FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010

¨ 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 0-16493

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

(Exact name of registrant as specified

in its limited partnership agreement)

Delaware		75-2145576
(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)

(432) 682-6324

(Registrant's telephone number, including area code)

Not applicable

(Former name former, address and former fiscal year, if changed since last report)

Indicate by check mark whether 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:YesxNo¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) 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 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 Exchange 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
	Glossary	3

	Part I - FINANCIAL INFORMATION

Item 1.	Financial Statements	5

	Balance Sheets as of June 30, 2010 and December 31, 2009	6

	Statements of Operations for the three months and six months ended June 30, 2010 and 2009	7

	Statements of Cash flows for the six months ended June 30, 2010 and 2009	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	15

Item 4.	Controls and Procedures	15


	Part II – OTHER INFORMATION

Item 1.	Legal Proceedings	16

Item 1A.	Risk Factors	16

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	16

Item 3.	Defaults Upon Senior Securities	16

Item 4.	Submission of Matter to a Vote of Security Holders	16

Item 5.	Other Information	16

Item 6.	Exhibits	16

	Signatures	17

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 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.

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.

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.

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.

PART I. - FINANCIAL INFORMATION

Item 1. Financial Statements

The unaudited condensed financial statements included herein have been prepared by the Registrant (herein also referred to as the "Partnership") in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments necessary for a fair presentation have been included and are of a normal recurring nature. The financial statements should be read in conjunction with the audited financial statements and the notes thereto for the year ended December 31, 2009, which are found in the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission. The December 31, 2009 balance sheet included herein has been taken from the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009. Operating results for the three and six month periods ended June 30, 2010 are not necessarily indicative of the results that may be expected for the full year.

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

Balance Sheets

	June 30,			December 31,
	2010			2009
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	100,303		$	51,518
Receivable from Managing General Partner		33,508			94,518
State income tax deposits		944			739
Total current assets		134,755			146,775

Oil and gas properties - using the full-
cost method of accounting		4,860,406			4,841,571
Less accumulated depreciation,
depletion and amortization		4,381,133			4,359,695

Net oil and gas properties		479,273			481,876
	$	614,028		$	628,651

Liabilities and Partners' Equity (Deficit)

Asset retirement obligation	$	503,117		$	485,813

Partners' equity (deficit):
General partner		(623,387	)		(620,193	)
Limited partners		734,298			763,031

Total partners' equity		110,911			142,838

	$	614,028		$	628,651

The accompanying notes are an integral

part of these financial statements.

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

Statements of Operations

(unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Revenues

Oil and gas	$	254,596	$	237,660	$	507,254	$	377,850
Interest		59		13		104		33
Other income		-		-		-		12
		254,655		237,673		507,358		377,895

Expenses

Production		130,892		75,508		228,093		202,425
Depreciation, depletion and amortization		11,353		11,040		21,438		21,219
Accretion expense		8,780		9,986		17,348		19,769
General and administrative		35,066		32,385		72,028		71,653
		186,091		128,919		338,907		315,066

Net income	$	68,564	$	108,754	$	168,451	$	62,829

Net income allocated to:
Managing General Partner	$	6,856	$	10,875	$	16,845	$	6,283

Limited partners	$	61,708	$	97,879	$	151,606	$	56,546

Per limited partner unit	$	4.11	$	6.53	$	10.11	$	3.77

The accompanying notes are an integral

part of these financial statements.

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

Statements of Cash Flows

(unaudited)

	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:

Cash received from oil and gas sales	$	568,059		$	314,913
Cash paid to suppliers		(300,121	)		(287,374	)
Interest received		104			33
Miscellaneous settlement		-			12
Net cash provided by operating activities		268,042			27,584

Cash flows used in investing activities:

Additions to oil and gas properties		(18,879	)		(9,163	)

Cash flows used in financing activities:

Distributions to partners		(200,378	)		(46,513	)

Net increase (decrease) in cash and cash equivalents		48,785			(28,092	)

Beginning of period		51,518			63,005

End of period	$	100,303		$	34,913

Reconciliation of net income to net
cash provided by operating activities:

Net income	$	168,451		$	62,829

Adjustments to reconcile net income to
net cash provided by operating activities:

Depreciation, depletion and amortization		21,438			21,219
Accretion expense		17,348			19,769
Decrease (increase) in receivables		60,805			(62,937	)
Decrease in payables		-			(13,296	)

Net cash provided by operating activities	$	268,042		$	27,584

Noncash investing and financing activities:

(Decrease) increase in oil and gas properties –
Asset retirement obligation	$	(44	)	$	29,459

The accompanying notes are an integral

part of these financial statements.

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

Notes to Financial Statements

1.	Organization

Southwest Oil & Gas Income Fund VII-A, L.P. was organized under the laws of the state of Delaware on January 30, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as the Managing General Partner of the Partnership.

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%	-
Property acquisition costs	100%	-
Gain/loss on property dispositions	90%	10%
Operating and administrative costs (2)	90%	10%
Depreciation, depletion and amortization of oil and gas properties	90%	10%
All other costs	90%	10%

(1)

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

(2)

Administrative costs in any year exceeding 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

The interim financial information as of June 30, 2010, and for the three and six months ended June 30, 2010, is unaudited. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, in the opinion of management, these interim financial statements include all the necessary adjustments to fairly present the results of the interim periods and all such adjustments are of a normal recurring nature. The interim consolidated financial statements should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.

3.	Abandonment Obligations

The Partnership follows the provisions of ASC topic 410-20, formerly SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). ASC 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.

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 and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

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

Notes to Financial Statements

3.	Abandonment Obligations – continued

Changes in abandonment obligations for the six months ended June 30, 2010 and 2009 are as follows:

	2010			2009
Beginning of period	$	485,813		$	434,589
Revision of estimates		(44	)		29,459
Accretion expense		17,348			19,769
End of period	$	503,117		$	483,817

4.	Subsequent Events

The Partnership has evaluated events and transactions that occurred after the balance sheet date of June 30, 2010. The Partnership did not have any subsequent events that would require recognition in the financial statements or disclosures in these notes to the financial statements.

Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations

General

Southwest Oil & Gas Income Fund VII-A, L.P. was organized as a Delaware limited partnership on January 30, 1987. The offering of limited partnership interests began on March 4, 1987. Minimum capital requirements were met on April 28, 1987 and the offering concluded on September 21, 1987, with total limited partner contributions of $7.5 million.

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

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 partners is therefore expected to decline in later years based on these factors.

The Partnership recognizes income from oil and gas properties on an accrual basis while the quarterly cash distributions are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. If the calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due until the deficit is recovered from future cash flows.

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 June 30, 2010, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

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. Current SEC financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report. The ceiling calculation dictates that those prices be held constant. Because the ceiling calculation dictates that prices 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 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-Q with data that is not readily available from those statements.

	Three Months Ended
	June 30,
	2010		2009
Oil production in barrels		2,835		3,394
Gas production in mcf		7,557		10,587
Total (BOE)		4,095		5,159
Average price per barrel of oil	$	73.84	$	55.37
Average price per mcf of gas	$	5.99	$	4.70
Partnership distributions	$	100,378	$	46,513
Limited partner distributions	$	90,339	$	41,856
Per unit distribution to limited partners	$	6.02	$	2.79
Number of limited partner units		15,000		15,000

Operating Results

The following discussion compares our results for the quarters ended June 30, 2010 and 2009. Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective quarterly period.

Revenue

Comparing 2010 to 2009, oil and gas sales increased $16,936, of which price variances accounted for a $62,120 increase and production variances accounted for a $45,184 decrease.

Production in 2010 (on a BOE basis) was 21% lower than 2009. Our oil production in 2010 was 16% lower than 2009 due primarily to the production decline on one property. Our gas production was 29% lower in 2010 due primarily to the production decline on one property.

In 2010, our realized oil price was 33% higher than 2009, while our realized gas price was 27% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Expenses

Oil and gas production costs on a BOE basis increased from $14.64 per BOE in 2009 to $31.96 per BOE in 2010. The increase in oil and gas production costs in 2010 was due primarily to subsurface repairs on an injection well.

Depletion on a BOE basis increased 30% in 2010. Comparing 2010 to 2009, depletion expense increased $313, of which rate variances accounted for a $2,590 increase and production variances accounted for a $2,277 decrease.

Accretion expense decreased 12% in 2010 due primarily to a number of wells that reached their estimated plug and abandonment date at the end of 2009.

General and administrative (“G&A”) expenses were 8% higher in 2010 due primarily to increases in professional fees.

Supplemental Information

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

	Six Months Ended
	June 30,
	2010		2009
Oil production in barrels		5,259		6,204
Gas production in mcf		15,107		20,893
Total (BOE)		7,777		9,686
Average price per barrel of oil	$	76.31	$	46.60
Average price per mcf of gas	$	7.01	$	4.25
Partnership distributions	$	200,378	$	46,513
Limited partner distributions	$	180,339	$	41,856
Per unit distribution to limited partners	$	12.02	$	2.79
Number of limited partner units		15,000		15,000

Operating Results

The following discussion compares our results for the six months ended June 30, 2010 and 2009. Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective six-month period.

Revenue

Comparing 2010 to 2009, oil and gas sales increased $129,404, of which price variances accounted for a $198,018 increase and production variances accounted for a $68,614 decrease.

Production in 2010 (on a BOE basis) was 20% lower than 2009. Our oil production in 2010 was 15% lower than 2009 due primarily to the production decline on one property. Our gas production was 28% lower in 2010 than 2009 due primarily to the production decline on one property.

In 2010, our realized oil price was 64% higher than 2009, while our realized gas price was 65% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Expenses

Oil and gas production costs on a BOE basis increased from $20.90 per BOE in 2009 to $29.33 per BOE in 2010. The increase in oil and gas production costs in 2010 was due primarily to subsurface repairs on an injection well.

Depletion on a BOE basis increased 26% in 2010. Comparing 2010 to 2009, depletion expense increased $219, of which rate variances accounted for a $4,402 increase and production variances accounted for a $4,183 decrease.

Accretion expense decreased 12% in 2010 due primarily to a number of wells that reached their estimated plug and abandonment date at the end of 2009.

General and administrative (“G&A”) expenses were 1% higher in 2010.

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. In 2008, the Managing General Partner increased its total ownership interest in the Partnership to more than 50%. Therefore, the Partnership became subject to the Texas Margin Tax in 2008, and its profit margin will be included in the consolidated tax return filed by Clayton Williams Energy, Inc., parent of the Managing General Partner. The Partnership does not record any provision for this tax since any Texas Margin Tax attributable to the Partnership will be paid by the Managing General Partner and the amount is not considered significant.

Liquidity and Capital Resources

Partnership distributions during the six months ending June 30, 2010 were $200,378, of which $180,339 was distributed to the limited partners and $20,039 to the general partners. Cumulative cash distributions of $16,243,496 have been made to the general and limited partners as of June 30, 2010. As of June 30, 2010, $14,637,338 or $975.82 per limited partner unit has been distributed to the limited partners, representing 195% of contributed capital.

Item 3.

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 4.

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

There has not been any change in the Partnership’s internal control over financial reporting that occurred during the quarter ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PART II. - OTHER INFORMATION

Item 1.

Legal Proceedings

None

Item 1A.

Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the U.S. Securities and Exchange Commission on March 31, 2010 and available at www.sec.gov. There have been no material changes to these risk factors since the filing of our Form 10-K.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3.

Defaults Upon Senior Securities

None

Item 4.

Submission of Matter to a Vote of Security Holders

None

Item 5.

Other Information

None

Item 6.

Exhibits

(a)

Exhibits:

31.1	Rule 13a-14(a)/15d-14(a) Certification
31.2	Rule 13a-14(a)/15d-14(a) Certification
32.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Southwest Oil & Gas Income Fund VII-A, L.P.,
	a Delaware limited partnership

By:	Southwest Royalties, Inc., Managing
	General Partner


By:	/s/ L. Paul Latham
	L. Paul Latham
	President and Chief Executive Officer

Date:	August 13, 2010

SOUTHWEST OIL & GAS INCOME FUND VII A L P 10-Q