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 0-15411

Southwest Royalties, Inc. Income Fund VI

(Exact name of registrant as specified

in its limited partnership agreement)

Tennessee		75-2127812
(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.

Net Profits Interest. An agreement whereby the owner receives a specified percentage of the defined net profits from a producing property in exchange for consideration paid. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

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 & 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 Royalties, Inc. Income Fund VI

Balance Sheets

	June 30,			December 31,
	2010			2009
	(unaudited)
Assets

Current assets:
Cash and cash equivalents	$	225,845		$	142,101
Receivable from Managing General Partner		232,958			329,695
Total current assets		458,803			471,796

Oil and gas properties - using the full-
cost method of accounting		8,811,607			8,801,548
Less accumulated depreciation,
depletion and amortization		6,966,890			6,894,085

Net oil and gas properties		1,844,717			1,907,463
	$	2,303,520		$	2,379,259

Liabilities and Partners' Equity (Deficit)

Asset retirement obligation	$	1,003,230		$	960,667

Partners' equity (deficit):
General partner		(724,301	)		(712,470	)
Limited partners		2,024,591			2,131,062

Total partners' equity		1,300,290			1,418,592
	$	2,303,520		$	2,379,259

The accompanying notes are an integral

part of these financial statements.

Southwest Royalties, Inc. Income Fund VI

Statements of Operations

(unaudited)

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

Income from net profits interests	$	464,018	$	230,941	$	957,870	$	450,807
Interest		196		70		336		142
Miscellaneous income		-		-		-		84
		464,214		231,011		958,206		451,033
Expenses

Depreciation, depletion and amortization		36,460		38,694		72,805		76,788
Accretion expense		16,383		17,636		32,504		34,902
General and administrative		43,945		47,618		96,180		95,763
		96,788		103,948		201,489		207,453

Net income	$	367,426	$	127,063	$	756,717	$	243,580

Net income allocated to:
Managing General Partner	$	36,743	$	12,706	$	75,672	$	24,358

Limited Partners	$	330,683	$	114,357	$	681,045	$	219,222

Per limited partner unit	$	16.53	$	5.72	$	34.05	$	10.96

The accompanying notes are an integral

part of these financial statements.

Southwest Royalties, Inc. Income Fund VI

Statements of Cash Flows

(unaudited)

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

Cash received from income from net
profits interests	$	1,054,607		$	535,198
Cash paid to suppliers		(96,180	)		(95,763	)
Interest received		336			142
Miscellaneous income		-			84
Net cash provided by operating activities		958,763			439,661

Cash flows used in financing activities:
Distributions to partners		(875,019	)		(445,072	)

Net increase (decrease) in cash and cash equivalents		83,744			(5,411	)

Beginning of period		142,101			88,123

End of period	$	225,845		$	82,712

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

Net income	$	756,717		$	243,580

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

Depreciation, depletion and amortization		72,805			76,788
Accretion expense		32,504			34,902
Decrease in receivables		96,737			84,391
Net cash provided by operating activities	$	958,763		$	439,661

Noncash investing and financing activities:

Increase in oil and gas properties –
Asset retirement obligation	$	10,059		$	115,486

The accompanying notes are an integral

part of these financial statements.

Southwest Royalties, Inc. Income Fund VI

Notes to Financial Statements

1.	Organization

Southwest Royalties, Inc. Income Fund VI was organized under the laws of the state of Tennessee on December 4, 1986 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 disposition	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.

Southwest Royalties, Inc. Income Fund VI

Notes to Financial Statements

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.

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

	2010		2009
Beginning of period	$	960,667	$	770,767
Additional abandonment obligations from new wells		-		728
Revision of estimates		10,059		114,758
Accretion expense		32,504		34,902
End of period	$	1,003,230	$	921,155

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 Royalties, Inc. Income Fund VI was organized as a Tennessee limited partnership on December 4, 1986. The offering of such limited partnership interests began on August 25, 1986. Minimum capital requirements were met on October 3, 1986 and the offering concluded on January 29, 1987, with total limited partner contributions of $10 million.

The Partnership was formed to acquire royalty and net profits 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 will not be 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.

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.

The Partnership's interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

The Partnership recognizes income from its net profits interest in oil and gas property on an accrual basis, while the quarterly cash distributions of the net profits interest are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. If the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due to the Partnership's net profits interest until the deficit is recovered from future net profits. The Partnership accrues a quarterly loss on its net profits interest provided there is a cumulative net amount due for accrued revenue as of the balance sheet date. As of June 30, 2010, there were no timing differences, which resulted in a deficit net profit interest.

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		6,352		6,277
Gas production in mcf		59,686		61,611
Total (BOE)		16,300		16,546
Average price per barrel of oil	$	75.36	$	54.39
Average price per mcf of gas	$	5.82	$	4.00
Partnership distributions	$	525,019	$	200,072
Limited partner distributions	$	472,516	$	180,059
Per unit distribution to limited partners	$	23.63	$	9.00
Number of limited partner units		20,000		20,000

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 $238,219, of which price variances accounted for a $241,834 increase and production variances accounted for a $3,615 decrease.

Production in 2010 (on a BOE basis) was 1% lower than 2009. Oil production increased 1% in 2010 than 2009. Our gas production was 3% lower in 2010 than 2009.

In 2010, our realized oil price was 39% higher than 2009, while our realized gas price was 46% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on a BOE basis increased from $21.56 per BOE in 2009 to $22.20 per BOE in 2010.

Expenses

Depletion on a BOE basis decreased 4% in 2010. Comparing 2010 to 2009, depletion expense decreased $2,234, of which rate variances accounted for a $1,659 decrease and production variances accounted for a $575 decrease.

Accretion expense decreased 7% in 2010 than 2009.

General and administrative (“G&A”) expenses were 8% lower in 2010 than 2009.

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		11,224		12,422
Gas production in mcf		122,633		125,784
Total (BOE)		31,663		33,386
Average price per barrel of oil	$	74.41	$	44.62
Average price per mcf of gas	$	6.57	$	3.93
Partnership distributions	$	875,019	$	445,072
Limited partner distributions	$	787,516	$	400,559
Per unit distribution to limited partners	$	39.38	$	20.03
Number of limited partner units		20,000		20,000

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 $592,545, of which price variances accounted for a $658,387 increase and production variances accounted for a $65,842 decrease.

Production in 2010 (on a BOE basis) was 5% lower than 2009. Oil production decreased 10% in 2010 due primarily to the production decline on one property. Our gas production was 3% lower in 2010 than 2009.

In 2010, our realized oil price was 67% higher than 2009, while our realized gas price was 67% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on a BOE basis increased from $17.91 per BOE in 2009 to $21.58 per BOE in 2010. The increase in oil and gas production costs in 2010 was due primarily to the workover of an oil well.

Expenses

Depletion on a BOE basis remained the same in 2010 and 2009. Comparing 2010 to 2009, depletion expense decreased $3,983, of which rate variances accounted for a $20 decrease and production variances accounted for a $3,963 decrease.

Accretion expense decreased 7% in 2010 than 2009.

General and administrative (“G&A”) expenses were less than 1% higher in 2010 than 2009.

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. However the Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership since substantially all of its income is derived from a net profits interest.

Liquidity and Capital Resources

Partnership distributions during the six months ended June 30, 2010 were $875,019, of which $787,516 was distributed to the limited partners and $87,503 to the general partners. Cumulative cash distributions of $30,744,277 have been made to the general and limited partners as of June 30, 2010. As of June 30, 2010, $27,685,557 or $1,384.28 per limited partner unit has been distributed to the limited partners, representing 277% 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 Royalties, Inc. Income Fund VI, a
	Tennessee 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 ROYALTIES INC INCOME FUND VI 10-Q