~2008~~prices ~~regarding the~~based ~~Partnership’s~~upon ~~proved~~the ~~oil~~prior ~~and~~12 ~~gas~~month ~~reserves~~period ~~for~~rather ~~certain~~than ~~significant fields.~~year-end prices;

	Proved Reserves
					Total Oil		Percent of
	Oil		Gas		Equivalent		Total Oil
	(Bbls)		(Mcf)		(BOE)		Equivalent
Block D		194,000		-		194,000		42.0	%
Hendrick		98,000		25,000		102,000		22.1	%
Collie		44,000		102,000		61,000		13.2	%
Scott		47,000		95,000		63,000		13.6	%
Other		24,000		104,000		42,000		9.1	%
Total		407,000		326,000		462,000		100.0	%

·	expands the type of technologies available to establish reserve estimates and categories;

~~The estimates~~· ofmodifies ~~proved~~certain ~~reserves~~definitions atused December 31, 2008 and the standardized measure of discounted future net cash flows 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~~estimating ~~with~~proved ~~SEC financial accounting and reporting standards.~~reserves;

~~In accordance~~· ~~with~~permits ~~applicable~~disclosure ~~financial accounting and reporting standards~~ of ~~the SEC,~~probable ~~the estimates of the Partnership’s proved reserves~~ and ~~the~~possible standardized measure of discounted future net cash flows 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 standardized measure of discounted future net cash flows as of December 31, 2008 were $42.85 per Bbl of oil and natural gas liquids and $6.84 per Mcf of gas, as compared to $91.81 per Bbl of oil and $7.83 per Mcf of gas as of December 31, 2007.

·	permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts.

See “Glossary of Terms” for current definitions of terms related to oil and gas reserves.

The following table sets forth certain information as of December 31, 2009 with respect to the Partnership’s estimated proved oil and gas reserves pursuant to SEC guidelines and standardized measure of discounted future net cash flows.

	Proved Developed				Proved		Total
	Producing		Nonproducing		Undeveloped		Proved
Oil (Bbls)		365,000		8,000		2,000		375,000
Gas (Mcf)		203,000		17,000		3,000		223,000
Total (BOE)		399,000		11,000		3,000		413,000

Standardized measure of discounted
future net cash flows							$	4,449,000

The following table sets forth certain information as of December 31, 2009 regarding the Partnership’s proved oil and gas reserves for certain significant fields.

	Proved Reserves
					Total Oil		Percent of
	Oil		Gas		Equivalent		Total Oil
	(Bbls)		(Mcf)		(BOE)		Equivalent
Block D		219,000		-		219,000		53.0	%
Collie		55,000		70,000		67,000		16.2	%
Scott		57,000		105,000		75,000		18.2	%
Other		44,000		48,000		52,000		12.6	%
Total		375,000		223,000		413,000		100.0	%

The estimates of proved reserves at December 31, 2009 and the standardized measure of discounted future net cash flows 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 commodity prices used to estimate proved reserves and their related PV-10 Value at December 31, 2009 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2009 through December 2009. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $55.61 per barrel of oil and $3.58 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.

~~The reserve~~Other ~~information~~Information ~~shown~~Concerning isour ~~estimated. The~~Proved 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 standardized measure 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 the Partnership’s business or the oil and natural gas industry in general are subject.Reserves

~~Unanticipated depletion,~~The ifaccuracy itof ~~occurs,~~any ~~will~~reserve ~~result~~estimate inis ~~lower~~a ~~reserves~~function ~~than~~of ~~previously estimated; thus an ultimately lower return for~~ the ~~Partnership. Basic changes~~quality inof ~~past~~available ~~reserve~~geological, ~~estimates~~geophysical, ~~occur~~engineering ~~annually. As~~and ~~new~~economic data, ~~is gathered during~~ the ~~subsequent~~precision ~~year,~~of the ~~engineer~~engineering ~~must~~and ~~revise~~geological ~~his~~interpretation ~~earlier estimates~~and judgment. AThe ~~year~~estimates of ~~new information~~reserves, ~~which~~future iscash ~~pertinent~~flows toand ~~the estimation~~PV-10 ofValue ~~future~~are ~~recoverable~~based ~~volumes,~~on isvarious ~~available~~assumptions ~~during~~and ~~the~~are ~~subsequent year~~inherently ~~evaluation~~imprecise. InAlthough ~~applying~~we ~~industry~~believe ~~standards~~these ~~and~~estimates ~~procedures~~are reasonable, ~~the new~~actual ~~data~~future ~~may~~production, ~~cause~~cash ~~the~~flows, ~~previous~~taxes, ~~estimates~~development toexpenditures, beoperating ~~revised. This revision~~expenses ~~may~~and ~~increase~~quantities orof ~~decrease~~recoverable ~~the~~oil ~~earlier~~and ~~estimated volumes. Pertinent~~natural ~~information~~gas ~~gathered~~reserves ~~during the year~~ may ~~include actual~~vary ~~production~~substantially ~~and~~from ~~decline~~these ~~rates~~estimates. Also, ~~production~~the ~~from~~use ~~offset~~of ~~wells~~a ~~drilled~~10% todiscount ~~the same~~factor ~~geologic~~for ~~formation,~~reporting ~~increased~~purposes ormay ~~decreased~~not ~~water~~necessarily ~~production,~~represent ~~workovers,~~the ~~and changes~~most inappropriate ~~lifting~~discount ~~costs~~factor, ~~among~~given ~~others. Accordingly,~~actual ~~reserve estimates~~interest ~~are~~rates ~~often~~and ~~different~~risks ~~from~~to ~~the~~which ~~quantities~~our ofbusiness or the oil and natural gas ~~that~~industry in general are ~~ultimately~~ ~~recovered~~subject.

Since January 1, 2009, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

Item 3. Legal Proceedings

There are no material pending legal proceedings to which the Partnership is a party.

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 ~~2008~~ 2009 through the solicitation of proxies or otherwise.

Part II

Item 5.

Market for 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, ~~2008~~2009, there were ~~422~~417 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 ~~2008~~2009, distributions were made totaling $2580,~~870,~~000, with $2522,~~583,~~000 ($~~189~~38.9839 per unit) distributed to the limited partners and $~~287~~58,000 to the general partner.

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 ended December 31, ~~2008~~2009.

	Total Number
	of Units		Average Price
Period	Purchased		Paid Per Unit
January 2008		-	$	-
January 2009		-	$	-
February 2008		-		-
February 2009		-		-
March 2008		-		-
March 2009		-		-
April 2008		-		-
April 2009		-		-
May 2008		-		-
May 2009		-		-
June 2008		221.3		826.93
June 2009		124.0		238.94
July 2008		-		-
July 2009		-		-
August 2008		-		-
August 2009		-		-
September 2008		20.0		797.11
September 2009		-		-
October 2008		-		-
October 2009		-		-
November 2008		-		-
November 2009		-		-
December 2008		-		-
December 2009		6.0		224.49
TOTALS		~~241~~130.30	$	~~824~~238.4627

Item 6. Selected Financial Data

The following selected financial data for the years ended December 31, 2009, 2008, 2007, 2006, ~~2005~~ and ~~2004~~2005 should be read in conjunction with the financial statements included in Item 8:

Years ended December 31,

2008

2007

2006

2005

2004

2009

2008

2007

2006

2005

Revenues

42,~~181~~213,~~145~~790

24,~~963~~181,~~475~~145

2,~~761~~963,~~552~~475

2,~~355~~761,~~901~~552

12,~~832~~355,~~578~~901

Net income

2736,~~494,176~~301

12,~~707~~494,~~720~~176

1,~~605~~707,~~829~~720

1,~~411~~605,~~417~~829

~~984~~1,~~197~~411,417

Partners' share of net income :

General partner

~~252~~77,~~125~~429

~~173~~252,~~545~~125

~~162~~173,~~196~~545

~~142~~162,~~295~~196

99142,~~580~~295

Limited partners

2658,~~242,051~~872

12,~~534~~242,~~175~~051

1,~~443~~534,~~633~~175

1,~~269~~443,~~122~~633

~~884~~1,~~617~~269,122

Limited partners' net income per unit

~~164~~48.9146

~~112~~164.8491

~~106~~112.1884

93106.3518

6593.0635

Limited partners' cash

distributions per unit

~~189~~38.9839

~~109~~189.2298

~~114~~109.1922

89114.3319

5689.2733

Total assets

~~648~~844,~~997~~683

1648,~~069,131~~997

~~897~~1,~~695~~069,131

~~816~~897,~~173~~695

~~674~~816,~~805~~173

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~~the net proceeds from operations to the ~~general~~limited and ~~limited~~ general partners. Net revenues from producing oil and gas properties are not reinvested in other revenue producing assets except to the extent that ~~producing~~ production facilities and wells are improved or 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~~increases ~~operating~~and ~~expenses~~decreases in production costs, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements, sales of properties, and on the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.

~~Well operating~~Production costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately to production volumes or revenues. Net income available for distribution to the ~~limited~~ partners is therefore 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~~Current ~~ceiling calculation~~SEC ~~dictates~~financial accounting and reporting standards require that ~~prices~~pricing ~~and~~parameters ~~costs~~be inthe ~~effect~~arithmetic asaverage of the ~~last~~ first-day -of-the-month price for the ~~period~~ ~~are~~12-month ~~generally~~period ~~held~~preceding ~~constant~~the ~~indefinitely.~~effective ~~Because~~date of the reserve report. The ceiling calculation dictates that those prices inbe ~~effect~~held asconstant. ofBecause the ~~last~~ceiling ~~day~~calculation ofdictates ~~the~~that ~~applicable~~prices ~~quarter~~and costs 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.

Supplemental Information

The following unaudited information is intended to supplement the financial statements included in this Form 10-K with data that is not readily available from those statements.

	Year Ended December 31,
	2008		2007		2006
	2009		2008		2007
Oil production in barrels		3835,~~210~~869		3738,~~663~~210		37,~~825~~663
Gas production in mcf		4336,~~192~~476		4243,~~507~~192		42,~~071~~507
Total (BOE)		4541,~~409~~948		4445,~~748~~409		44,~~837~~748
Average price per barrel of oil	$	9857.7017	$	6998.4870	$	6169.5248
Average price per mcf of gas	$	94.4447	$	89.0344	$	78.2703
Partnership distributions	$	2580,~~870,~~000	$	12,~~650~~870,000	$	1,~~725~~650,000
Limited partner distributions	$	2522,~~583,~~000	$	12,~~485~~583,000	$	1,~~552~~485,~~500~~000
Per unit distribution to limited partners	$	~~189~~38.9839	$	~~109~~189.2298	$	~~114~~109.1922
Number of limited partner units		13,596		13,596		13,596

Operating Results

The following discussion compares our results for the year ended December 31, ~~2008~~ 2009 to the two previous years. All references to ~~2008~~2009, ~~2007~~2008 and ~~2006~~ 2007 within this section refer to the respective annual periods.

Revenues

Oil and gas prices ~~remained~~declined ~~high~~ compared to the previous two years. Comparing ~~2008~~2009 to ~~2007~~2008, oil and gas sales ~~increased~~ decreased $1,~~220~~965,~~672~~253, of which price variances accounted for a $1,~~177~~670,~~167~~823 ~~increase~~decrease and production variances accounted for a $43294,~~505~~430 ~~increase~~decrease. Comparing ~~2007~~ 2008 to ~~2006~~2007, oil and gas sales increased $~~325~~1,~~258~~220,672, of which price variances accounted for a $~~332~~1,~~055~~177,167 increase and production variances accounted for a $643,~~797~~505 ~~decrease~~increase.

Production in ~~2008~~2009 (on a BOE basis) was 18% ~~higher~~lower than ~~2007~~2008 and 16% ~~higher~~lower than ~~2006~~ 2007. Our oil production was 16% ~~higher~~lower in ~~2008~~2009 than ~~2007~~2008. ~~and~~Our ~~our~~ gas production was 216% ~~higher~~lower in ~~2008~~2009 than ~~2007~~2008 due primarily to production decline on one property.

In ~~2008~~2009, our realized oil price was 42% ~~higher~~lower than ~~2007~~2008 and 6018% ~~higher~~lower than ~~2006~~2007, while our realized gas price was 1853% ~~higher~~lower than ~~2007~~2008 and 3044% ~~higher~~lower than ~~2006~~ 2007. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. ~~We have very little control over the prices we receive for our production at the wellhead since most of our physical marketing arrangements are market-sensitive.~~

Expenses

Oil and gas production costs on a BOE basis ~~increased~~decreased from $2332.4683 per BOE in ~~2007~~2008 and increased from $2223.0646 per BOE in ~~2006~~2007 to $3230.8304 per BOE in ~~2008~~2009. The ~~increase~~higher in oil and gas production costs in 2008 ~~was~~were due primarily to ~~increases~~repairs ~~in operating and repair costs~~ on ~~three~~two injection wells ~~and seven oil wells~~. Also contributing to the ~~increase~~decrease ~~was~~were ~~higher~~lower production taxes resulting from ~~the higher~~lower commodity prices.

Depletion on a BOE basis ~~decreased~~increased 452% from ~~2007~~2008 and increased 6746% from ~~2006~~ 2007. Comparing ~~2008~~2009 to ~~2007~~2008, depletion expense ~~decreased~~increased $~~653~~10,918, of which rate variances accounted for a $112,~~063~~981 ~~decrease~~increase and production variances accounted for a $~~410~~2,063 ~~increase~~decrease. Comparing ~~2007~~2008 to ~~2006~~2007, depletion expense ~~increased~~decreased $11653,~~593,~~ of which rate variances accounted for a $111,~~625 increase~~063 decrease and production variances accounted for a $~~32 decrease~~410 increase. Depletion rates are a function of net capitalized costs and estimated reserve quantities.

Accretion expense ~~decreased~~increased 1921% due primarily to changes in asset retirement obligations.

General and administrative (“G&A”) expenses were 1% higher than ~~2007~~2008 and 32% higher than ~~2006~~2007.

Texas Margin Taxes

In May 2006, the State of Texas adopted House Bill 3, which modified the state’s franchise tax structure, replacing the previous tax based on capital or earned surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax reports filed on or after January 1, 2008. The Texas margin Tax is computed by applying the applicable tax rate (1% for the Partnership’s business) to the profit margin, which is generally determined by total revenue less either cost of goods sold or compensation as applicable. Although House Bill 3 states that the Texas Margin Tax is not an income tax, the Partnership believes that Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”) applies to the Texas Margin Tax. However the Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership because it qualifies under the passive entity exclusion.

Other Income

Southwest Royalties Inc. formed a redevelopment plan for the NR Colby B water flood in 1997. The development included drilling 5 additional wells, converting 7 wells to injection, drilling 2 water supply wells, workover of 4 producers, and upgrading injection and production facilities at an estimated cost of $1,547,500. An outside consultant advised that a fair farm out arrangement would be for SWRI to pay all the costs of the development in return for 90% of the limited partnerships’ interest in the property. The project started in December 1997 with the ownership change effective January 1, 1998. Upon seeing a precipitous decline in oil prices in 1998 the project was cancelled after converting two wells to injection and performing a workover on one well. To satisfy the inequity that resulted from the assignment of the full 90% interest without performing all the planned development activities, SWRI assigned the 90% earned interest back to the partnership effective January 1, 2007 and paid $121,364 to the partnership for the difference between the amount paid and the pre-farm-out decimal amount for years 1998 through 2006 less the development cost incurred plus interest.

Liquidity and Capital Resources

Partnership distributions during the year ended December 31, ~~2008~~2009 were $2580,~~870,~~000, of which $2522,~~583,~~000 was distributed to the limited partners and $~~287~~58,000 to the general partner. Cumulative cash distributions of $1718,~~684~~264,097 have been made to the general and limited partners as of December 31, ~~2008~~2009. As of December 31, ~~2008~~2009, $1516,~~963~~485,929 or $1,~~174~~212.1656 per limited partner unit has been distributed to the limited partners, representing ~~235~~243% of contributed capital.

Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Cash flow provided by operating activities for ~~2008~~ 2009 was 6980% ~~higher~~lower than ~~2007~~2008 due to the combined effects of several drivers. The ~~positive~~effect ~~benefits~~ of a 4147% ~~increase~~decrease in oil and gas sales, driven primarily by ~~higher~~lower oil prices, and the ~~decrease~~increase in accounts receivables were offset in part by ~~increases~~decreases in production costs. Our only use in financing activities is the distribution to partners which was 7480% ~~higher~~ lower than ~~2007~~2008.

As of December 31, ~~2008~~2009, the Partnership had approximately $60255,~~200~~800 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 have 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

~~There~~Effective ~~are no~~July ~~recent~~1, 2009, the Partnership adopted SFAS No. 168, “The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards Codification (“ASC”). SFAS 168 establishes the ASC as the source of authoritative accounting ~~pronouncements~~principles ~~that~~recognized ~~affect~~by the ~~Partnership~~FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Other than the manner in which new accounting guidance is referenced, the adoption did not have a material impact on our financial statements.

Effective April 1, 2009, the Partnership adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”) (superseded by ASC topic 855-10-5), which establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of SFAS 165 did not have a material impact on our disclosure of subsequent events.

In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. All of these rule changes became effective December 31, 2009. We have adopted these changes and conformed our reserve estimation and disclosure practices in accordance with the guidance contained in the releases.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Partnership financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, trading activities in commodities future markets, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. The Partnership cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our financial condition, results of operations and cash distributions to partners.

The Partnership is not a party to any derivative or embedded derivative instruments.

Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

		Page
Report of Independent Registered Public Accounting Firm		17

Balance Sheets		18

Statements of Operations		19

Statements of Changes in Partners' Equity (Deficit)		20

Statements of Cash Flows		21

Notes to Financial Statements		22

REPORT OF INDEPENDENT REGISTERED

PUBLIC ~~ACCOUNTING~~ ACCOUNINTG FIRM

The Partners

Southwest Oil &and Gas Income Fund VIII-A, L.P.

(A Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Oil &and Gas Income Fund VIII-A, L.P. (the “Partnership”) as of December 31, ~~2008~~2009 and ~~2007~~2008, and the related statements of operations, changes in ~~partners~~partner’s equity (deficit), and cash flows for each of the years in the three-year period ended December 31, ~~2008~~ 2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing 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. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 &and Gas Income Fund VIII-A, L.P. as of December 31, ~~2008~~2009 and ~~2007~~2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, ~~2008,~~2009 in conformity with U.S. generally accepted accounting principles.

KPMG LLP

Dallas, Texas

March 2729, ~~2009~~ 2010

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Balance Sheets

	December 31,
	2008			2007
	2009			2008
Assets
Current assets:
Cash and cash equivalents	$	~~105~~90,~~984~~333		$	~~112~~105,~~867~~984
Receivable from Managing General Partner		-165,430			~~345,275~~-
Total current assets		~~105~~255,~~984~~763			~~458~~105,~~142~~984
Oil and gas properties - using the full-
cost method of accounting		5,~~692~~776,~~292~~190			5,~~733~~692,~~195~~292
Less accumulated depreciation,
depletion and amortization		5,~~149~~187,~~279~~270			5,~~122~~149,~~206~~279
Net oil and gas properties		~~543~~588,~~013~~920			~~610~~543,~~989~~013
	$	~~648~~844,~~997~~683		$	1648,~~069,131~~997
Liabilities and Partners' Equity (Deficit)
Current liability:
Payable to Managing General Partner	$	~~45,747~~-		$	-45,747
Asset retirement obligation		~~574~~659,~~148~~280			~~664~~574,~~205~~148
Partners' equity (deficit):
General partner		~~(15~~4,~~311~~118	)		19(15,~~564~~311	)
Limited partners		44181,~~413~~285			~~385~~44,~~362~~413
Total partners' equity		29185,~~102~~403			~~404~~29,~~926~~102
	$	~~648~~844,~~997~~683		$	1648,~~069,131~~997

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Statements of Operations

	Years ended December 31,
	2008		2007		2006
	2009		2008		2007
Revenues
Oil and gas revenue	$	42,~~178~~213,~~787~~534	$	24,~~958~~178,~~115~~787	$	2,~~632~~958,~~857~~115
Interest income		~~2,358~~256		52,~~360~~358		75,~~331~~360
Other		-		-		121,364
		2,213,790		4,181,145		2,963,475
		4,181,145		2,963,475		2,761,552
Expenses
Production		1,~~490~~260,~~609~~045		1,~~049~~490,~~891~~609		~~989~~1,~~235~~049,891
Depreciation, depletion and amortization		2737,~~073~~991		27,~~726~~073		1627,~~133~~726
Accretion expense		4454,~~825~~078		5544,~~111~~825		3055,~~032~~111
General and administrative		~~124~~125,~~462~~375		~~123~~124,~~027~~462		~~120~~123,~~323~~027
		1,686,969		1,255,755		1,155,723
		1,477,489		1,686,969		1,255,755
Net income	$	2736,~~494,176~~301	$	12,~~707~~494,~~720~~176	$	1,~~605~~707,~~829~~720
Net income allocated to:
Managing General Partner	$	~~252~~77,~~125~~429	$	~~173~~252,~~545~~125	$	~~162~~173,~~196~~545
Limited partners	$	2658,~~242,051~~872	$	12,~~534~~242,~~175~~051	$	1,~~443~~534,~~633~~175
Per limited partner unit	$	~~164~~48.9146	$	~~112~~164.8491	$	~~106~~112.1884

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Statements of Changes in Partners' Equity (Deficit)

Years ended December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007

	General			Limited
	Partner			Partners			Total
Balance at December 31, 2005	$	21,323		$	445,054		$	466,377
Balance at December 31, 2006	$	11,019		$	336,187		$	347,206
Net income		162,196			1,443,633			1,605,829
Distributions		(172,500	)		(1,552,500	)		(1,725,000	)
Balance at December 31, 2006		11,019			336,187			347,206
Net income		173,545			1,534,175			1,707,720
Distributions		(165,000	)		(1,485,000	)		(1,650,000	)
Balance at December 31, 2007		19,564			385,362			404,926
Net income		252,125			2,242,051			2,494,176
Distributions		(287,000	)		(2,583,000	)		(2,870,000	)
Balance at December 31, 2008	$	(15,311	)	$	44,413		$	29,102
Net income		77,429			658,872			736,301
Distributions		(58,000	)		(522,000	)		(580,000	)
Balance at December 31, 2009	$	4,118		$	181,285		$	185,403

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Statements of Cash Flows

	Years ended December 31,
	2008			2007			2006
	2009			2008			2007
Cash flows from operating activities:
Cash received from oil and gas sales	$	42,~~524~~048,~~062~~104		$	24,~~795~~524,~~172~~062		$	2,~~666~~795,~~701~~172
Cash paid for production expense, administrative
fees and general and administrative overhead		(1,~~571~~449,~~568~~961	)		(1,~~172~~571,~~980~~568	)		(1,~~113~~172,~~684~~980	)
Interest received		~~2,358~~256			52,~~360~~358			75,~~331~~360
Miscellaneous settlement		-			~~121,364~~-			-121,364
Net cash provided by operating activities		2598,~~954,852~~399			12,~~748~~954,~~916~~852			1,~~560~~748,~~348~~916
Cash flows used in investing activities:
Additions to oil and gas properties		(9134,~~735~~050	)		(7191,~~809~~735	)		(671,~~505~~809	)
Cash flows used in financing activities:
Distributions to partners		(2580,~~870,~~000	)		(12,~~650~~870,000	)		(1,~~725~~650,000	)
Decrease in distribution payable		-			-			(119	)
Net (decrease) increase in cash and cash equivalents		(15,651	)		(6,883	)		27,107
Net cash used in financial activities		(2,870,000	)		(1,650,000	)		(1,725,119	)
Beginning of year		105,984			112,867			85,760
Net (decrease) increase in cash and cash equivalents		(6,883	)		27,107			(171,276	)
End of year	$	90,333		$	105,984		$	112,867
Beginning of year		112,867			85,760			257,036
End of year	$	105,984		$	112,867		$	85,760
Reconciliation of net income to net
cash provided by operating activities:
Net income	$	2736,~~494,176~~301		$	12,~~707~~494,~~720~~176		$	1,~~605~~707,~~829~~720
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization		2737,~~073~~991			27,~~726~~073			1627,~~133~~726
Accretion expense		4454,~~825~~078			5544,~~111~~825			3055,~~032~~111
Settlement of asset retirement obligations
for plugged and abandoned wells		(218,~~244~~794	)		(622,244	)		(~~4,126~~62	)
Decrease (increase) in receivables		345,275			(41,579	)		(87,520	)
(Increase) decrease in receivables		(165,430	)		345,275			(41,579	)
Increase in payables		45,747			-			-
(Decrease) increase in payables		(45,747	)		45,747			-
Net cash provided by operating activities	$	2598,~~954,852~~399		$	12,~~748~~954,~~916~~852		$	1,~~560~~748,~~348~~916
Noncash investing and financing activities:
(Decrease) increase in oil and gas properties –
Increase (decrease) in oil and gas properties –
SFAS No. 143	$	(132,638	)	$	58,667		$	174,906
Asset retirement obligations	$	49,848		$	(132,638	)	$	58,667

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

1.	Organization

Southwest Oil & Gas Income Fund VIII-A, L.P. was organized under the laws of the state of Delaware on November 30, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc., 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 contributions	100%	-
Oil and gas sales	90%	10%
All other revenues	90%	10%
Organization and offering costs (1)	100%	-
Amortization of organization costs	100%	-
Syndication costs	100%	-
Property acquisition costs	100%	-
Gain/loss on property disposition	90%	10%
Operating and administrative costs (2)	90%	10%
Depreciation, depletion and amortization
of oil and gas properties	100%	-
All other costs	90%	10%

(1)

All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

(2)

Administrative costs in any year, which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.	Summary of Significant Accounting Policies

Oil and Gas Properties

The Partnership uses the full cost method of accounting for its oil and gas producing activities. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves are capitalized. Depletion is provided using the unit-of production method based upon estimates of proved oil and gas reserves. The amortizable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage value. All of the Partnership’s oil and gas properties are located within the United States. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are sold.

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, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007 the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

Southwest Oil & Gas Income Fund VIII-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

The Partnership recognizes 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, ~~2008~~2009 and ~~2007~~2008, there were no significant amounts of imbalance in terms of units or value.

Income Taxes

No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.

In accordance with the requirements of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes, the Partnership's tax basis in its net oil and gas properties at December 31, 2008 and 2007 is $448,425 and $487,645, respectively, less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.

Number of Limited Partner Units

As of December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007, there were 13,596 limited partner units outstanding held by ~~422~~417, ~~441~~422 and ~~450~~441 partners.

Concentrations of Credit Risk

The Partnership is subject to credit risk for amounts due from its customers. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the Partnership.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

2.	Summary of Significant Accounting Policies - continued

Concentrations of Credit Risk

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 per limited partnership unit

The net income per limited partnership unit is calculated by using the number of outstanding limited partnership units.

Recent Accounting Pronouncements

3. Abandonment Obligations

The Partnership follows the provisions of ~~Statement~~ASC oftopic ~~Financial~~410-20, ~~Accounting Standards~~formerly SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”)~~, as amended~~. ~~SFAS~~ASC ~~143~~topic 410-20 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 capitalize an equal amount as a cost of the asset. The cost associated with the abandonment obligations, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

~~Changes in~~Our asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment ~~obligations~~and ~~for~~remediation ~~2008~~costs, inflation rate and ~~2007~~well life. The inputs are calculated based on historical data as ~~follows:~~well as current estimated costs.

	2008			2007
Beginning of year	$	664,205		$	550,489
Additional abandonment obligations from new wells		3,779			58,667
Reduction of obligations due to wells plugged and abandoned		(2,244	)		(62	)
Accretion expense		44,825			55,111
Revisions of previous estimates		(136,417	)		-
End of year	$	574,148		$	664,205

Changes in abandonment obligations for 2009 and 2008 are as follows:

	2009			2008
Beginning of year	$	574,148		$	664,205
Additional abandonment obligations from new wells		440			3,779
Reduction of obligations due to wells plugged and abandoned		(18,794	)		(2,244	)
Accretion expense		54,078			44,825
Revisions of previous estimates		49,408			(136,417	)
End of year	$	659,280		$	574,148

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

4.	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, ~~2008~~2009, 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 the Partnership’s financial condition and operations. 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 the Partnership's properties.

5.	Related Party Transactions

A significant portion of the oil and gas properties in which the Partnership has an interest are purchased from and operated by 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 payable to Southwest Royalties, Inc. as operator approximating $~~146~~175,~~300~~400, $~~135~~146,~~800~~300 and $135,~~900~~800 for the years ended December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007 respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Southwest Royalties, Inc., the Managing General Partner, was paid $98,400 during each of ~~2008~~ 2009, ~~2007~~2008 and ~~2006~~2007 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 (payable to) ~~from~~ Southwest Royalties, Inc., the Managing General Partner, of approximately $165,400 and ($45,700) ~~and $345,300~~ are from oil and gas production, net of lease operating costs and production taxes, as of December 31, ~~2008~~2009 and ~~2007~~2008, respectively.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

6.	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.

In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the Financial Accounting Standards Board (“FASB”) adopted conforming changes to Accounting Standards Codification (“ASC”) Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC. The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009. As it affects the Partnership’s reserve estimates and disclosures, the final rule:

·	amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices;

·	expands the type of technologies available to establish reserve estimates and categories;

·	modifies certain definitions used in estimating proved reserves;

·	permits disclosure of probable and possible reserves; and

·	permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts.

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

The Partnership's interest in proved oil and gas reserves is as follows:

	Oil (bbls)			Gas (mcf)
Total Proved -
January 1, 2006		569,000			428,000
January 1, 2007		479,000			371,000
Revisions of previous estimates		(52,000	)		(15,000	)
Production from continuing operations		(38,000	)		(42,000	)
December 31, 2006		479,000			371,000
Revisions of previous estimates		197,000			73,000
Production from continuing operations		(38,000	)		(43,000	)
December 31, 2007		638,000			401,000
New discoveries and extensions		2,000			4,000
Revisions of previous estimates		(195,000	)		(36,000	)
Production from continuing operations		(38,000	)		(43,000	)
December 31, 2008		407,000			326,000
Revisions of previous estimates		4,000			(67,000	)
Production from continuing operations		(36,000	)		(36,000	)
December 31, 2009		375,000			223,000
Proved developed reserves -
December 31, 2006		476,000			367,000
December 31, 2007		635,000			398,000
December 31, 2008		404,000			323,000
December 31, 2009		373,000			219,000

Net revisions of 201,000 BOE in 2008 consisted of approximately 203,000 BOE of downward revisions attributable to the effects of lower product prices on the estimated quantities of proved reserves, and upward revisions of approximately 2,000 BOE attributable to well performance primarily from properties in the Kermit Field of West Texas. Net revisions of 209,000 BOE in 2007 consisted of approximately 40,000 BOE additional reserves from the assignment of additional interest in the NR Colby B and approximately 15,000 BOE of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, and upward revisions of approximately 154,000 BOE attributable to well performance primarily from properties in the Block D Field of West Texas.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The standardized measure as of December 31, 2008, 2007 and 2006 reflects an average oil price of $42.85, $91.81 and $56.41 per barrel, respectively.

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

6.	Oil and Gas Reserves Information (unaudited) - continued

Net revisions of 7,000 BOE in 2009 consisted of approximately 23,000 BOE of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, and downward revisions of approximately 29,000 BOE attributable to well performance primarily from properties in the Hendrick Field of West Texas and 1,000 BOE of downward revisions of proved undeveloped reserves. Net revisions of 201,000 BOE in 2008 consisted of approximately 203,000 BOE of downward revisions attributable to the effects of lower product prices on the estimated quantities of proved reserves, and upward revisions of approximately 2,000 BOE attributable to well performance primarily from properties in the Kermit Field of West Texas.

Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The standardized measure as of December 31, 2009, 2008 and 2007 reflects an average oil price of $55.61, $42.85 and $91.81 per barrel, respectively. Average prices for December 31, 2009 were based on the 12-month unweighted arithmetic average for the first-day-of-the-month price for the period from January 2009 through December 2009.

Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The standardized measure as of December 31, 2009, 2008 and 2007 reflects an average natural gas price of $3.58, $6.84 and $7.83 per Mcf, respectively. Average prices for December 31, 2009 were based on the 12-month unweighted arithmetic average for the first-day-of-the-month price for the period from January 2009 through December 2009.

The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.

Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes. Pertinent information gathered during the year may include actual production and decline rates, production from offset wells drilled to the same geologic formation, increased or decreased water production, workovers, and changes in lifting costs, among others. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.

The Partnership has reserves, which are classified as proved developed and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate the Partnership's present reserves.

Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007 is presented below:

2008

2007

2006

2009

2008

2007

Future cash inflows

1921,~~695~~636,000

6119,~~757~~695,000

2861,~~970~~757,000

Production, development and abandonment costs

1214,~~720~~848,000

2512,~~096~~720,000

1425,~~748~~096,000

Future net cash flows

6,~~975~~788,000

366,~~661~~975,000

1436,~~222~~661,000

10% annual discount for estimated

timing of cash flows

2,~~801~~339,000

192,~~502~~801,000

619,~~642~~502,000

Standardized measure of discounted

future net cash flows

4,~~174~~449,000

174,~~159~~174,000

717,~~580~~159,000

Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2008, 2007 and 2006 are as follows:

	2008			2007			2006
Sales of oil and gas produced, net of production costs	$	(2,688,000	)	$	(1,908,000	)	$	(1,644,000	)
Changes in prices and production costs		(13,911,000	)		6,361,000			(2,056,000	)
Extensions and discoveries and improved
recovery net of future production and
development costs		48,000			-			-
Changes of production rates (timing) and others		3,660,000			(724,000	)		850,000
Revisions of previous quantities estimates		(1,810,000	)		5,092,000			(764,000	)
Accretion of discount		1,716,000			758,000			1,018,000
Discounted future net cash flows -
Beginning of year		17,159,000			7,580,000			10,176,000
End of year	$	4,174,000		$	17,159,000		$	7,580,000

Southwest Oil & Gas Income Fund VIII-A, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

6.	Oil and Gas Reserves Information (unaudited) - continued

Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2009, 2008 and 2007 are as follows:

	2009			2008			2007
Sales of oil and gas produced, net of production costs	$	(954,000	)	$	(2,688,000	)	$	(1,908,000	)
Changes in prices and production costs		583,000			(13,911,000	)		6,361,000
Extensions and discoveries and improved
recovery net of future production and
development costs		-			48,000			-
Changes of production rates (timing) and others		306,000			3,660,000			(724,000	)
Revisions of previous quantities estimates		(77,000	)		(1,810,000	)		5,092,000
Accretion of discount		417,000			1,716,000			758,000
Discounted future net cash flows -
Beginning of year		4,174,000			17,159,000			7,580,000
End of year	$	4,449,000		$	4,174,000		$	17,159,000

7.	Selected Quarterly Financial Results – (unaudited)

	Quarters
	First		Second		Third		Fourth
2009:
Total revenues	$	369,506	$	561,923	$	579,941	$	702,420
Total expenses		334,637		316,665		368,392		457,795
Net income	$	34,869	$	245,258	$	211,549	$	244,625

Net income per limited partners unit	$	2.24	$	16.17	$	13.94	$	16.11

	Quarters
	First		Second		Third		Fourth
2008:
Total revenues	$	1,085,726	$	1,368,386	$	1,149,635	$	577,398
Total expenses		268,320		413,210		415,033		590,406
Net income (loss)	$	817,406	$	955,176	$	734,602	$	(13,008	)

Net income (loss) per
limited partners unit	$	54.05	$	63.19	$	48.58	$	(.91	)

	Quarters
	First		Second		Third		Fourth
2007:
Total revenues	$	522,103	$	697,057	$	758,027	$	986,288
Total expenses		221,496		306,282		318,551		409,426
Net income	$	300,607	$	390,775	$	439,476	$	576,862
Net income per limited partners unit	$	19.85	$	25.82	$	29.04	$	38.13

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None

Item 9A. Controls and Procedures

Disclosure 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

Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and

provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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~~year ended December 31, ~~2008~~2009 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Management assessed the effectiveness of our internal control over financial reporting as of December 31, ~~2008~~2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December 31, ~~2008~~2009, our internal control over financial reporting is effective based on those criteria.

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

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 7778, 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 5758, 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 5455, 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.

RANDY HOWARD, age 5354, is Vice President – of the Managing General Partner, having served in this capacity since March 2006.

ROBERT C. LYON, age 7273, 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 5253, 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.

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. Executive Compensation

The Partnership does not employ any directors, executive officers or employees. The Managing General Partner receives an administrative fee for the management of the Partnership. The Managing General Partner received $98,400 during each of ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007 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. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

There are no limited partners who own of record, or are known by the Managing General Partner to beneficially own, more than five percent of the Partnership's limited partnership interests, other than the Managing General Partner.

Through repurchase offers to the limited partners, the Managing General Partner owns 5,~~272~~402.8 limited partner units, a 3435.98% limited partner interest. The Managing General Partner's total percentage interest ownership in the Partnership is 4445.98%.

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. Certain Relationships and Related Transactions, and Director Independence

In ~~2008~~2009, the Managing General Partner received $98,400 as an administrative fee. This amount is part of the general and administrative expenses incurred by the Partnership.

In some instances, the Managing General Partner and its affiliates may be working interest owners in an oil and gas property in which the Partnership also has a working interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $~~146~~175,~~300~~400 for administrative overhead attributable to operating such properties during ~~2008~~2009.

The terms of the above transaction are similar to ones, which would have been obtained through arm’s length negotiations with unaffiliated third parties.

Item 14. 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, ~~2008~~2009 and ~~2007~~2008 and fees billed for other services rendered by KPMG during those periods.

For the Year Ended December 31,	~~2008~~2009		~~2007~~2008
Audit Fees	$	1817,~~030~~163	$	1618,~~932~~030
Audit Related Fees		-		-
Tax Fees		-		-
All Other Fees		-		-
TOTAL	$	1817,~~030~~163	$	1618,~~932~~030

The Audit Committee of CWEI reviewed and approved, in advance, all audit and non-audit services provided by KPMG LLP.

Part IV

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
		Statements of Changes in Partners' Equity (Deficit)
		Statements of Cash Flows
		Notes to Financial Statements

	(2)	Schedules required by Article 12 of Regulation S-X are either omitted because they are not applicable or because the required information is shown in the financial statements or the notes thereto.

	(3)	Exhibits:

4	(a)	Certificate of Limited Partnership of Southwest Oil & Gas Income Fund VIII-A, L.P., dated November 30, 1987. (Incorporated by reference from Partnership's S-1 Registration Statement File Number 33-18847 effective March 31, 1988.)

	(b)	Agreement of Limited Partnership of Southwest Oil & Gas Income Fund VIII-A, L.P. dated July 6, 1988. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)


	31.1	Rule 13a-14(a)/15d-14(a) Certification
	31.2	Rule 13a-14(a)/15d-14(a) Certification
	32.1	Certification of Chief Executive Officer 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

Glossary of Oil and Gas Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this filing. All volumes of natural gas referred to herein are stated at the legal pressure base to the state or area where the reserves exit and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One stock tank barrel, or 42 United States gallons liquid volume.

BOE. Equivalent barrels of oil, with natural gas converted to oil equivalents based on a ratio of six Mcf of natural gas to one Bbl of oil.

Developmental well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploratory well. A well drilled to find and produce oil or gas in an unproved area to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Farm-out arrangement. An agreement whereby the owner of a leasehold or working interest agrees to assign his interest in certain specific acreage to an assignee, retaining some interest, such as an overriding royalty interest, subject to the drilling of one (1) or more wells or other specified performance by the assignee.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Mcf. One thousand cubic feet.

Oil. Crude oil, condensate and natural gas liquids.

Overriding royalty interest. Interests that are carved out of a working interest, and their duration is limited by the term of the lease under which they are created.

Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to estimated future abandonment costs, net of the estimated salvage value of related equipment.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

Proved Area. The part of a property to which proved reserves have been specifically attributed.

Proved developed oil and gas reserves. Proved oil and gas reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved properties. Properties with proved reserves.

Proved oil and gas reserves. The estimated quantities of crude oil, natural gas, and natural gas liquids with geological and engineering data that demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

Proved undeveloped reserves. Proved Oil and gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Southwest Oil & Gas Income Fund VIII-A, L.P.,
	a Delaware limited partnership
By:	Southwest Royalties, Inc., Managing
	General Partner
By:	/s/ L. Paul Latham
	L. Paul Latham
	President and Chief Executive Officer
Date:	March 2731, ~~2009~~2010

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, Chairman of the Board		L. Paul Latham, President and a Director
and a Director
Date: March 27, 2009		Date: March 27, 2009
Date: March 31, 2010		Date: March 31, 2010
/s/ Mel G. Riggs
Mel G. Riggs, Vice President – Finance,
Treasurer and a Director
Date: March 27, 2009
Date: March 31, 2010

Filing Compare · SOUTHWEST OIL & GAS INCOME FUND VIII-A L P