UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2010~~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 No. 000-51266

RIDGEWOOD ENERGY K FUND, LLC

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

68-0580588

(I.R.S. Employer

Identification No.)

14 Philips Parkway, Montvale, NJ 07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

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

Shares of LLC Membership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

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 o x No o

Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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 (Do not check if a smaller reporting company)	o	Smaller reporting company	x

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

There is no market for the shares of LLC Membership Interest in the Fund. As of March 151, ~~2011~~2012 there are 480.7046 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY K FUND, LLC

~~2010~~2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	9
	ITEM 1B	UNRESOLVED STAFF COMMENTS	9
	ITEM 2	PROPERTIES	9
	ITEM 3	LEGAL PROCEEDINGS	10
	ITEM 4	~~(REMOVED~~MINE ~~AND~~SAFETY ~~RESERVED)~~DISCLOSURES	10
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	1110
	ITEM 6	SELECTED FINANCIAL DATA	1110
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1110
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	15
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	15
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	15
	ITEM 9A	CONTROLS AND PROCEDURES	1615
	ITEM 9B	OTHER INFORMATION	16
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	16
	ITEM 11	EXECUTIVE COMPENSATION	18
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	18
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	18
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	1918
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	1918
		SIGNATURES	20

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FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy K Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections, statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995 that are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations. Examples of forward-looking statements made herein include statements regarding future projects, investments and insurance. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

WHERE YOU CAN GET MORE INFORMATION

The Fund files annual, quarterly and current reports and certain other information with the Securities and Exchange Commission (“SEC”). Persons may read and copy any materials the Fund files with the SEC at the SEC’s public reference room at 100 F Street, NE, Washington D.C. 20549 on official business days during the hours of 10 a.m. to 3 p.m. Eastern Time. Information may be obtained from the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

Table of Contents

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on March 1, 2004 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on April 1, 2004, selling whole and fractional shares of LLC membership interests (“Shares”) primarily at $150 thousand per whole Share. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund's limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on August 1, 2004. The Fund raised $70.9 million and after payment of $11.1 million in offering fees, commissions and investment fees, the Fund had $59.8 million for investments and operating expenses.

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project ~~investments~~investment, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions in which the investments are made. This includes review of existing title documents, reserve information, and other technical specifications regarding a project, and review and preparation of participation agreements and other agreements relating to an investment. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Form 10-K.

The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required.

The Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing and printing periodic reports for shareholders and the SEC, commission fees, taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses. The Fund is required to reimburse the Manager for all such expenses paid on its behalf.

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund.

The Manager is entitled to a 15% interest in cash distributions made by the Fund. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.

Business Strategy

The Fund’s primary investment objective ~~has~~is ~~been~~ to generate cash flow for distribution to its shareholders ~~through~~by ~~the~~generating ~~acquisition~~returns ofacross ~~working~~a ~~interests~~portfolio inof ~~the~~exploratory ~~exploration,~~or ~~production~~development ~~and sale of~~ oil and natural gas. projects. Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion, subject to available cash from operations, reserve requirements and Fund operations. A working interest is a percentage of ownership in an oil and natural gas lease granting its owner the right to explore, drill and produce oil and natural gas from projects on that lease block. The Fund has focused on projects that have significant reserve potential and are projected to have the shortest time period from investment to first production. The Fund does not operate these projects, and although it has a vote, it is not in control of the schedule pursuant to which its projects are developed and completed. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well. After royalties are paid, the working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of working interest owned.

Table of Contents

ByInvestment virtue of its acquisition of working interests in various leases, the Fund invests and participates in exploration and production of oil and natural gas projects in leases located in the waters of the Gulf of Mexico on the Outer Continental Shelf (“OCS”). These activities are governed by the Outer Continental Shelf Lands Act (“OCSLA”) enacted in 1953 and administered by the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) (formerly the Mineral Management Services). The Fund generally has looked to invest in working interests that have been proposed by larger independent oil and natural gas companies seeking to minimize their risks by selling a portion of their interest in the working interest. For certain of the Fund’s investments, the Fund may have paid the operator a “promote” on the cost of an initial exploratory well, representing a larger share of the drilling costs. In addition, notwithstanding the sale of an interest to the Fund, the seller may retain a right for some period of time to payments from sales of oil and natural gas production from a well or project. This is called an overriding interest, which is also common in this industry. Notwithstanding any such promote or overriding interest, the Fund has invested in projects that it believes contain sufficient commercial quantities of oil or natural gas and which are near existing oil or natural gas gathering and processing infrastructure and developed markets where the Fund can sell its oil or natural gas.Strategy

~~For~~The ~~project~~Fund ~~investments~~invests its capital with operators through working interest joint ventures with such operators and, in some cases, other energy companies that also own or acquire working interests in the ~~Manager~~projects. A ~~reviews~~working ~~reserve~~interest ~~analyses~~is ~~provided~~an byundivided fractional interest in a lease block acquired from the ~~operators~~U.S. government or from an operator that has acquired the working interest. ~~The~~A ~~Manager~~working ~~employs~~interest ~~individuals~~includes the right to drill, produce and conduct operating activities and share in ~~its~~any ~~Houston~~resulting oil and natural gas production. Operators will generally retain 25% to 50% interests in multiple drilling projects, ~~Texas~~rather ~~office~~than 100% interests in a few projects, in order to share risk, obtain independent technical validation and stretch exploration budgets that ~~can~~are ~~perform~~split ~~significant~~across ~~analysis~~numerous regions of the world. Ridgewood Energy evaluates each project and its operator’s ~~information. However,~~on ifan ~~necessary~~individual project basis, allowing the Fund ~~may~~to ~~retain~~invest ~~independent~~in ~~engineers~~what Ridgewood Energy believes are the projects with the most attractive risk/reward ratios. Critical to ~~review~~the success of this approach is the ~~operator~~ability of Ridgewood Energy to diversify the Fund’s ~~reserve~~portfolio across project types and operators. Attributes sought in projects for investment include: depth of scientific analysis and preparation; strong potential project economics and favorable operating agreement terms; similarity to existing producing properties; and expertise of the operator in the proposed region/orgeology/technical ~~conduct~~environment. Attractive ancharacteristics ~~independent~~of ~~review~~potential and existing operators include industry contacts and relationships, sophisticated geological and geophysical teams and a strong track record of success. For ~~producing~~certain ~~properties~~of the Fund’s investments, the ~~Manager~~Fund ~~engages~~may ~~independent~~pay ~~petroleum~~the ~~engineers~~operator toa ~~examine~~“promote” ~~and~~on ~~provide~~the ~~reserve~~cost ~~estimates~~of onthe initial exploratory well, representing a larger share of the drilling costs. For a successful well, all of the Fund’s ~~behalf~~subsequent costs, including completion costs for the exploratory well, the costs of all development wells, infrastructure costs such as production platforms and pipelines, and day-to-day operating costs for the life of the project, would be paid on a proportionate basis to its working interest ownership.

~~Once~~Investment the Manager determines that a particular project (i.e., working interest in a lease block) is an appropriate investment for the Fund, the Manager enters into a participation agreement and a joint operating agreement with the other working interest owners in a lease. Pursuant to the participation agreements and operating agreements, proposals and decisions are made based on percentage ownership approvals.Process

~~The~~Although ~~Manager,~~Ridgewood onEnergy’s ~~behalf~~model of ~~the~~investing ~~Fund,~~fund ~~and~~capital ~~other~~with ~~working~~operators ~~interest~~affords ~~owners~~it ~~retain~~access ~~the right~~ to ~~make~~industry-leading ~~proposals~~technical ~~involving~~and ~~certain~~engineering ~~operational~~resources, ~~matters~~Ridgewood ~~associated~~Energy ~~with~~performs aits ~~project. This~~own ~~limits~~due ~~the~~diligence ~~operator’s inclination to act~~ on, ~~its~~and ~~own~~independently orevaluates, ~~against~~all ~~the interests~~ of the ~~other~~projects ~~working~~in ~~interest~~which ~~owners~~the ofFund ~~the~~may ~~project~~invest. InRidgewood ~~accordance~~Energy ~~with~~conducts ~~the~~an ~~Manager’s~~initial ~~working~~screening ~~interest,~~process ~~the Manager reviews, discusses and consents~~ to ~~the~~identify ~~details~~new ofproject ~~the~~investment ~~drilling~~opportunities ~~plan,~~and ~~monitors~~is ~~progress~~selective ~~under~~as ~~such plan, contributes ideas~~ to ~~the~~which ~~design~~projects ofit ~~and~~pursues. Key ~~budget~~criteria ~~for~~that ~~production~~form ~~facilities~~part ~~and~~of ~~then monitors~~ the ~~construction~~detailed ofevaluation ~~those~~include ~~facilities. In addition,~~ the ~~Manager~~identity ~~retains~~of the ~~right~~operator ~~to review~~ and ~~audit~~other ~~the~~partners, ~~operator’s financial records related to~~ the ~~project~~technical toquality ~~ensure~~of the project, isaccess ~~executed according~~ to ~~budget. Once~~existing ~~a well is in production~~infrastructure, ~~the~~drilling ~~Manager~~schedule ~~continually~~and ~~monitors,~~rig ~~evaluates~~availability and ~~discusses~~project ~~the~~economics ~~well~~and ~~production rate with the operator~~terms.

Ridgewood Energy maintains an investment committee consisting of five members, which provides operational, financial, scientific and technical oil and gas expertise to the Fund (the “Investment Committee”). Four members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and one member is based out of the Manager’s Houston, Texas office. Once the technical and economic analyses of a potential project are complete and a project has been deemed to satisfy Ridgewood Energy’s technical criteria, provide an attractive economic risk/reward ratio, and fit within Ridgewood Energy’s diversification strategy, final investment approval is made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee seeks to balance the economics of the projects, the potential sizes of the projects, project location, the diversity of the operators, and the likely timing of new projects. The Investment Committee also considers the geological, financial and operating risks of the proposed project and compares these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further focuses on the initial well cost relative to the overall revenue potential of the project.

~~The~~Participation ~~Manager maintains an investment committee, consisting of five members, which provides operational, financial, scientific~~ and ~~technical~~Joint ~~oil~~Operating and gas expertise to the Fund (the “Investment Committee”). Four members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and one member is based out of the Manager’s Houston, Texas office. Once the technical and economic analyses of a potential project were complete and a project was deemed to satisfy Ridgewood Energy’s technical criteria, provided an attractive economic risk/reward ratio, and fit within Ridgewood Energy’s diversification strategy, final investment approval was made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee sought to balance the economics of the projects, the potential sizes of the projects, the diversity of the operators, and the likely timing of new projects. The Investment Committee also considered the geological, financial and operating risks of the proposed project and compared these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further focused on the initial well cost relative to the overall revenue potential of the project.Agreements

~~Post-Investment~~Once ~~Activities~~Ridgewood Energy decides that a project is an appropriate investment for the Fund, the Fund will seek to enter into participation and joint operating agreements with the other working interest owners in a lease. Ridgewood Energy negotiates these agreements with the goal of achieving the best possible economics and governance rights for the Fund in connection with acquiring the interest. Under the joint operating agreement, proposals and decisions are made based on percentage ownership approvals and although an operator’s percentage ownership may constitute a majority ownership, operators generally seek consensus relating to project decisions. As a result, Ridgewood Energy and other partners generally retain the right to make proposals and influence decisions involving certain operational matters associated with a project. This approval discretion and the operator’s desire to execute the project efficiently and expeditiously can function to limit the operator’s inclination to act on its own, or against the interests of the participants in the project.

The Fund has reached the end of its project investment cycle. All of the projects in which the Fund owns a working interest are currently producing, have been determined to be dry holes or have been fully depleted. The Investment Committee continually evaluates the production rates of the Fund’s producing wells and takes steps to ensure that optimal prices are obtained for the oil and natural gas produced by the Fund’s wells.

Project Information

Existing projects, and future projects, if any, are located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The OCSLA governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS. See further discussion under the heading “Regulation” in Item 1. “Business” of this Annual Report.

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~~Leases~~Project in the OCS are generally issued for a primary lease term of 5, 8 or 10 years depending on the water depth of the lease block. The 5-year lease term is for blocks in water depths generally less than 400 meters, 8 years for depths between 400 meters and 800 meters and 10 years for depths in excess of 800 meters. During a primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.Information

~~The~~Existing ~~lessee~~projects, ofand afuture ~~particular block~~projects, ~~for~~if ~~the~~any, ~~term~~are oflocated in the ~~lease,~~waters ~~has~~of the ~~right~~Gulf toof ~~drill~~Mexico ~~and~~offshore ~~develop~~from ~~exploratory~~Texas, ~~wells~~Louisiana and ~~conduct~~Alabama, ~~other~~on ~~activities throughout~~ the ~~block.~~Outer IfContinental ~~the~~Shelf ~~initial~~(“OCS”). ~~well~~The onOuter ~~the~~Continental ~~block~~Shelf isLands ~~successful,~~Act ~~a lessee~~(“OCSLA”), orwhich ~~third-party~~was ~~operator~~enacted ~~for~~in ~~a project~~1953, ~~may~~governs ~~conduct~~certain ~~additional~~activities ~~geological~~with ~~studies~~respect ~~and may determine~~ to ~~drill~~working ~~additional~~interests orand ~~development wells. If a development well is to be drilled in~~ the ~~block,~~exploration ~~each~~of ~~lessee~~oil ~~owning~~and ~~working~~natural ~~interests~~gas in the ~~block~~OCS. See ~~must~~further bediscussion ~~offered~~under the ~~opportunity~~heading to“Regulation” ~~participate~~ in, ~~and~~this ~~cover~~Item ~~the~~1. ~~costs~~“Business” of, ~~the~~this ~~development~~Annual ~~well up to that particular lessee’s working interest ownership percentage~~Report.

Leases in the OCS are generally issued for a primary lease term of 5, 8 or 10 years, depending on the water depth of the lease block. During a primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee, or third-party operator for a project, may conduct additional geological studies and may determine to drill additional exploratory or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee’s working interest ownership percentage.

Royalty Payments

Generally, working interests in an offshore oil and natural gas lease under the OCSLA pay a 12.5%, 16.67% or 18.75% royalty to the ~~BOE~~Bureau ~~for~~of ~~shallow-water~~Ocean ~~projects,~~Energy ~~dependent~~Management ~~upon the lease date, and a 12~~(“BOEM”).5% ~~royalty to the BOE for deepwater projects.~~ Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 8387.335% of the total revenue, ~~for~~depending ~~shallow-water~~on ~~projects~~the ~~and~~nature ~~87.5%~~ of the ~~total~~project. The ~~revenue for deepwater projects, and, such~~ net revenue ~~amount~~interest is further reduced by any other royalty burdens that apply to a lease block, such as those imposed by override interest owners. However, as described below, the BOEM has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects. Other than ~~BOE~~BOEM royalties, the Fund does not have material royalty burdens.

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned an interest as of December 31, ~~2010~~2011. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund ~~has~~owns ana working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

	Total Productive Wells
	Gross		Net	~~Net~~
Oil and natural gas		43		0.19	~~0.22~~

Acreage Data

The following table sets forth the Fund’s interests in developed oil and gas acreage as of December 31, ~~2010~~2011. The Fund did not have any interests in undeveloped oil and gas acreage as of December 31, ~~2010~~2011. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and gas leases that have varying terms. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

Developed Acres
Gross		Net
	12,161		831

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Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table.

			~~Total Spent~~		Total Spent		~~Total~~		Total
	Working		~~through~~		through		~~Fund~~		Fund
Lease Block	Interest		~~December 31, 2010~~		December 31, 2011		~~Budget~~		Budget	~~Status~~	Status
			~~(in thousands)~~		(in thousands)
Producing Properties
Non-producing Properties
South Marsh Island 111	3.75%		$	1,031			$	1,204		Production commenced February 2009. Recompletion efforts to access behind the pipe reserves are expected to commence in March 2011 at an estimated cost of $0.2 million.
Falcon Project		4.50%			$	2			$	1,258	Acquired interest in July 2011. Drilling expected to commence in second quarter 2012.
West Delta 67	3.75%		$	569			$	569		Production commenced in 2008. Recompletion activities completed in July 2010 and December 2010 at a total cost of $0.1 million.
Producing Properties
West Delta 68	3.75%		$	897			$	903		Production commenced in 2008. Recompletion activities completed in July 2010 and January 2011 at a total cost of $0.1 million. Additional recompletion planned for 2013 at an estimated cost of $6 thousand.
South Marsh Island 111		3.75%			$	1,183			$	1,187	Production commenced in 2009. Recompletion efforts to access behind the pipe reserves commenced in April 2011 and completed in May 2011 at a cost of $0.2 million. Well was shut-in for pipeline maintenance from August 2011 through late-October 2011. Minor recompletion is also planned for 2013 at an estimated cost of $4 thousand.
West Cameron 76 A-1	~~11.24%~~	11.24%	$	~~1,781~~	$	1,781	$	~~1,781~~	$	~~Production commenced in 2007.~~2,129	Production commenced in 2007. Recompletion efforts to access behind the pipe reserves are planned for 2012 at an estimated cost of $0.3 million.
Fully Depleted
West Delta 68		3.75%			$	888			$	892	Production commenced in 2008. Recompletion planned for 2014 at an estimated cost of $4 thousand.
2010
Fully Depleted
East Cameron 299	10.00%		$	6,020				N/A		Determined to be fully depleted at December 31, 2010.
West Delta 67		3.75%			$	563				N/A	Production commenced in 2008. Determined to be fully depleted during second quarter 2011.
West Cameron 556	20.00%		$	11,604				N/A		Determined to be fully depleted at December 31, 2010.
East Cameron 299		10.00%			$	6,052				N/A	Determined to be fully depleted at December 31, 2010.
2009
West Cameron 556		20.00%			$	11,800				N/A	Determined to be fully depleted at December 31, 2010.
Vermilion 344	3.75%		$	1,223				N/A		Determined to be fully depleted at December 31, 2009.

In April 2010, the Deepwater Horizon, which was drilling a BP-operated project in the deepwater of the Gulf of Mexico, sank after an apparent blowout and fire. As of the date of this filing, the well has been permanently capped and environmental remediation efforts are ongoing. Neither the Fund nor any operators of the Fund’s projects owns an interest in the affected field. As a result of the explosion and resultant oil spill, the U.S. government placed a six-month moratorium on deepwater drilling operations in the Gulf of Mexico, which was lifted effective October 12, 2010. The U.S. government has also implemented additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico. The extent to which these recent events may impact the Fund’s future results is uncertain. The Fund cannot predict how federal and state authorities will further respond to the incident or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. Such changes, if any, may impact the way the Fund conducts business and may increase the Fund’s cost of doing business.

Marketing/Customers

~~During~~The ~~2010~~Manager, on behalf of the Fund, ~~had~~has engaged aEnergy ~~third-party~~Upgrade, ~~marketer~~Inc. to sell the Fund’s ~~proportionate share of~~ oil and natural gas. Currently, tothe Fund has five major customers in the public market. ~~The~~ Because ~~Fund~~a ~~did~~ready ~~not~~market ~~contract~~exists tofor ~~sell~~ oil and natural gas ~~to customers and therefore~~, ~~had~~the noFund ~~customers~~does ornot ~~any~~believe ~~one~~that orthe ~~few~~loss ~~major~~of ~~customers~~any ~~upon~~individual ~~which~~customer itwould ~~depends. Effective~~have ~~December~~a ~~2010,~~material ~~the~~adverse ~~Fund~~effect ~~sells~~on its ~~oil~~financial ~~and~~position ~~gas~~or ~~through~~results anof ~~agent, Energy Upgrade, Inc~~operations.

The Fund’s current projects are near existing transportation infrastructure and pipelines. The Manager believes that it is likely that oil and natural gas from the Fund’s future projects will have access to pipeline transportation and can be marketed through ~~its~~Energy ~~agent~~Upgrade, Inc.

Natural gas is sold in the spot market at prevailing prices, which fluctuate with demand as a result of related industry variables. Oil is generally sold one month at a time at prevailing market prices. Historically, the markets for, and prices of, oil and natural gas have been extremely volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence; therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse ~~affect~~effect on the Fund’s future profitability. In the past, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production.

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Seasonality

Generally, the Fund's business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund's oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is producing, the operator of the project extracts oil and natural gas reserves throughout the year. Once extracted, oil and natural gas can be sold at any time during the year.

The Fund’s properties are located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any damage or shut-ins, or production stoppages, due to hurricane activity in 2010.5

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Operator

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's producing properties are operated by LLOG Exploration Offshore, Inc. and BHP Billiton Petroleum Ltd.

Because the Fund does not operate any of the projects in which it has acquired ana working interest, shareholders not only bear the risk that the Manager will be able to select suitable projects, but also that, once selected, such projects will be managed prudently, efficiently and fairly by the operators.

Insurance

The Manager has obtained what it believes to be adequate insurance for the funds that it manages. The Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to the projects. Further, for the policy periods August 2009 through July 2010 and August 2010 through July 2011, the Manager did not obtain coverage for named windstorm. As a result of the losses underwriters incurred from claims arising from Hurricane Ike, a named windstorm in September 2008, the Manager determined that the premiums sought by underwriters for, and the deductibles applicable to, coverage for named windstorm made obtaining such coverage for such policy period prohibitively expensive. In addition, the Manager's past practice has been to obtain insurance as a package that is intended to cover most, if not all, of the funds under its management. The Manager re-evaluates the insurance coverage on an annual basis. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims to the Fund's affiliates, yearly insurance limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.

Salvage Fund

As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for the Fund’s proportionate share of the anticipated cost of dismantling production platforms and facilities, plugging and abandoning the wells, and removing the platforms, facilities and wells in respect of the projects after the end of their useful lives, in accordance with applicable federal and state laws and regulations. The Fund has deposited $1.0 million from capital contributions into a salvage fund, which, along with interest earned on this account, the Fund currently estimates to be sufficient to meet the Fund’s potential requirements. If, at any time, the Manager determines the salvage fund will not be sufficient to cover the Fund’s proportionate share of expense, the Fund may transfer amounts from capital contributions or operating income to fund the deficit. ~~Payments~~Further contributions to the salvage fund ~~will~~may reduce the amount of cash distributions that may be made to investors by the Fund. Any portion of a salvage fund that remains after the Fund pays its share of the actual salvage cost will be distributed to the shareholders. There are no legal restrictions on the withdrawal or use of the salvage fund.

Competition

Strong competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. Although the Fund itself does not compete for lease acquisitions from the ~~BOE~~BOEM, it does compete with other companies for the acquisition of percentage ownership interests in oil and natural gas working interests in the secondary market.

In many instances, the Fund competes for working interests in projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and may have more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position to outbid the Fund. Nevertheless, the Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, and (ii) Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint.

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In many instances, the Fund competes for projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position that they could outbid the Fund for a project. However, because these companies are larger and have significant resources, they tend to focus more on projects that are larger, have greater reserve potential, and cost significantly more to explore and develop. The focus of these companies on larger projects does not necessarily mean that they will not investigate and/or acquire projects for which the Fund typically competes. The Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, (ii) Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint, and (iii) Ridgewood Energy is typically not viewed as a competitor by the syndicating operator, as Ridgewood Energy does not participate in lease block sales but principally invests in drill-ready syndicated projects.

Employees

The Fund has no employees as the Manager operates and manages the Fund.

Offices

The principal executive office of ~~each~~both of the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at ~~11700~~1254 ~~Old~~Enclave ~~Katy Road~~Parkway, Houston, TX ~~77079~~77077. In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.

Regulation

Oil and natural gas exploration, development and production activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled and the plugging and abandoning of projects are also subject to regulations.

The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations. The Fund may own interests in properties located in state waters of the Gulf of Mexico, for which such states regulate drilling and operating activities by requiring, among other things, drilling permits, ~~and~~ bonds and reports concerning operations. The laws of such states also govern a number of environmental and conservation matters, including the handling and disposing of waste materials, unitization and pooling of natural gas and oil properties, and the levels of production from natural gas and oil wells.

Outer Continental Shelf Lands Act

Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the ~~BOE~~BOEM, an agency of the United States Department of Interior. ~~The~~Federal ~~BOE~~offshore ~~administers~~leases ~~federal~~are ~~offshore~~managed ~~leases~~both by the BOEM and the Bureau of Safety and Environmental Enforcement pursuant to regulations promulgated under the OCSLA. Lessees must obtain ~~BOE~~ approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The Fund is not involved in the process of obtaining any such approvals or permits. Offshore operations are subject to numerous regulatory requirements, including stringent engineering and construction specifications related to offshore production facilities and pipelines and safety-related regulations concerning the design and operating procedures of these facilities and pipelines. ~~BOE~~Regulations ~~regulations~~ also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

Offshore operations are subject to regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Under certain circumstances, operations on federal leases may be suspended or terminated. Any such suspension or termination could adversely affect the Fund’s operations and interests.

The BOEM conducts auctions for lease blocks of submerged areas offshore. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the duration of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a limited degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.

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The BOE has also imposed regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Under certain circumstances, the BOE may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect the Fund’s operations and interests.

The BOE conducts auctions for lease blocks of submerged areas offshore. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the duration of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a limited degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.

Sales and Transportation of Oil and Natural Gas

The Fund sells its proportionate share of oil and natural gas to the market through ana ~~agent~~marketer or a joint operating agreement and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). The rates, terms and conditions are regulated by FERC pursuant to a variety of statutes, including the OCSLA, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different than the impact upon other oil or natural gas producers and marketers.

Environmental Matters and Regulation

The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water and the protection of aquatic species and habitats. However, although it shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that may be caused by the Fund’s projects.

Some of the environmental laws that apply to oil and natural gas exploration and production are described below:

The Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez spill, that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to, and increases penalties for, such spills. The OPA establishes a new liability regime for oil pollution incidents in the aquatic environment. Essentially, the OPA provides that a responsible party for a vessel or facility from which oil is discharged or that poses a substantial threat of a discharge could be liable for certain specified damages resulting from a discharge of oil, including clean-up and remediation, loss of subsistence use of natural resources, real or personal property damages, as well as certain public and private damages. A responsible party includes a lessee of an offshore facility.

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages. In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier, the Fund has not been required to make any such showing to the ~~BOE~~BOEM, as the operators are responsible for such compliance. However, notwithstanding the operators’ responsibility for compliance, in the event of an oil spill, the Fund, along with the operators and other working interest owners, could be liable under the OPA for the resulting environmental damage.

Clean Water Act. Generally, the Clean Water Act imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal, or state, if applicable, agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

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Federal Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act.

Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act of 1976, as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation and Liability Act, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment.

The above represents a brief outline of the significant environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated thereunder. The Fund does not believe that the costs of compliance with applicable environmental laws, including federal, state and local laws, will have a material adverse impact on its financial condition and/or operations.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

The information regarding the Fund’s properties that is contained in Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties,” is incorporated herein by reference.

Drilling Activity

The ~~following~~Fund ~~table~~had ~~sets~~no ~~forth the Fund’s~~ drilling activity ~~for~~during the years ended December 31, ~~2010~~2011 and 2009. Gross wells are the total number of wells in which the Fund has an interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico. During the years ended December 31, 2010 ~~and 2009, the Fund had no drilling activity for developmental wells~~.

	2010				2009
	Gross		Net		Gross		Net
Exploratory wells:
Productive		-		-		1		0.04
Nonproductive		-		-		-		-
In-progress		-		-		-		-
Exploratory well total		-		-		1		0.04

Unaudited Oil and Gas Reserve Quantities

The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation. The Fund’s management controls over proved reserve estimation include: 1) verification of input data that is provided to an independent petroleum engineering firm,; 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines; and 3) a review of the reserve estimates by the Manager.

The Manager’s primary technical person in charge of overseeing the Fund’s reserves estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over twenty years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation of exploration and development opportunities, and the oversight of drilling and production operations.

The Fund’s reserve estimates at December 31, 2011 and 2010 were prepared by Ryder Scott Company, L.P., (“Ryder Scott”) an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from Ryder Scott, which is filed as Exhibit 99 to this Annual Report, and is incorporated herein by reference.

Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The information regarding the Fund’s proved reserves, which is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Critical Accounting Estimates – Proved Reserves”, is incorporated herein by reference. The information regarding the Fund’s unaudited net quantities of proved developed and undeveloped reserves, which is contained in Table III in the “Supplementary Financial Information – Information about Oil and Gas Producing Activities – Unaudited” included in Item 15. “Exhibits, Financial Statement Schedules” of this Annual Report, is incorporated herein by reference.

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~~The~~Proved ~~primary~~Undeveloped ~~technical person in charge of overseeing the Fund’s reserves estimates has a B~~Reserves.S. ~~degree~~At inDecember ~~Petroleum~~31, ~~Engineering~~2011 and ~~is a member of the Society of Petroleum Engineers~~2010, the ~~Association~~Fund ofhad ~~American~~no ~~Drilling~~proved ~~Engineers~~undeveloped ~~and~~oil ~~the American Petroleum Institute. With over twenty years of industry experience, he is currently responsible for reserve reporting, engineering~~ and ~~economic~~natural ~~evaluation~~gas ~~of exploration and development opportunities, and the oversight of drilling and production operations~~reserves.

The Fund’s reserve estimates at December 31, 2010 and 2009 were prepared by Ryder Scott Company, L.P., (“Ryder Scott”) an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from Ryder Scott, which is included as Exhibit 99 of this Annual Report, and is incorporated herein by reference.

Proved Undeveloped Reserves. At December 31, 2010, the Fund had no proved undeveloped oil and natural gas reserves. At December 31, 2009, the Fund had approximately 400 barrels and 80 thousand mcf of proved undeveloped oil and natural gas reserves, respectively, attributable to South Marsh Island 111. During 2010, the Fund determined it was not economical to proceed with the development of the proved undeveloped oil and natural gas reserves related to South Marsh Island 111.

Production and Prices

The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, ~~2010~~2011 and ~~2009~~2010 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – ~~Oil and Gas Revenue~~Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference.

Delivery Commitments

As of December 31, ~~2010~~2011, the Fund had no obligations or delivery commitments under any existing contracts.

ITEM 3. LEGAL PROCEEDINGS

On August 16, 2006, the Manager of the Fund filed a lawsuit against the former independent registered public accounting firm for the Fund, Perelson Weiner, LLP, (“Perelson”) in New Jersey Superior Court, captioned Ridgewood Energy Corporation vNone. Perelson Weiner, LLP, Docket No. L-6092-06. The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Fund by Perelson. Thereafter, Perelson filed a counterclaim against the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. During May 2010, a settlement was reached by the parties at no cost to the Fund. Legal costs related to this claim were borne by the Manager.

ITEM 4. ~~(REMOVED~~ MINE ~~AND~~SAFETY ~~RESERVED)~~DISCLOSURES

10None.

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is currently no established public trading market for the Shares. As of the date of this filing, there were ~~856~~857 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash as defined in the LLC Agreement, for distribution to shareholders. There is, however, no requirement to distribute available cash and as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. ~~During~~The Fund did not pay distributions during the ~~years~~year ended December 31, ~~2010~~2011. During ~~and~~the ~~2009~~year ended December 31, 2010, the Fund paid distributions to shareholders totaling $0.4 million ~~and $2~~.~~1 million, respectively.~~

ITEM 6.

SELECTED FINANCIAL DATA

Not required.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of the Fund’s Business

The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects. However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.

The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing management, administrative and advisory services associated with these projects. The Fund does not currently, nor is there any plan to operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as appropriate. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.

Revenues are subject to market pricing for oil and natural gas, which has been volatile, and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability.10

Critical Accounting Estimates

The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented. The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position, or cash flows. See Note 2 of Notes to Financial Statements – “Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of the Fund’s significant accounting policies.

Accounting for Exploration and Development Costs

Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and dry-hole costs are expensed as incurred. Costs of drilling and equipping productive wells and related production facilities are capitalized.

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Critical Accounting Estimates

The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented. The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of the Fund’s significant accounting policies.

Accounting for Exploration, Development and Acquisition Costs

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Annual lease rentals, exploration expenses and dry-hole costs are expensed as incurred.

The costs of exploratory and developmental wells are capitalized pending determination of whether proved reserves have been found. Drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are expensed as dry-hole costs. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel; active negotiations for sales contracts with customers; negotiations with governments, operators and contractors; and firm plans for additional drilling and other factors.

Unproved Property

Unproved property is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination. These costs are excluded from the depletion base until the outcome of the project has been determined, or generally until it is known whether proved reserves will or will not be assigned to the property. The Fund assesses all items in its unproved property balance on an ongoing basis for possible impairment or reduction in value.

Proved Reserves

Annually, the Fund engages an independent petroleum engineer, Ryder Scott, to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording ~~depreciation,~~ depletion and amortization.

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Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, a liability is recognized for the present value of asset retirement obligations once reasonably estimable. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of its proved properties. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.

Impairment of Long-Lived Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the end of each period. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, ~~2010~~2011 and ~~2009~~2010, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” ~~contained~~ in this Annual Report.

	Year ended December 31,
	2011			2010
	(in thousands)
Revenue
Oil and gas revenue	$	334		$	948
Expenses
Depletion and amortization		197			688
Impairment of oil and gas properties		(65	)		2,985
Dry-hole costs		(62	)		(3	)
Operating expenses		128			553
General and administrative expenses		197			270
Total expenses		395			4,493
Loss from operations		(61	)		(3,545	)
Interest income		29			30
Net loss	$	(32	)	$	(3,515	)

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 2011 and 2010.

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	Year ended December 31,
	2010			2009
	2011			2010
	(in thousands)
Number of wells producing		4			6
Revenue
Total number of production days		867			1,436
Oil and gas revenue	$	948		$	2,385
Average mcfe per production day		56			120
Expenses
Oil sales (in thousands of barrels)		1			2
Depletion and amortization		688			2,895
Average oil price per barrel	$	105		$	78
Impairment of oil and gas properties		2,985			2,394
Gas sales (in thousands of mcfs)		34			146
Operating expenses		550			613
Average gas price per mcf	$	4.11		$	4.89
General and administrative expenses		270			273
Total expenses		4,493			6,175
Loss from operations		(3,545	)		(3,790	)
Other income
Interest income		30			44
Net loss	$	(3,515	)	$	(3,746	)

~~Overview.~~ The ~~Fund’s~~decreases ~~revenue,~~in ~~depletion~~production ~~and amortization~~days, ~~and~~average ~~lease~~production ~~operating~~rate ~~expense~~and ~~were~~oil ~~affected~~and bygas ~~the~~volumes ~~timing~~were ofprincipally ~~the~~attributable ~~onset~~to ~~of production of~~ the ~~Fund’s~~number ~~wells and by the impact~~ of ~~well~~productive ~~maintenance activities~~wells. ~~During~~One ~~the~~of ~~year ended December 31, 2010,~~ the Fund’s ~~had six~~ wells ~~that~~was ~~produced~~determined ~~for a total of 1,436 days, compared~~ to ~~seven wells~~be ~~that~~fully ~~produced~~depleted ~~for a total of 2,038 days~~ during the ~~year~~second ~~ended~~quarter ~~December~~2011 ~~31,~~and ~~2009. The~~two ~~decrease in total production days was the result~~ of ~~one of~~ the Fund’s wells ~~being~~were ~~fully~~determined ~~depleted at December 31, 2009 coupled with increased non-productive days related~~ to ~~maintenance~~be ~~activities. During~~fully ~~the~~depleted ~~year~~at ~~ended~~ December 31, 2010,. See ~~the~~Item ~~Fund's~~1. ~~wells'~~“Business” ~~production~~of ~~rate~~this ~~averaged~~Annual ~~120~~Report ~~mcfe/producing~~under ~~day, compared to 262 mcfe/producing day during~~ the ~~year~~heading ~~ended~~“Properties” ~~December 31, 2009. The decrease was primarily related to natural declines in production~~ for ~~two~~more ~~of the Fund’s wells, which were determined to be fully depleted at December 31, 2010~~information.

Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, ~~2010~~2011 was $0.93 million, a $10.46 million decrease from the year ended December 31, ~~2009~~2010. The decrease is primarily attributable to ~~the impact of~~ decreased sales volumes ~~totaling $1~~.~~6 million, partially offset by the impact of increased average prices totaling $0.2 million.~~

~~Oil~~Depletion ~~sales~~and ~~volumes~~Amortization. Depletion ~~were 2 thousand barrels~~ and 5amortization ~~thousand barrels~~ for the ~~years~~year ended December 31, ~~2010~~2011 ~~and~~was ~~2009, respectively~~$0. ~~The~~2 ~~Fund’s~~million, ~~oil~~a ~~prices~~decrease ~~averaged~~of $780.5 ~~per~~million ~~barrel~~from ~~during~~ the year ended December 31, 2010. The ~~compared~~decrease toresulted ~~$53~~primarily ~~per~~from ~~barrel~~a ~~during~~decrease ~~the~~in ~~year~~production ~~ended December 31, 2009~~volumes.

Impairment of Oil and Gas ~~sales~~Properties. During ~~volumes~~the ~~were~~year ~~146~~ended ~~thousand~~December ~~mcf~~31, 2011, the Fund recorded credits to impairment of oil and ~~492~~gas ~~thousand~~properties ~~mcf~~totaling $0.1 million, which were primarily attributable to revisions to cost estimates for fully depleted wells. During the ~~years~~year ended December 31, 2010 ~~and 2009~~, ~~respectively. The~~the Fund’s recorded impairment of oil and gas ~~prices~~properties ~~averaged~~totaling $43.890 ~~per~~million, ~~mcf~~which ~~during~~were ~~the~~attributable ~~year~~to ~~ended~~revisions ~~December~~in 31reserve estimates related to East Cameron 299, ~~2010~~West ~~compared~~Cameron 556, and South Marsh Island 111 and adjustments to ~~$4.20~~asset ~~per~~retirement ~~mcf~~obligations ~~during~~for ~~the~~fully ~~year~~depleted ~~ended~~wells. At December 31, ~~2009~~2010, the Fund’s independent petroleum engineer determined that both the East Cameron 299 and West Cameron 556 wells were fully depleted.

~~The~~Dry-hole ~~decreases~~Costs. Dry-hole incosts ~~oil~~are ~~and~~those ~~gas~~costs ~~volumes~~incurred ~~were~~to ~~principally~~drill ~~attributable~~and todevelop a ~~reduction~~well inthat ~~the~~is ~~number~~ultimately found to be incapable of ~~production~~producing ~~days~~either ~~coupled~~oil ~~with~~or anatural ~~decrease~~gas in sufficient quantities to justify completion of the ~~average~~well. At ~~production~~times, ~~rate~~the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. ~~See~~During ~~“Overview”~~the ~~above~~years ~~for~~ended ~~additional~~December ~~information~~31, 2011 and 2010, the Fund recorded credits to dry-hole costs of $62 thousand and $3 thousand, respectively.

Depletion and Amortization. Depletion and amortization for the year ended December 31, 2010 was $0.7 million, a decrease of $2.2 million from the year ended December 31, 2009. The decrease resulted primarily from a decrease in production volumes totaling $2.0 million coupled with a decrease in average depletion rates totaling $0.2 million. The decrease in average depletion rates was primarily the result of the composite of productive wells coupled with a reduction in depletable costs resulting from impairments recorded during 2009.

Impairment of Oil and Gas Properties. During the year ended December 31, 2010, the Fund recorded impairments of oil and gas properties totaling $3.0 million, which were attributable to revisions in reserve estimates related to East Cameron 299, West Cameron 556, and South Marsh Island 111 and adjustments to asset retirement obligations for fully depleted wells. At December 31, 2010, the Fund’s independent petroleum engineer determined that both the East Cameron 299 and West Cameron 556 wells were fully depleted. During the year ended December 31, 2009 the Fund recorded impairments of oil and gas properties totaling $2.4 million, which were attributable to lower oil and gas commodity prices, revisions to reserve estimates, and adjustments to asset retirement obligations for fully depleted wells.

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Operating Expenses. Operating expenses represent costs specifically identifiable or allocable to the Fund's wells, as detailed in the following table.

	Year ended December 31,
	2010			2009
	2011			2010
	(in thousands)
Lease operating expense	$	~~530~~82		$	~~610~~530
Workover expense		14			11
Geological costs		45			-
Accretion expense		94			89
Dry-hole costs		(3	)		(16	)
Workover costs		(3	)		14
	$	~~550~~128		$	~~613~~553

Lease operating expense was related to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $31.0770 per mcfe during the year ended December 31, ~~2010~~2011 compared to $13.1407 per mcfe during the year ended December 31, ~~2009~~2010. ~~Workover~~Geological ~~expenses represent~~ costs, relating to ~~restore or stimulate production of existing reserves of a proved property. During~~ the ~~years~~Falcon ~~ended December 31~~Project, ~~2010~~represent ~~and~~costs ~~2009,~~incurred ~~workover expenses were attributable~~ to ~~East~~obtain ~~Cameron~~seismic ~~299~~data, surveys, and ~~West~~lease ~~Delta 67, respectively~~rentals. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties. ~~Dry-hole~~Workover costs ~~are~~include ~~those~~ costs ~~incurred to drill~~ and ~~develop~~credits aattributable ~~well that is ultimately found~~ to beEast ~~incapable~~Cameron of299, ~~producing~~representing ~~either~~costs ~~oil or natural gas in sufficient quantities~~ to ~~justify~~restore ~~completion~~or ofstimulate ~~the well~~production. ~~At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.~~

General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the following table.

	Year ended December 31,
	2010		2009
	(in thousands)
Accounting fees	$	121	$	131
Management reimbursement and other		80		81
Insurance expense		69		61
	$	270	$	273

~~Accounting~~Table fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund. Management reimbursement and other expenses relate primarily to reimbursements for various administrative costs incurred on the Fund’s behalf. Insurance expense represents premiums related to producing well and control of ~~well insurance, which varies depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance.~~Contents

Interest Income. Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities. Interest income for the year ended December 31, 2010 was $30 thousand, a $14 thousand decrease from the year ended December 31, 2009. The decrease was the result of a reduction in average outstanding balances earning interest, due to capital expenditures for oil and gas properties, coupled with lower interest rates earned.

	Year ended December 31,
	2011		2010
	(in thousands)
Accounting fees	$	105	$	121
Insurance expense		51		69
Management reimbursement and other		41		80
	$	197	$	270

Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund. Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance. Management reimbursement relates to reimbursements for various administrative costs incurred on the Fund’s behalf.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows used in operating activities for the year ended December 31, 2011 were $0.3 million, primarily related to operating expenses paid of $0.4 million, general and administrative expenses paid of $0.2 million and settlements of asset retirement obligations of $0.1 million, partially offset by revenue received of $0.4 million.

Cash flows provided by operating activities for the year ended December 31, 2010 were $0.3 million, primarily related to revenue received of $1.1 million, partially offset by operating expenses paid of $0.5 million and general and administrative expenses of $0.3 million.

Cash flows provided by operating activities for the year ended December 31, 2009 were $1.9 million, primarily related to revenue received of $2.6 million and favorable working capital of $0.2 million, partially offset by operating expenses of $0.6 million and general and administrative expenses of $0.3 million.

Investing Cash Flows

Cash flows provided by investing activities for the year ended December 31, 2011 were $15 thousand, primarily related net proceeds received from the salvage fund of $0.1 million, partially offset by capital expenditures for oil and gas properties of $0.1 million.

Cash flows used in investing activities for the year ended December 31, 2010 were $0.4 million, primarily related to capital expenditures for oil and gas properties, inclusive of advances.

Cash flows used in investing activities for the year ended December 31, 2009 were $0.3 million, primarily related to capital expenditures for oil and gas properties.

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Financing Cash Flows

There were no cash flows from financing activities for the year ended December 31, 2011.

Cash flows used in financing activities for the year ended December 31, 2010 were $0.4 million, related to shareholder distributions.

Cash flows used in financing activities for the year ended December 31, 2009 were $2.1 million, related to shareholder distributions.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investment properties. The estimated capital expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis. As of December 31, ~~2010~~2011, the Fund had committed to spend an additional $01.26 million ~~relating~~related to its investment properties, principally all of which is expected to be spent during the next twelve months.

Capital expenditures for investment properties ~~were~~are funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain. The number of projects in which the Fund can invest ~~was~~is limited, and each unsuccessful project the Fund ~~experienced~~experiences ~~reduced~~exhausts its ~~ability~~capital toand ~~generate~~reduces ~~revenue~~its ~~and~~ability ~~exhausted~~to ~~its~~generate ~~capital~~revenue.

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Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its operations, inclusive of expenditures for its investment properties. Operations are funded utilizing operating income, existing cash on-hand and income earned therefrom. Based upon its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. In the event of a temporary production stoppage, causing the Fund’s wells to not produce cash flow from operations, the Fund may borrow from the Manager until such time that production is resumed. At such time the Manager determines that the Fund is no longer capable of continuing to fund its operations, the Manager would elect to dissolve the Fund.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. ~~During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.~~

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at December 31, ~~2010~~2011 and ~~2009~~2010 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate such contracts. No contractual obligations exist at December 31, ~~2010~~2011 and ~~2009~~2010 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

~~See~~The ~~Note~~Fund 3has ofconsidered ~~Notes~~recent toaccounting ~~Financial~~pronouncements ~~Statements – “Recent Accounting Standards” contained in Item 8. “Financial Statements~~ and ~~Supplementary~~believes ~~Data”~~that ~~contained~~these inrecent ~~this~~pronouncements ~~Annual~~will ~~Report~~not ~~for~~have a ~~discussion~~material ofeffect ~~recent~~on ~~accounting~~the ~~pronouncements~~Fund’s financial statements.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits, Financial Statement Schedules” and filed as part of this report.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, ~~2010~~2011. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

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Management's Report on Internal Control over Financial Reporting

Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, ~~2010~~2011. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework. Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, ~~2010~~2011, the Fund’s internal control over financial reporting is effective.

This Annual Report does not include an attestation report of the Fund’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Fund’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Fund to provide only management’s report in this Annual Report.

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, ~~2010~~2011 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of Ridgewood Energy and the Fund and their ages at December 31, ~~2010~~2011 are as follows:

Name, Age and Position with Registrant	Officer of Ridgewood Energy Corporation Since

Robert E. Swanson, 64 Chief Executive Officer	1982

Kenneth W. Lang, 57 President and Chief Operating Officer	2009

Kathleen P. McSherry, 46 Executive Vice President and Chief Financial Officer	2001

Robert L. Gold, 53 Executive Vice President	1987

Daniel V. Gulino, 51 Senior Vice President and General Counsel	2003

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			Officer of
			Ridgewood Energy
Name, Age and Position with Registrant			Corporation Since
Robert E. Swanson, 63
	Chief Executive Officer		1982
Kenneth W. Lang, 56
	President and Chief Operating Officer		2009
Kathleen P. McSherry, 45
	Executive Vice President and
		Chief Financial Officer	2001
Robert L. Gold, 52
	Executive Vice President		1987
Daniel V. Gulino, 50
	Senior Vice President and General Counsel		2003

The officers in the above table have also been officers of the Fund since March 1, 2004, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of Ridgewood Energy and the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC, and President of Ridgewood Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is aan inactive member of the New York ~~State~~ and New Jersey State Bars~~, the Association of the Bar of the City of New York and the New York State Bar Association~~. He is a graduate of Amherst College and Fordham University Law School.

Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President – Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.

Kathleen P. McSherry has served as the Executive Vice President and Chief Financial Officer of Ridgewood Energy since 2001 and is a member of the Investment Committee. Ms. McSherry holds a Bachelor of Science degree in Accounting.

Robert L. Gold has served as the Executive Vice President of Ridgewood Energy since 1987 and is a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.

Daniel V. Gulino is Senior Vice President of Legal Affairs for Ridgewood Energy and has served as counsel for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management and Senior Vice President & General Counsel of Ridgewood Securities Corporation. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.

Board of Directors and Board Committees

The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure. Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11. “Executive Compensation” of this Annual Report. Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager, the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.

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Code of Ethics

The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on our website or in a current report on Form 8-K. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN: General Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, ~~2010~~2011, all filing requirements applicable to its officers, directors and 10% beneficial owners were met.

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ITEM 11.

EXECUTIVE COMPENSATION

The executive officers of the Fund do not receive compensation from the Fund. The Manager, orand its affiliates, ~~compensates~~compensate the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report for more information regarding Manager compensation and payments to affiliated entities.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 480.7046 shares outstanding at March 151, ~~2011~~2012. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs, which are included in general and administrative expenses, totaled $8040 thousand ~~for~~and ~~each~~$80 ofthousand for the years ended December 31, ~~2010~~2011 and ~~2009~~2010, ~~which were included in general and administrative expenses~~respectively.

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.

None of the ~~compensation~~amounts paid to the Manager ~~has~~have been derived as a result of arm’s length negotiations.

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.

Profits and losses are allocated in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, ~~2010~~2011 and ~~2009~~2010.

	Year ended December 31,
	2010		2009
	2011		2010
	(in thousands)
Audit fees (1)	$	9080	$	~~105~~90
Audit-related fees (2)		-		3
	$	90	$	108

(1)	Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.

(2) Fees for consultations regarding the Fund’s disclosure controls and procedures in accordance with Section 906 of the Sarbanes-Oxley Act of 2002.

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1)

Financial Statements

See “Index to Financial Statements” set forth on page F-1.

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(a) (2)

Financial Statement Schedules

None.

(a) (3)

Exhibit
EXHIBIT NUMBER	TITLE OF EXHIBIT		METHOD OF FILING
Number		Title of Exhibit		Method of Filing
3.1	Certificate of Formation of Ridgewood Energy K Fund, LLC dated March 1, 2004		Incorporated by reference to the Fund's Form 10 filed on April 29, 2005
3.1		Certificate of Formation of Ridgewood Energy K Fund LLC dated March 1, 2004		Incorporated by reference to the Fund's Form 10 filed on April 29, 2005
3.2	Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy K Fund, LLC dated April 1, 2004		Incorporated by reference to the Fund's Form 10 filed on April 29, 2005
3.2		Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy K Fund LLC dated April 1, 2004		Incorporated by reference to the Fund's Form 10 filed on April 29, 2005
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)		Filed herewith
14		Code of Ethics		Filed herewith
31.2	Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)		Filed herewith
31.1		Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Securities Exchange Act Rule 13a-14(a)		Filed herewith
31.2		Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Securities Exchange Act Rule 13a-14(a)		Filed herewith
32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund		Filed herewith
99		Report of Ryder Scott Company, L.P.		Filed herewith

32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund.	Filed herewith

99	Report of Ryder Scott Company, L.P.	Filed herewith

101.INS	XBRL Instance Document	*

101.SCH	XBRL Taxonomy Extension Schema	*

101.CAL	XBRL Taxonomy Extension Calculation Linkbase	*

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*

101.LAB	XBRL Taxonomy Extension Label Linkbase	*

101.PRE	XBRL Taxonomy Extension Presentation Linkbase	*

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Act of 1934 and otherwise are not subject to liability.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

	RIDGEWOOD ENERGY K FUND, LLC
Date: March 15, 2011	By:	/s/ ROBERT E. SWANSON
Date: March 1, 2012	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson
		Chief Executive Officer
		(Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	~~Capacity~~Date	~~Date~~
/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)	~~Chief~~March ~~Executive~~1, ~~Officer (Principal~~2012	~~March 15, 2011~~
Robert E. Swanson		~~Executive Officer)~~
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	~~Executive~~March ~~Vice~~1, ~~President and Chief~~2012	~~March 15, 2011~~
Kathleen P. McSherry		~~Financial Officer (Principal Financial~~
		and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
RIDGEWOOD ENERGY CORPORATION
/s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	March 1, 2012
/s/ ROBERT E. SWANSON		Chief Executive Officer of the Manager	March 15, 2011
Robert E. Swanson
Robert E. Swanson

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INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2010 and 2009	F-3
Balance Sheets as of December 31, 2011 and 2010	F-3
Statements of Operations for the years ended December 31, 2010 and 2009	F-4
Statements of Operations for the years ended December 31, 2011 and 2010	F-4
Statements of Changes in Members’ Capital for the years ended December 31, 2010 and 2009	F-5
Statements of Changes in Members' Capital for the years ended December 31, 2011 and 2010	F-5
Statements of Cash Flows for the years ended December 31, 2010 and 2009	F-6
Statements of Cash Flows for the years ended December 31, 2011 and 2010	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-12

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~Shareholders~~shareholders and Manager of Ridgewood Energy K Fund, LLC:

We have audited the accompanying balance sheets of Ridgewood Energy K Fund, LLC (the “Fund”) as of December 31, ~~2010~~2011 and ~~2009~~2010, and the related statements of operations, changes in members’' capital, and cash flows for the years ended December 31, ~~2010~~2011 and ~~2009~~2010. These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Fund's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures, in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy K Fund, LLC as of December 31, ~~2010~~2011 and ~~2009~~2010, and the results of its operations and its cash flows for the years ended December 31, ~~2010~~2011 and ~~2009~~2010, in conformity with accounting principles generally accepted in the United States of America.

/s/ ~~Deloitte~~DELOITTE & ~~Touche~~TOUCHE LLP

Parsippany, New Jersey

March 151, ~~2011~~2012

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Table of Contents

RIDGEWOOD ENERGY K FUND, LLC
BALANCE SHEETS
(in thousands, except share data)
	December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	2,311		$	2,786
Production receivable		57			209
Other current assets		28			25
Total current assets		2,396			3,020
Salvage fund		1,215			1,189
Oil and gas properties:
Advances to operators for working interests and expenditures		67			-
Proved properties		4,381			21,972
Less: accumulated depletion and amortization		(2,241	)		(16,795	)
Total oil and gas properties, net		2,207			5,177
Total assets	$	5,818		$	9,386
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators	$	87		$	156
Accrued expenses		386			65
Asset retirement obligations		152			-
Total current liabilities		625			221
Asset retirement obligations		436			478
Other liabilities		29			-
Total liabilities		1,090			699
Commitments and contingencies (Note 8)
Members' capital:
Manager:
Distributions		(290	)		(290	)
Retained earnings		1,137			1,153
Manager's total		847			863
Shareholders:
Capital contributions (534 shares authorized; 480.7046 issued and outstanding)		70,860			70,860
Syndication costs		(7,775	)		(7,775	)
Distributions		(12,442	)		(11,998	)
Accumulated deficit		(46,762	)		(43,263	)
Shareholders' total		3,881			7,824
Total members' capital		4,728			8,687
Total liabilities and members' capital	$	5,818		$	9,386

RIDGEWOOD ENERGY K FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	2,014		$	2,311
Salvage fund		305			-
Production receivable		35			57
Other current assets		41			28
Total current assets		2,395			2,396
Salvage fund		793			1,215
Oil and gas properties:
Advances to operators for working interests and expenditures		-			67
Unproved properties		2			-
Proved properties		4,634			4,381
Less: accumulated depletion and amortization		(2,438	)		(2,241	)
Total oil and gas properties, net		2,198			2,207
Total assets	$	5,386		$	5,818

LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Accrued expenses	$	154		$	473
Asset retirement obligations		305			152
Total current liabilities		459			625
Asset retirement obligations		231			436
Other liabilities		-			29
Total liabilities		690			1,090

Commitments and contingencies (Note 5)
Members' capital:
Manager:
Distributions		(290	)		(290	)
Retained earnings		1,145			1,137
Manager's total		855			847
Shareholders:
Capital contributions (534 shares authorized; 480.7046 issued and outstanding)		70,860			70,860
Syndication costs		(7,775	)		(7,775	)
Distributions		(12,442	)		(12,442	)
Accumulated deficit		(46,802	)		(46,762	)
Shareholders' total		3,841			3,881
Total members' capital		4,696			4,728
Total liabilities and members' capital	$	5,386		$	5,818

The accompanying notes are an integral part of these financial statements.

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Table of Contents

RIDGEWOOD ENERGY K FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
	Year ended December 31,
	2010			2009
Revenue
Oil and gas revenue	$	948		$	2,385
Expenses
Depletion and amortization		688			2,895
Impairment of oil and gas properties		2,985			2,394
Operating expenses		550			613
General and administrative expenses		270			273
Total expenses		4,493			6,175
Loss from operations		(3,545	)		(3,790	)
Other income
Interest income		30			44
Net loss	$	(3,515	)	$	(3,746	)
Manager Interest
Net (loss) income	$	(16	)	$	171
Shareholder Interest
Net loss	$	(3,499	)	$	(3,917	)
Net loss per share	$	(7,279	)	$	(8,148	)

RIDGEWOOD ENERGY K FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2011			2010
Revenue
Oil and gas revenue	$	334		$	948

Expenses
Depletion and amortization		197			688
Impairment of oil and gas properties		(65	)		2,985
Dry-hole costs		(62	)		(3	)
Operating expenses		128			553
General and administrative expenses		197			270
Total expenses		395			4,493
Loss from operations		(61	)		(3,545	)
Interest income		29			30
Net loss	$	(32	)	$	(3,515	)

Manager Interest
Net income (loss)	$	8		$	(16	)

Shareholder Interest
Net loss	$	(40	)	$	(3,499	)
Net loss per share	$	(82	)	$	(7,279	)

The accompanying notes are an integral part of these financial statements.

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Table of Contents

RIDGEWOOD ENERGY K FUND, LLC
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(in thousands, except share data)
	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2008		480.7046	$	692		$	13,852		$	14,544
Net income (loss)		-		171			(3,917	)		(3,746	)
Distributions		-		-			(2,111	)		(2,111	)
Balances, December 31, 2009		480.7046		863			7,824			8,687
Net loss		-		(16	)		(3,499	)		(3,515	)
Distributions		-		-			(444	)		(444	)
Balances, December 31, 2010		480.7046	$	847		$	3,881		$	4,728

RIDGEWOOD ENERGY K FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2009		480.7046	$	863		$	7,824		$	8,687
Net loss		-		(16	)		(3,499	)		(3,515	)
Distributions		-		-			(444	)		(444	)
Balances, December 31, 2010		480.7046		847			3,881			4,728
Net income (loss)		-		8			(40	)		(32	)
Balances, December 31, 2011		480.7046	$	855		$	3,841		$	4,696

The accompanying notes are an integral part of these financial statements.

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Table of Contents

RIDGEWOOD ENERGY K FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
	Year ended December 31,
	2010			2009
Cash flows from operating activities
Net loss	$	(3,515	)	$	(3,746	)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion and amortization		688			2,895
Impairment of oil and gas properties		2,985			2,394
Dry-hole costs		-			(16	)
Accretion expense		9			8
Changes in assets and liabilities:
Decrease in production receivable		152			213
(Increase) decrease in other current assets		(2	)		160
Increase in due to operators		34			5
Decrease in accrued expenses and other liabilities		(15	)		(8	)
Net cash provided by operating activities		336			1,905
Cash flows from investing activities
Payments to operators for working interests and expenditures		(67	)		-
Capital expenditures for oil and gas properties		(274	)		(276	)
Interest reinvested in salvage fund		(26	)		(27	)
Net cash used in investing activities		(367	)		(303	)
Cash flows from financing activities
Distributions		(444	)		(2,111	)
Net cash used in financing activities		(444	)		(2,111	)
Net decrease in cash and cash equivalents		(475	)		(509	)
Cash and cash equivalents, beginning of year		2,786			3,295
Cash and cash equivalents, end of year	$	2,311		$	2,786

RIDGEWOOD ENERGY K FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2011			2010

Cash flows from operating activities
Net loss	$	(32	)	$	(3,515	)
Adjustments to reconcile net loss to net cash
(used in) provided by operating activities:
Depletion and amortization		197			688
Impairment of oil and gas properties		(65	)		2,985
Dry-hole costs		(62	)		(3	)
Accretion expense		4			9
Changes in assets and liabilities:
Decrease in production receivable		22			152
Decrease (increase) in other current assets		7			(2	)
(Decrease) increase in accrued expenses and other liabilities		(258	)		22
Settlements of asset retirement obligations		(125	)		-
Net cash (used in) provided by operating activities		(312	)		336

Cash flows from investing activities
Payments to operators for working interests and expenditures		-			(67	)
Capital expenditures for oil and gas properties		(102	)		(274	)
Proceeds from (investments in) salvage fund, net		117			(26	)
Net cash provided by (used in) investing activities		15			(367	)

Cash flows from financing activities
Distributions		-			(444	)
Net cash used in financing activities		-			(444	)

Net decrease in cash and cash equivalents		(297	)		(475	)
Cash and cash equivalents, beginning of year		2,311			2,786
Cash and cash equivalents, end of year	$	2,014		$	2,311


Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$	67		$	-

The accompanying notes are an integral part of these financial statements.

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Table of Contents

RIDGEWOOD ENERGY K FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and ~~Purpose~~Summary of Significant Accounting Policies

The Ridgewood Energy K Fund, LLC ( the “Fund”), a Delaware limited liability company, was formed on March 1, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated April 1, 2004 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund. The Fund was organized to acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.Organization

The ~~Manager~~Ridgewood ~~has~~Energy ~~direct~~K ~~and~~Fund, ~~exclusive~~LLC ~~control~~( ~~over~~ the ~~management of the~~ “Fund’s”), ~~operations. With~~a ~~respect~~Delaware tolimited ~~project~~liability ~~investments~~company, ~~the~~was ~~Manager~~formed ~~locates~~on ~~potential~~March ~~projects~~1, ~~conducts~~2004 ~~due diligence~~ and ~~negotiates~~operates ~~and~~pursuant ~~completes~~to ~~the~~a ~~transactions~~limited inliability ~~which~~company agreement (the ~~investments~~“LLC ~~are~~Agreement”) ~~made. The~~dated ~~Manager~~April ~~performs~~1, or2004 ~~arranges~~by ~~for the performance of, the management, advisory~~ and ~~administrative~~among ~~services~~Ridgewood ~~required~~Energy ~~for~~Corporation ~~Fund operations. Such services include, without limitation,~~ (the ~~administration~~“Manager”) ~~of shareholder accounts, shareholder relations~~ and the ~~preparation,~~shareholders ~~review and dissemination~~ of ~~tax~~the ~~and~~Fund. ~~other~~The ~~financial~~Fund ~~information. In~~was ~~addition,~~organized ~~the~~to ~~Manager~~primarily ~~provides~~acquire ~~office~~interests ~~space,~~in ~~equipment~~oil and ~~facilities~~gas ~~and~~properties ~~other~~located ~~services~~in ~~necessary for Fund operations. The Manager also engages and manages~~ the ~~contractual~~United ~~relations~~States ~~with~~offshore ~~unaffiliated~~waters ~~custodians,~~of ~~depositories~~Texas, ~~accountants,~~Louisiana ~~attorneys, broker-dealers, corporate fiduciaries, insurers, banks~~ and ~~others~~Alabama asin ~~required.~~the ~~See~~Gulf ~~Notes~~of ~~2, 6 and 8~~Mexico.

2The Manager has direct and exclusive control over the management of the Fund’s operations. ~~Summary~~With respect to project investments, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, ~~Significant~~the ~~Accounting~~management, ~~Policies~~advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 3 and 5.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less are considered cash and cash equivalents. At times, deposits may be in excess of federally insured limits~~. Federally~~, ~~insured~~which, ~~limits~~for ofinterest ~~the~~bearing ~~Fund’s~~ deposits, are $250 thousand per insured financial institution. Additionally, non-interest bearing deposits are fully insured through December 31, 2012, after which they will be included within the $250 thousand limit. At December 31, ~~2010~~2011, the Fund’s bank balances exceeded federally insured limits by $21.04 million, ~~principally~~ all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations. At December 31, ~~2010~~2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity, of $1.1 million, which ~~mature~~matured in February 2012. Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value. For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

Oil and Gas Properties

The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund's portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.

The successful efforts method of accounting for oil and gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves have not been found, exploratory drilling costs are expensed as dry-hole costs. Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of oil and gas, are capitalized. Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred.

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Table of Contents

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory drilling costs are expensed as dry-hole costs. Annual lease rentals and exploration expenses are expensed as incurred.

Upon the sale or retirement of a proved property, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized.

Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.

At December 31, 2010 and 2009, amounts recorded in due to operators totaling $2 thousand and $0.1 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund may be required to advance its share of estimated cash expenditures for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, ~~2010~~2011 and ~~2009~~2010.

	2010			2009
	2011			2010
	(in thousands)
Balance, beginning of year	$	~~478~~588		$	~~348~~478
Liabilities incurred		~~101~~-			~~122~~101
Accretion expense		9			8
Liabilities settled		(125	)		-
Balance, end of year	$	588		$	478
Accretion expense		4			9
Revisions in estimated cash flows		69			-
Balance, end of year	$	536		$	588

As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

Syndication Costs

Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.

Impairment of Long-Lived Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

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Table of Contents

During the year ended December 31, ~~2010~~2011, the Fund recorded ~~impairments~~credits to impairment of oil and gas properties totaling $3.0.1 million, which were primarily attributable to revisions into ~~reserve~~cost estimates ~~related to East Cameron 299, West Cameron 556, and South Marsh Island 111 and adjustments to asset retirement obligations~~ for fully depleted wells. ~~At December 31, 2010, the Fund’s independent petroleum engineer determined that both the East Cameron 299 and West Cameron 556 wells were fully depleted.~~ During the year ended December 31, ~~2009~~2010, the Fund recorded ~~impairments~~ impairment of oil and gas properties totaling $23.40 million, which were attributable to ~~lower~~revisions ~~oil~~in ~~and~~reserve ~~gas~~estimates ~~commodity~~related ~~prices,~~to ~~revisions~~East toCameron ~~reserve~~299, ~~estimates~~West Cameron 556, and South Marsh Island 111 and adjustments to asset retirement obligations for fully depleted wells. ~~The~~At ~~fair~~December ~~value~~31, of2010, the ~~impaired~~Fund’s ~~wells~~independent ~~was~~petroleum engineer determined ~~based~~that onboth ~~level~~the 3East ~~inputs,~~Cameron ~~which~~299 ~~include~~and ~~projected~~West ~~income~~Cameron ~~from~~556 ~~reserves~~wells ~~utilizing~~were ~~forward~~fully ~~price curves, net of anticipated costs, discounted~~depleted.

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs~~, the costs to acquire proved properties and platform and pipeline costs~~.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.

Income and Expense Allocation

Profits and losses are allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for interest income and certain expenses, such as dry-hole costs, trust fees, depletion and amortization, which are allocated 99% to shareholders and 1% to the Manager.

~~3. Recent Accounting Standards~~Distributions

In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements. This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective beginning January 1, 2010. The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, which will be effective for the Fund December 31, 2011. The adoption of the guidance is not expected to have a material impact on the Fund’s financial statements.

4. Oil and Gas Properties

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves. At December 31, 2010 or 2009, the Fund had no unproved properties.

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. The Fund had credits to dry-hole costs of $3 thousand and $16 thousand during the years ended December 31, 2010 and 2009, respectively.

5. Distributions

Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

2. Oil and Gas Properties

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. During the years ended December 31, 2011 and 2010, the Fund recorded credits to dry-hole costs of $62 thousand and $3 thousand, respectively.

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Table of Contents

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions3. Related ~~After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.~~Parties

6In accordance with the LLC Agreement, the Manager is entitled to an annual management fee equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. ~~Related~~Such ~~Parties~~costs, which are included in general and administrative expenses, totaled $40 thousand and $80 thousand for the years ended December 31, 2011 and 2010, respectively.

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs totaled $80 thousand for each of the years ended December 31, 2010 and 2009, which were included in general and administrative expenses.

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.

None of the ~~compensation~~amounts paid to the Manager ~~has~~have been derived as a result of arm’s length negotiations.

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.

74. Fair Value Measurements

At December 31, ~~2010~~2011 and ~~2009~~2010, cash and cash equivalents, ~~production~~salvage ~~receivable~~fund, ~~salvage~~production ~~fund~~receivable, accrued expenses and other liabilities approximate fair value.

85. Commitments and Contingencies

Capital Commitments

The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, ~~2010~~2011, the Fund had committed to spend an additional $01.26 million related to its investment properties, principally all of which is expected to be spent during the next twelve months. Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. In the event of a temporary production stoppage, causing the Fund’s wells to not produce cash flow from operations, the Fund may borrow from the Manager until such time that production is resumed. At such time the Manager determines that the Fund is no longer capable of continuing to fund its operations, the Manager would elect to dissolve the Fund.

Environmental Considerations

The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At December 31, ~~2010~~2011 and ~~2009~~ 2010, there were no known environmental contingencies that required the Fund to record a liability.

In response to the ~~recent~~April 2010 oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore. Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

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Insurance Coverage

The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.

96. Subsequent Events

The Fund has assessed the impact of subsequent events through the date of issuance of its financial statements, and has concluded that there were no such events that require adjustment to, or disclosure in, the notes to the financial statements.

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Ridgewood Energy K Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities - Unaudited

In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are currently located in the United States offshore waters of Louisiana in the Gulf of Mexico.

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
	December 31,
	2010			2009
	2011			2010
	(in thousands)
Advances to operators for working interests and expenditures	$	67-		$	-67
Proved properties		4,381			21,972
Unproved properties		2			-
Total oil and gas properties		4,448			21,972
Proved properties		4,634			4,381
Accumulated depletion and amortization		(2,241	)		(16,795	)
Total oil and gas properties		4,636			4,448
Oil and gas properties, net	$	2,207		$	5,177
Accumulated depletion and amortization		(2,438	)		(2,241	)
Oil and gas properties, net	$	2,198		$	2,207
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
	Year ended December 31,
		2011			2010
	(in thousands)
Exploration costs	$	(15	)	$	69
Development costs		213			291
	$	198		$	360

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
	Year ended December 31,
	2010		2009
	(in thousands)
Exploration costs	$	69	$	253
Development costs		291		52
	$	360	$	305

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Table III - Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer, Ryder Scott Company, L.P. at December 31, 2011 and 2010. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer, Ryder Scott Company, L.P. at December 31, 2010 and 2009. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

	December 31, 2011						December 31, 2010
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)

Proved developed and undeveloped reserves:
Beginning of year		24,671			425,050			33,855			979,499
Revisions of previous estimates (a)		(6,270	)		(47,269	)		(7,335	)		(392,358	)
Production		(1,460	)		(39,892	)		(1,849	)		(162,091	)
End of year		16,941			337,889			24,671			425,050

Proved developed reserves:
Beginning of year		24,671			425,050			33,455			899,437
End of year		16,941			337,889			24,671			425,050

Proved undeveloped reserves:
Beginning of year		-			-			400			80,062
End of year		-			-			-			-

	December 31, 2010						December 31, 2009
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)
Proved developed and undeveloped reserves:
Beginning of year		33,855			979,499			49,675			1,689,276
Extensions and discoveries		-			-			1,507			358,714
Revisions of previous estimates (a)		(7,335	)		(392,358	)		(12,367	)		(567,434	)
Production		(1,849	)		(162,091	)		(4,960	)		(501,057	)
End of year		24,671			425,050			33,855			979,499
Proved developed reserves:
Beginning of year		33,455			899,437			39,490			1,096,603
End of year		24,671			425,050			33,455			899,437
Proved undeveloped reserves:
Beginning of year		400			80,062			10,185			592,673
End of year		-			-			400			80,062
(a) Revisions of previous estimates were primarily attributable to revisions due to well performance coupled with the year-end determinations that two of the Fund's wells were fully depleted at December 31, 2010 and one of the Fund's wells was fully depleted at December 31, 2009.

(a) Revisions of previous estimates were primarily attributable to revisions due to well performance coupled with the determinations that one of the Fund's wells was fully depleted during 2011 and two of the Fund's wells were fully depleted at December 31, 2010.

Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. At December 31, 2010 and 2009, future cash inflows were determined based on average first-of-the-month prices for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

	December 31,
	2010			2009
	(in thousands)
Future cash inflows	$	3,981		$	6,015
Future production costs		(880	)		(1,246	)
Future development costs		(1,142	)		(808	)
Future net cash flows		1,959			3,961
10% annual discount for estimated timing of cash flows		(348	)		(735	)
Standardized measure of discounted future net cash flows	$	1,611		$	3,226

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Table VIV - ~~Changes~~Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Summarized in the ~~Standardized~~following ~~Measure~~table is information for ~~Discounted~~the ~~Cash~~Fund ~~Flows~~with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. At December 31, 2011 and 2010, future cash inflows were determined based on average first-of-the-month prices for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

	December 31,
	2011			2010
	(in thousands)
Future cash inflows	$	3,532		$	3,981
Future production costs		(590	)		(880	)
Future development costs		(911	)		(1,142	)
Future net cash flows		2,031			1,959
10% annual discount for estimated timing of cash flows		(297	)		(348	)
Standardized measure of discounted future net cash flows	$	1,734		$	1,611

	Year ended December 31,
	2010			2009
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	416		$	(2,038	)
Sales and transfers of oil and gas produced during the period		(418	)		(1,775	)
Net change due to extensions, discoveries, and improved recovery		-			771
Changes in estimated future development costs		(334	)		1,803
Net change due to revisions in quantities estimates		(1,247	)		(2,610	)
Accretion of discount		323			684
Other		(355	)		(452	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(1,615	)	$	(3,617	)

Table V - Changes in the Standardized Measure for Discounted Cash Flows

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

	Year ended December 31,
	2011			2010
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	424		$	416
Sales and transfers of oil and gas produced during the period		(252	)		(418	)
Changes in estimated future development costs		231			(334	)
Net change due to revisions in quantities estimates		(555	)		(1,247	)
Accretion of discount		161			323
Other		114			(355	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	123		$	(1,615	)

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.

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