UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2011

o 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: 333-122935-01

REEF GLOBAL ENERGY VI, L.P.

(Exact name of registrant as specified in its charter)

Nevada

(State or other jurisdiction of

incorporation or organization)

20-3170768

(I.R.S. employer

identification no.)

1901 N. Central Expressway, Suite 300

Richardson, Texas

(Address of principal executive offices)

75080-3610

(Zip code)

(972)-437-6792

Registrant’s telephone number, including area code

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. Yes x No o

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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o		Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of November 10, 2011, the registrant had 75.363 units of general partner interest held by the managing general partner, and 1,431.897 units of limited partner interest outstanding.

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Reef Global Energy VI, L.P.

Form 10-Q Index

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)
	Condensed Balance Sheets
	Condensed Statements of Operations
	Condensed Statements of Cash Flows
	Notes to Condensed Financial Statements

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

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk

ITEM 4T.	Controls and Procedures

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings

ITEM 1A.	Risk Factors

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds

ITEM 3.	Default Upon Senior Securities

ITEM 4.	(Removed and Reserved)

ITEM 5.	Other Information

ITEM 6.	Exhibits

Signatures

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Reef Global Energy VI, L.P.

Condensed Balance Sheets

	September 30, 2011		December 31, 2010
	(unaudited)

Assets

Current assets:
Cash and cash equivalents	$	183,088	$	182,919
Accounts receivable	3,644		2,895
Accounts receivable from affiliates	632,887		631,006
Total current assets	819,619		816,820

Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $32,211,054 and $31,598,214	1,399,638		1,998,602
Net oil and gas properties	1,399,638		1,998,602

Total assets	$	2,219,257	$	2,815,422

Liabilities and partnership equity

Current liabilities:
Accounts payable	$	45,107	$	18,372
Accounts payable to affiliates	75,054		271,514
Total current liabilities	120,161		289,886

Long-term liabilities:
Asset retirement obligation	438,674		429,827
Total long-term liabilities	438,674		429,827

Partnership equity:
Limited partners	1,456,920		1,881,392
Managing general partner	203,502		214,317
Partnership equity	1,660,422		2,095,709

Total liabilities and partnership equity	$	2,219,257	$	2,815,422

See accompanying notes to condensed financial statements (unaudited).

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Reef Global Energy VI, L.P.

Condensed Statements of Operations

(Unaudited)

	For the three months ended September 30,				For the nine months ended September 30,
	2011		2010		2011		2010

Oil, gas and NGL sales	$	955,564	$	1,049,635	$	3,108,213	$	3,393,779

Costs and expenses:
Lease operating expenses	83,720		113,798		294,029		336,293
Production taxes	65,367		81,871		236,201		32,272
Depreciation, depletion and amortization	194,482		451,452		612,840		1,475,542
Accretion of asset retirement obligation	3,874		3,498		11,380		65,347
General and administrative	111,384		121,969		370,703		497,708
Total costs and expenses	458,827		772,588		1,525,153		2,407,162

Income from operations	496,737		277,047		1,583,060		986,617

Other income:
Interest income	64		142		214		493
Total other income	64		142		214		493

Net income	$	496,801	$	277,189	$	1,583,274	$	987,110

Net income per limited partner unit	$	280.84	$	134.60	$	895.47	$	487.80
Net income per managing general partner unit	$	1,256.15	$	1,120.70	$	3,994.70	$	3,829.88

See accompanying notes to condensed financial statements (unaudited).

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Reef Global Energy VI, L.P.

Condensed Statements of Cash Flows

(Unaudited)

	For the nine months ended September 30,
	2011			2010

Cash flows from operating activities
Net income	$	1,583,274		$	987,110
Adjustments to reconcile net income to net cash provided by operating activities:
Plugging and abandonment costs paid from asset retirement obligation	(2,533		)	(30,964		)
*Adjustments for non-cash transactions:*
Depreciation, depletion and amortization	612,840			1,475,542
Accretion of asset retirement obligation	11,380			65,347
*Changes in operating assets and liabilities:*
Accounts receivable	(749		)	12,033
Accounts receivable from affiliates	(1,881		)	95,297
Accounts payable	26,735			(65,442		)
Accounts payable to affiliates	(196,460		)	—
Net cash provided by operating activities	2,032,606			2,538,923

Cash flows from investing activities
Proceeds from sale of property	—			96,206
Property acquisition and development	(13,876		)	(210,269		)
Net cash used in investing activities	(13,876		)	(114,063		)

Cash flows from financing activities
Partner distributions	(2,018,561		)	(2,419,305		)
Net cash used in financing activities	(2,018,561		)	(2,419,305		)

Net increase in cash and cash equivalents	169			5,555
Cash and cash equivalents at beginning of period	182,919			165,715
Cash and cash equivalents at end of period	$	183,088		$	171,270

Supplemental disclosure of non-cash investing transactions
Adjustment to asset retirement obligation	$	—		$	873

See accompanying notes to condensed financial statements (unaudited).

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Reef Global Energy VI, L.P.

Notes to Condensed Financial Statements (unaudited)

1. Organization and Basis of Presentation

The condensed financial statements of Reef Global Energy VI, L.P. (the “Partnership”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations. We have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”). The adjustments are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first nine months of 2011. Therefore, please read these condensed financial statements and notes to condensed financial statements together with the audited financial statements and notes to financial statements contained in the Partnership’s Annual Report on Form 10-K for the period ended December 31, 2010 (the “Annual Report”).

2. Summary of Accounting Policies

Oil and Gas Properties

The Partnership follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves, as determined by independent petroleum engineers. For these purposes, proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the sum of the estimated future net revenues from proved reserves using prices that are the 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. No gain or loss is recognized upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three and nine month periods ended September 30, 2011 and 2010, the Partnership recognized no property impairment expense of proved properties.

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at September 30, 2011 and December 31, 2010 have been prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and current costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows.

Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing net income. A decline in estimated proved reserves and future cash flows also reduces the capitalized cost ceiling and may result in increased impairment expense.

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Restoration, Removal, and Environmental Liabilities

The Partnership is subject to extensive Federal, state and local environmental laws and regulations. These laws 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 substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or reliably determinable.

Asset retirement costs and liabilities associated with future site restoration and abandonment of long-lived assets are initially measured at fair value, which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the net asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations.

The following table summarizes the Partnership’s asset retirement obligation for the nine month period ended September 30, 2011 and the year ended December 31, 2010.

	Nine months ended September 30, 2011			Year Ended December 31, 2010
Beginning asset retirement obligation	$	429,827		$	393,393
Additions related to well conversion	—			5,478
Accretion expense	11,380			68,979
Retirement related to property sale	—			(873		)
Retirement related to property abandonment and restoration	(2,533		)	(37,150		)
Ending asset retirement obligation	$	438,674		$	429,827

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, accounts payable, and accounts payable to affiliates approximates their carrying value due to their short-term nature.

Reclassifications

Certain information provided for prior years has been reclassified to conform to the current year presentation adopted as of September 30, 2011.

3. Transactions with Affiliates

The Partnership has no employees. Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. The Partnership reimburses RELP for technical and administrative services at cost. During the three and nine month periods ended September 30, 2011, the Partnership incurred administrative costs totaling $79,625 and $271,814, respectively. The Partnership incurred no technical services costs during the three and nine month periods ended September 30, 2011. During the three and nine month periods ended September 30, 2010, the Partnership incurred technical services costs of $9,410 and $14,268, respectively, and incurred administrative costs of $78,621 and $320,963, respectively. Technical services costs are capitalized as project costs on the condensed balance sheets. Administrative costs are included as general and administrative expenses on the condensed statements of operations.

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Reef contributed 1% of all leasehold, drilling and completion costs when incurred during the drilling and completion phase of Partnership operations. Reef contributed $316,361 in connection with this obligation. In addition, Reef also purchased 5% of the Partnership units and paid 5% of the 99% of these costs paid by the unit holders (4.95%).

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At September 30, 2011 and December 31, 2010, RELP owed the Partnership $632,887 and $631,006, respectively, for net revenues processed in excess of joint interest and technical and administrative services charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month to which the revenues pertain. The Partnership settles its balances with Reef and RELP on at least a quarterly basis.

The Partnership reimbursed to Reef legal fees totaling $162,793 and $120,000, respectively, during the nine months ended September 30, 2011 and the year ended December 31, 2010 pertaining to the settlement of a lawsuit brought against Reef by a partner in the Partnership. Reef prevailed in the defense of this lawsuit and a judgment was entered that dismissed the plaintiff’s claims. Although the Partnership was not formally named a defendant in the litigation, the partner who brought the lawsuit was a partner in several Reef affiliates, including this Partnership, and his claim involved his participation in these partnerships, including this Partnership. Pursuant to the Partnership Agreement of the Partnership, Reef is indemnified against litigation such as this, and the associated legal fees are to be reimbursed by the Partnership. At September 30, 2011, the Partnership owed Reef a balance of $75,054 for its share of the legal fees associated with this lawsuit.

The Partnership reimbursed to Reef legal fees totaling $23,239 and $23,457, respectively, during the nine months ended September 30, 2011 and the year ended December 31, 2010 pertaining to the lawsuit described in Note 4 below. The partners who brought the lawsuit are partners in several Reef affiliates, including this Partnership, and their claims involve their participation in these partnerships, including this Partnership. Pursuant to the Partnership Agreement of the Partnership, Reef is indemnified against litigation such as this, and the associated legal fees are being reimbursed to Reef by each of the partnerships involved on a quarterly basis.

4. Commitments and Contingencies

On August 26, 2010, Frank Stevenson (“Stevenson”) filed a lawsuit, styled Stevenson v. Wayne Kirk, Michael J. Mauceli, Reef Global Energy Ventures II, et al., Cause No. 10-10647, in the 191st Judicial District Court, Dallas County, Texas. The suit also names as defendants Reef Global Energy VI, L.P. and multiple other Reef-sponsored ventures and limited partnerships, as well as Reef Securities, Inc., among others. On September 22, 2010, James and Carol Estle (the “Estles”) and Nancy Dykes Thurmond Antolic (“Antolic”) joined the suit as additional plaintiffs. On January 27, 2011, Donna Stevenson (Frank Stevenson’s spouse) and Jaimie Davis (“Davis”) joined the suit as additional plaintiffs. With respect to Davis’s claims, specifically, Reef Securities, Inc. did not offer or sell the interests in the Reef program that Davis purchased. Rather, she purchased her interests through an unaffiliated broker/dealer. In the First Amended Petition, plaintiffs alleged that, collectively, they were seeking in excess of $1 million in compensatory damages as well as exemplary damages, attorneys’ fees, pre- and post-judgment interest, and costs. In the Second Amended Petition, plaintiffs seek an undisclosed, unspecified amount of damages. Plaintiffs assert claims of fraud, rescission under the Texas Securities Act, control person liability under the Texas Securities Act, and breach of fiduciary duty. Plaintiff Davis asserts against defendant Reef Oil & Gas Income and Development Fund, L.P. a claim for tortious interference with an existing contract. Defendants believe plaintiffs’ claims are meritless, and with respect to many of the Reef programs named in the petition, defendants believe that the claims for fraud are barred by limitations, as are any claims for rescission or breach of fiduciary duty with respect to those programs. In addition, with respect to all Reef programs in which plaintiffs participated, each plaintiff received offering documents that thoroughly disclosed all material facts and risks associated with participation in such programs, particularly the fact that no guarantees or promises could be made or relied upon. Defendants (including Reef Global Energy VI, L.P.) intend to vigorously defend the lawsuit and may seek damages from plaintiffs based upon, among other things, breaches of representations and warranties made by them as well as the indemnification provisions of the documents executed by each of them. As of this time, no substantive discovery has been conducted, and no trial date has been set. The case has been stayed pending an arbitration by one of the plaintiffs against an unaffiliated broker-dealer. The Partnership is reimbursing to Reef its share of the costs of defending this lawsuit as incurred, and has reimbursed $23,239 and $23,457, respectively, during the nine months ended September 30, 2011 and the year ended December 31, 2010.

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5. Partnership Equity

Information regarding the number of units outstanding and the net income per type of Partnership unit for the three and nine month periods ended September 30, 2011 is detailed below:

For the three months ended September 30, 2011

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner units	75.363	$	94,667	$	1,256.15
Limited partner units	1,431.897	402,134		$	280.84
Total	1,507.260	$	496,801

For the nine months ended September 30, 2011

Type of Unit	Number of Units	Net income		Net income per unit
Managing general partner units	75.363	$	301,053	$	3,994.70
Limited partner units	1,431.897	1,282,221		$	895.47
Total	1,507.260	$	1,583,274

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

The following is a discussion of the Partnership’s financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our financial statements and the related notes thereto, included in the Annual Report.

This Quarterly Report contains forward-looking statements that involve risks and uncertainties. You should exercise extreme caution with respect to all forward-looking statements made in this Quarterly Report. Specifically, the following statements are forward-looking:

· statements regarding the state of the oil and gas industry and the opportunity to profit within the oil and gas industry, competition, pricing, level of production, or the regulations that may affect the Partnership;

· statements regarding the plans and objectives of Reef for future operations, including, without limitation, the uses of Partnership funds and the size and nature of the costs the Partnership expects to incur and people and services the Partnership may employ;

· any statements using the words “anticipate,” “believe,” “estimate,” “expect” and similar such phrases or words; and

· any statements of other than historical fact.

Reef believes that it is important to communicate its future expectations to the partners. Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions, including, without limitation, the risk factors listed in the section captioned “RISK FACTORS” contained in the Partnership’s Annual Report. Although Reef believes that the expectations reflected in such forward-looking statements are reasonable, Reef can give no assurance that such expectations will prove to have been correct. Should any one or more of these or other risks or uncertainties materialize or should any underlying assumptions prove incorrect, actual results are likely to vary materially from those described herein. There can be no assurance that the projected results will occur, that these judgments or assumptions will prove correct or that unforeseen developments will not occur.

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Reef does not intend to update its forward-looking statements. All subsequent written and oral forward-looking statements attributable to Reef or persons acting on its behalf are expressly qualified in their entirety by the applicable cautionary statements.

Overview

Reef Global Energy VI, L.P. is a Nevada limited partnership formed to acquire, explore, develop and produce crude oil, natural gas, and natural gas liquids for the benefit of its investor partners. The Partnership’s primary purposes are to generate revenues from the production of crude oil and natural gas, distribute cash flow to investors, and provide tax benefits to investors. The Partnership purchased working interests in twenty developmental prospects. The Partnership participated in the drilling of eight successful developmental wells and eleven unsuccessful developmental wells on nineteen of these twenty prospects. Six of these successful wells have ceased production, and the Partnership sold its interest in one well during 2010. The Partnership purchased a working interest in the Sand Dunes developmental prospect in Eddy County, New Mexico, and has participated in the drilling of eight developmental wells on this prospect (see below).

The Partnership also purchased working interests in fourteen exploratory prospects, and participated in the drilling of sixteen exploratory and eight developmental wells on those prospects. The Partnership participated in the drilling of eight successful exploratory wells, seven successful developmental wells, eight unsuccessful exploratory wells, and one unsuccessful developmental well on these fourteen prospects. Of the fifteen successful wells, four wells have ceased production, and eleven are currently productive.

Since completing its drilling phase of operations during the first quarter of 2008, the Partnership has participated in drilling two additional wells on one of the Partnership’s exploratory prospects located in Live Oak County, Texas. One of these wells was successful and is currently productive, and the second well was unsuccessful. These wells are included in the summaries of wells in the preceding paragraphs. While there are currently no plans to drill any additional wells, the Partnership is allowed to borrow funds in accordance with the Partnership Agreement, or utilize cash flows from successful wells in order to conduct further development upon prospects initially purchased by and drilled upon by the Partnership during the drilling phase of operations.

In this Quarterly Report, we use the term “successful” to refer to wells that are drilled, tested, and either capable of or actually producing in commercial quantities. We use the term “unsuccessful” to refer to wells that do not meet one or more of these criteria.

The Partnership participated in the drilling of eight developmental wells on the Sand Dunes prospect located in Eddy County, New Mexico during the fourth quarter of 2007 and the first quarter of 2008. Initial testing confirmed the presence of crude oil and natural gas in all eight wells. However, the field was temporarily shut-in because of the lack of electric service and because of the high cost of trucking offsite the salt water volumes associated with the production of the crude oil and natural gas from the wells. Electrical service to the eight Sand Dunes wells was connected in September 2008. Based upon initial testing, larger bottom hole pumps were placed below the well perforations in three of the wells and testing was resumed in late September 2008 to determine the three wells’ commercial productivity. Water continued to be trucked offsite, and RELP applied for and received a permit which would allow for the conversion of one of the existing eight Sand Dunes wells into a water disposal well. RELP also explored the possibility of drilling a ninth well as a salt water disposal well for the field. Testing results on two of the three wells were positive, and salt water production volumes declined as a result of pumping off the wells using the larger bottom hole pumps. However, the price of crude oil also declined at a rapid rate while testing was being conducted. In late December 2008, two of the three testing wells were shut-in again. Crude oil prices continued declining to a level below $40 per barrel. In February 2009, following a mechanical failure in the third testing well, RELP, as operator, shut-in the field. The eight wells could not be commercially productive without efficient salt water disposal capabilities, and none of the options regarding salt water disposal were economically viable at first quarter 2009 commodity prices. As of December 31, 2008, the eight Sand Dunes wells were considered temporarily non-commercial until the conversion of one of the eight wells into a salt water disposal well was completed and commodity prices recovered.

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Beginning with March 2009, oil prices increased from levels below $40 per barrel to between $60 and $70 per barrel by the third quarter of 2009. As a result of this increase in prices, in October 2009, Reef approved the conversion of one of the eight wells on the Sand Dunes development prospect located in Eddy County, New Mexico to a salt water disposal well. The conversion work on the well began in March 2010 and was completed during April 2010. Upon completion of the disposal facilities, the new disposal well became operational during August 2010. Based on the disposal capacity of the converted well, all of the remaining seven Sand Dunes wells were placed into production as of December 31, 2010. The cost of the well conversion to this Partnership was approximately $172,355. This cost was paid for by the Partnership by retaining a portion of the funds normally paid out in distributions to the partners. As of December 31, 2010, there were 2,100 BBL of crude oil and 2,350 Mcf of natural gas reserves net to the Partnership’s interest for the wells placed on full time production during 2010.

As of September 30, 2011, two of the Sand Dunes wells were shut-in. Repair and maintenance work was performed on one shut-in well and it has been returned to production during the fourth quarter of 2011. Repair and maintenance work to return the remaining shut-in well to production has been approved during the fourth quarter of 2011. To date, performance of the Sand Dunes wells has fallen short of Reef’s expectations, due to lower production volumes and higher repair and maintenance costs than were originally anticipated. While the wells have only been on line for a short time, Reef does not believe they will achieve the level of production originally forecast when considering the conversion of the new salt water disposal well.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in the Annual Report.

Liquidity and Capital Resources

The Partnership was funded with initial capital contributions totaling $37,398,898. Reef purchased 75.363 general partner units, or 5% of the total units sold, for $1,601,464. Investor partners purchased 1,190.561 units of general partner interest and 241.336 units of limited partner interest for $35,797,434. Reef also contributed $316,361 in connection with its obligation to pay 1% of all leasehold, drilling, and completion costs. Organization and offering costs totaled $5,369,615, leaving capital contributions of $32,345,644 available for Partnership activities. The Partnership expended $33,101,838 on prospect and property acquisitions, drilling and completion costs in connection with its participation in the drilling of forty-nine wells and expended $138,317 on general and administrative expenses during its drilling and completion phase of operations. The Partnership also expended $306,940 on the drilling of one successful exploratory well and one unsuccessful exploratory well subsequent to the completion of the Partnership’s drilling phase. Expenditures in excess of Partnership capital were deducted from Partnership distributions. There are no plans to conduct any additional drilling on Partnership prospects at this time; however, additional drilling activity is permitted on the Partnership prospects. Any additional capital expenditures will also be recovered from cash flow by reducing Partnership distributions. The Partnership does not operate in any other industry segment, and operates solely in the United States.

The Partnership has working capital of $699,458 at September 30, 2011. Subsequent to expending the initial available Partnership capital contributions on prospect acquisitions and drilling and completion costs of Partnership wells, the Partnership’s working capital consists primarily of cash flows from productive properties utilized to pay cash distributions to investors.

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Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the unaudited condensed financial statements and the related notes to the unaudited condensed financial statements included in this Quarterly Report.

The following table provides information about sales volumes and crude oil and natural gas prices for the periods indicated. Equivalent barrels of oil (“EBO”) are computed by converting 6 Mcf of natural gas to 1 barrel of crude oil.

	For the three months ended September 30,				For the nine months ended September 30,
	2011		2010		2011		2010
Sales volumes:
Oil (Barrels)	7,366		8,817		23,466		25,755
Natural gas (Mcf)	57,455		95,093		182,642		316,882

Average sales prices received:
Oil (Barrels)	$	88.99	$	61.92	$	90.31	$	67.65
Natural gas (Mcf)	$	5.22	$	5.30	$	5.42	$	5.21

The estimated net proved crude oil and natural gas reserves as of September 30, 2011 and 2010 are summarized below. The quantities of proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership reasonably expects to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

Net proved reserves	Oil (Bbl)	Gas (Mcf)
September 30, 2011	32,867	534,550
September 30, 2010	40,241	453,266

Three months ended September 30, 2011 compared to the three months ended September 30, 2010

Partnership net income rose from $277,189 for the three month period ended September 30, 2010 to $496,801 for the three month period ended September 30, 2011. The primary causes of this increase in net income were lower expenses, including lower depletion, depreciation and amortization expenses as discussed below.

Partnership oil and gas sales volumes are declining due to natural production declines from existing wells, combined with the fact that the Partnership is not drilling and has no plans to conduct additional drilling activity. Sales volumes declined by approximately 31.3% during the three month period ended September 30, 2011 compared to the three month period ended September 30, 2010. The HBR A Big Gas well (“HBR A”) experienced a 76.5% decline in gas volumes with the Partnership’s share of gas volumes declining from approximately 37,399 Mcf during the three months ended September 30, 2010 to approximately 8,773 Mcf during the three months ended September 30, 2011. The Partnership’s share of sales volumes from the two most significant wells in which the Partnership has an interest, the Rob L RA SUA CL&F #1 (“Gumbo II”) and the HBR A, totaled 6,871 barrels of crude oil and 41,398 Mcf of natural gas, or 93.3% and 72.05% of sales volumes for the three month period ended September 30, 2011, respectively. During the three month period ended September 30, 2010, the Partnership’s share of sales volumes from these two wells totaled 8,564 barrels of crude oil and 73,467 Mcf of natural gas, or 97.13% and 77.26% of the Partnership’s total sales volumes, respectively. Production from existing Partnership wells will continue to decline in future quarters. The economic life of the Partnership is dependent upon the lives of the most significant wells in which it participates. The current estimated reserve lives of the Gumbo II and HBR A wells are estimated to be approximately 51 and 27 months, respectively, using current prices and costs.

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As a result of the sales price for crude oil rising by 43.7%, to an average price of $88.99 per Bbl for the three month period ended September 30, 2011, compared to an average price of $61.92 for the three month period ended September 30, 2010, the overall decline in sales revenues was only $94,071, or 9% on a comparative basis. Gas prices were relatively stable on a comparative basis, averaging $5.22 per Mcf during the three month period ended September 30, 2011, compared to $5.30 per Mcf during the three month period ended September 30, 2010. There has been a drop in prices for both crude oil and natural gas during the third quarter, and fourth quarter average sales prices for both crude oil and natural gas are expected to be below the third quarter averages.

Lease operating costs decreased from $113,798 during the three months ended September 30, 2010 to $83,720 during the three month periods ended September 30, 2011. Decreases in ad valorem taxes were partially offset by increased marketing and gathering expenses, legal expenses, and direct labor costs. In addition, operating costs increased slightly during the three month period ended September 30, 2011 compared to the three month period ended September 30, 2010 because the converted Sand Dunes salt water disposal well, which was completed during August 2010, allowed seven Sand Dunes wells to return to producing status during the third and fourth quarters of 2010.

The Partnership incurred $194,482 of depletion, depreciation, and amortization expense during the three month period ended September 30, 2011 compared to $451,452 of depletion, depreciation, and amortization expense during the three month period ended September 30, 2010. The Partnerships’ depletable property basis entering 2011 was $1,998,602, compared to $3,600,860 entering 2010. While the decrease is primarily due to the reduced depletable basis of the Partnership, the combination of declining production rates and rising oil prices between the comparative periods have also led to a reduced depletion rate applied to the remaining basis.

General and administrative costs decreased from $121,969 incurred during the three months ended September 30, 2010 to $111,384 incurred during the three months ended September 30, 2011, due primarily to decreased legal fees during the comparative periods. The allocation of RELP’s overhead to partnerships is the largest factor in general and administrative expenses, and is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. The administrative overhead charge to the Partnership was relatively stable, decreasing from $78,049 for the three months ended September 30, 2010 to $77,316 for the three months ended September 30, 2011.

Nine months ended September 30, 2011 compared to the nine months ended September 30, 2010

Partnership net income rose from $987,110 for the nine month period ended September 30, 2010 to $1,583,274 for the nine month period ended September 30, 2011. The primary cause of this increase in net income is lower depletion, depreciation and amortization expenses as discussed below.

Partnership oil and gas sales volumes are declining due to natural production declines from existing wells, combined with the fact that the Partnership is not drilling and has no plans to conduct additional drilling activity. Sales volumes declined by approximately 31.4% during the nine month period ended September 30, 2011 compared to the nine month period ended September 30, 2010. The HBR A well experienced a 79.1% decline in gas volumes with the Partnership’s share of gas volumes declining from approximately 132,538 Mcf during the nine months ended September 30, 2010 to approximately 27,735 Mcf during the nine months ended September 30, 2011. The Partnership’s share of sales volumes from the two most significant wells in which the Partnership has an interest, the Gumbo II and the HBR A, totaled 21,985 barrels of crude oil and 127,613 Mcf of natural gas, or 93.7% and 69.9% of sales volumes for the nine month period ended September 30, 2011, respectively. During the nine month period ended September 30, 2010, the Partnership’s share of sales volumes from these two wells totaled 24,070 barrels of crude oil and 240,766 Mcf of natural gas, or 93.5% and 76.0% of the Partnership’s total sales volumes, respectively. Production from existing Partnership wells will continue to decline in future quarters. The economic life of the Partnership is dependent upon the lives of the most significant wells in which it participates. The current estimated reserve lives of the Gumbo II and HBR A wells are estimated to be approximately 51 and 27 months, respectively, using current prices and costs.

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As a result of sales prices for crude oil rising by 33.5%, to an average price of $90.31 per Bbl for the nine month period ended September 30, 2011, compared to an average price of $67.65 for the nine month period ended September 30, 2010, the overall decline in sales revenues was only $285,566, or 8.4% on a comparative basis. Gas prices were relatively stable on a comparative basis, averaging $5.42 per Mcf during the nine month period ended September 30, 2011, compared to $5.21 per Mcf during the nine month period ended September 30, 2010. The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations. There has been a drop in prices for both crude oil and natural gas during the third quarter, and fourth quarter average sales prices for both crude oil and natural gas are expected to be below the third quarter averages.

Lease operating costs decreased from $336,293 during the nine months ended September 30, 2010 to $294,029 during the nine month period ended September 30, 2011. Decreases in ad valorem taxes were partially offset by increased marketing and gathering expenses. In addition, operating costs increased slightly during the nine month period ended September 30, 2011 compared to the nine month period ended September 30, 2010 because the converted Sand Dunes salt water disposal well, which was completed during August 2010, allowed seven Sand Dunes wells to return to producing status during the third and fourth quarters of 2010.

Production taxes increased during the nine month period ended September 30, 2011 compared to the nine month period ended September 30, 2010 due to a one-time severance tax adjustment received from the operator of the Gumbo II well. During the second quarter of 2010 the Partnership received a severance tax credit from the operator of the Gumbo II well, because the well obtained a severance tax exemption from the State of Louisiana for the period of inception through February 2010. This one time tax adjustment resulted in the Partnership showing a negative amount for severance taxes during the second quarter of 2010, and skewed the production tax expense shown for the nine months ended September 30, 2010.

The Partnership incurred $612,840 of depletion, depreciation, and amortization expense during the nine month period ended September 30, 2011 compared to $1,475,542 of depletion, depreciation, and amortization expense during the nine month period ended September 30, 2010. The Partnerships’ depletable property basis at the beginning of 2011 was $1,998,602, compared to $3,600,860 at the beginning of 2010. While the decrease is primarily due to the reduced depletable basis of the Partnership, the combination of declining production rates and rising oil prices between the comparative periods have also led to a reduced depletion rate applied to the remaining basis.

General and administrative costs decreased from $497,708 incurred during the nine months ended September 30, 2010 to $370,703 incurred during the nine months ended September 30, 2011, primarily due to decreased overhead charges from RELP as well as decreased legal fees. The allocation of RELP’s overhead to partnerships is the largest factor in general and administrative expenses, and is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. The administrative overhead charge to the Partnership decreased from $304,696 for the nine months ended September 30, 2010 to $255,976 for the nine months ended September 30, 2011.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership is a “smaller reporting company” as defined by Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as such, is not required to provide the information required under this Item.

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Item 4T. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As the managing general partner of the Partnership, Reef maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Quarterly Report. Based on that evaluation, the principal executive officer and principal financial officer have concluded that the Partnership’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding financial disclosure.

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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Item 1A. Risk Factors

There were no material changes in the Risk Factors applicable to the Partnership as set forth in the Annual Report.

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

None.

Item 3. Default Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

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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.

	REEF GLOBAL ENERGY VI, L.P.

	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner

	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner


Dated: November 10, 2011	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)


Dated: November 10, 2011	By:	/s/ Daniel C. Sibley
		Daniel C. Sibley
		Chief Financial Officer and General Counsel of
		Reef Exploration, L.P.
		(Principal Financial and Accounting Officer)

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EXHIBIT INDEX

Exhibits

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

Reef Global Energy VI, L.P. 10-Q