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, ~~2009~~2010

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(Dd) 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 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 ~~the~~ definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer (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 2315, ~~2010~~ 2011 there are 480.7046 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY K FUND, LLC

~~2009~~ 2010 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	109
	ITEM 1B	UNRESOLVED STAFF COMMENTS	109
	ITEM 2	PROPERTIES	109
	ITEM 3	LEGAL PROCEEDINGS	10
	ITEM 4	(REMOVED AND RESERVED)	1110
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	11
	ITEM 6	SELECTED FINANCIAL DATA	11
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	1615
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	1615
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	1615
	ITEM 9A	CONTROLS AND PROCEDURES	16
	ITEM 9B	OTHER INFORMATION	1716
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	1716
	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	1918
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	19
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	2019
		SIGNATURES	20

Table of Contents

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 ~~investment~~investments, 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, ~~outside~~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 ~~permanently~~ 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 been to generate cash flow for distribution to its shareholders through the acquisition of working interests in the exploration, production and sale of oil and natural gas. 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

By 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 ~~Mineral~~Bureau of Ocean Energy Management ~~Services~~, Regulation and Enforcement (“~~MMS~~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. ~~These~~For ~~investments~~certain ~~may~~of ~~require~~ the Fund’s ~~to pay~~investments, athe ~~disproportionate~~Fund ~~part~~may ofhave paid the ~~drilling~~operator ~~costs~~a “promote” on the ~~exploratory~~cost ~~well~~ of ~~a project~~an ~~than~~initial ~~its~~exploratory ~~working~~well, ~~interest~~representing ~~would otherwise require. This is called~~ a ~~promote,~~ ~~which~~larger isshare ~~common in~~of the ~~oil~~drilling ~~and natural gas exploration industry~~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.

For project investments, the Manager reviews reserve analyses provided by the operators. The Manager employs individuals in its Houston, Texas office that can perform significant analysis of the operator’s information. However, if necessary, the Fund may retain independent engineers to review the operator’s reserve analysis and/or conduct an independent review. For producing properties, the Manager engages independent petroleum engineers to examine and provide reserve estimates on the Fund’s behalf.

Once 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.

The Manager, on behalf of the Fund, and other working interest owners retain the right to make proposals involving certain operational matters associated with a project. This limits the operator’s inclination to act on its own or against the interests of the other working interest owners of the project. In accordance with the Manager’s working interest, the Manager reviews, discusses and consents to the details of the drilling plan, monitors progress under such plan, contributes ideas to the design of and budget for production facilities and then monitors the construction of those facilities. In addition, the Manager retains the right to review and audit the operator’s financial records related to the project to ensure the project is executed according to budget. Once a well is in production, the Manager continually monitors, evaluates and discusses the well production rate with the operator.

Manager’s ~~Investment~~ ~~Committee and~~ Investment ~~Criteria~~Committee

The Manager 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~~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~~were complete and a project ~~has~~was ~~been~~ deemed to satisfy Ridgewood Energy’s technical criteria, ~~provide~~provided an attractive economic risk/reward ratio, and fit within Ridgewood Energy’s diversification strategy, final investment approval iswas made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee ~~seeks~~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 ~~considers~~considered the geological, financial and operating risks of the proposed project and ~~compares~~ compared these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further ~~focuses~~focused on the initial well cost relative to the overall revenue potential of the project.

~~Properties~~Post-Investment Activities

The Fund ~~owns~~ ~~working~~has ~~interests~~reached the end of its project investment cycle. All of the projects in ~~fifteen~~which ~~wells:~~the ~~six~~Fund ~~are~~owns ~~currently~~a ~~producing,~~working ~~one~~interest is are currently ~~shut-in~~producing, ~~seven~~ 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 ~~one~~takes ~~was determined~~steps to beensure ~~fully~~that ~~depleted~~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.

Table of Contents

			Off-shore
			Location in			Total Spent
	Working		Gulf of	Well		through
Lease Block	Interest		Mexico	Depth		12/31/09
Producing Properties				(feet)		(in thousands)
South Marsh Island 111		3.75%	Louisiana		11,600	$	1,040
West Delta 68		3.75%	Louisiana		14,000	$	766
West Delta 67		3.75%	Louisiana		14,000	$	493
East Cameron 299		10.0%	Louisiana		21,300	$	18,655
West Cameron 556		20.0%	Louisiana		17,800	$	11,604
West Cameron 76 A-1		8.43%	Louisiana		14,000	$	1,775
Fully Depleted - 2009
Vermilion 344		3.75%	Louisiana		8,900	$	1,223

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. 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.

~~LLOG Projects~~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 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.

InRoyalty 2006, the Fund acquired a 3.75% working interest in each of six exploratory wells which are operated by LLOG Exploration Offshore, Inc. (“LLOG”) off the coast of Louisiana. Of the six wells, the Fund elected not to proceed with one well and one well was determined to be a dry hole.Payments

~~The~~Generally, ~~Fund has~~working ~~capitalized~~interests $3in an offshore oil and natural gas lease under the OCSLA pay a 16.567% ~~million~~or ~~related~~18.75% royalty to the ~~four~~BOE ~~exploratory~~for ~~wells~~shallow-water projects, ~~which~~dependent ~~were determined~~upon tothe belease ~~discoveries~~date, ~~during~~and ~~2007~~a 12. At5% ~~December~~royalty ~~31,~~to ~~2009~~the BOE for deepwater projects. Therefore, the ~~Fund~~ ~~has~~net ~~additional~~revenue ~~budgets~~interest ~~for~~of ~~these~~the ~~wells~~holders of ~~$0.3~~100% ~~million~~of ~~related~~the toworking ~~various recompletion~~interest ~~efforts. At~~in ~~December~~the ~~31,~~projects ~~2009,~~in ~~Vermilion~~which ~~344~~the ~~was determined~~Fund towill beinvest ~~fully~~is ~~depleted~~between by81.25% ~~the~~and ~~Fund’s~~83.33% ~~independent~~of ~~petroleum~~the ~~engineer, Ryder~~total ~~Scott~~revenue ~~Company,~~for ~~L.P.~~shallow-water ~~(“Ryder~~projects ~~Scott”)~~and 87. ~~During~~5% of the ~~years~~total ~~ended December~~revenue ~~31,~~for ~~2009~~deepwater ~~and~~projects, ~~2008~~and, ~~the~~such ~~Fund~~net ~~recorded~~revenue ~~impairments~~amount ~~related~~is tofurther ~~Vermilion 344~~reduced ~~totaling~~by ~~$0.5~~any ~~million~~other ~~and~~royalty $0burdens that apply to a lease block.6 Other ~~million~~than BOE royalties, ~~respectively~~the Fund does not have material royalty burdens.

South Marsh Island 111	Discovery July 2007; Production commenced February 2009
Vermilion 344	Discovery January 2007; Production commenced December 2008; Fully depleted at December 31, 2009
West Delta 68	Discovery March 2007; Production commenced July 2008
West Delta 67	Discovery November 2007; Production commenced July 2008

Properties

~~East Cameron~~Productive ~~299 / West Cameron 556~~Wells

The ~~Fund acquired~~following ~~from~~table ~~Millennium~~sets ~~Offshore~~forth ~~Group~~the ~~(“MOGI”)~~number aof ~~10.0%~~productive ~~working~~oil ~~interest~~and natural gas wells in which the ~~East~~ ~~Cameron~~Fund ~~299~~owned ~~field~~an ~~and~~interest aas ~~20.0%~~of ~~working~~December ~~interest~~31, in2010. Productive ~~West~~wells ~~Cameron~~are ~~556~~producing atwells ~~a total~~and ~~cost~~wells capable of ~~$30~~production.~~3 million.~~ ~~During~~Gross ~~2005,~~wells ~~MOGI~~are ~~sold~~the ~~its~~total ~~interests~~number of wells in which the ~~East~~Fund ~~Cameron~~has ~~299~~an ~~and~~interest. Net ~~West~~wells ~~Cameron~~are ~~556~~the ~~wells,~~sum ~~which~~of ~~are~~the ~~currently~~Fund’s ~~operated~~fractional ~~by ATP Oil~~working ~~and~~interests ~~Gas~~owned ~~Corporation~~in ~~(“ATP”)~~the gross wells. ~~Within~~All of the ~~East~~wells ~~Cameron 299/West~~are ~~Cameron~~located ~~556~~in ~~field,~~the ~~there~~offshore ~~are~~waters ~~currently~~of ~~two~~the ~~producing~~Gulf ~~wells~~of Mexico and ~~one~~are ~~well is~~operated ~~shut~~by third-inparty ~~pending a workover~~operators.

During August 2009, a valve repair was required on the pipeline through which the East Cameron 299/West Cameron 556 production flows. Accordingly, these wells did not produce for several weeks during the third quarter 2009. Production rates continue to decrease for the East Cameron 299 well, as its initial zone is nearly depleted. A recompletion of the well will be needed in order to access the reserves in the well’s lower zone. The Fund and its joint interest partners are evaluating the recompletion options. The Fund recorded impairment charges totaling $1.9 million during the year ended December 31, 2009 after re-considering its plans to bring a second East Cameron well on production under current market conditions. To date, the Fund has recorded impairments of $14.6 million related to East Cameron 299 and West Cameron 556.

	Total Productive Wells
	Gross		Net
Oil and natural gas		4		0.22

~~West Cameron~~Acreage ~~76 A-1~~Data

InThe ~~2007,~~ following table sets forth the Fund’s ~~acquired~~interests anin 8developed oil and gas acreage as of December 31, 2010.~~43%~~ The ~~working~~Fund ~~interest~~did not have any interests in ~~the~~undeveloped ~~West~~oil ~~Cameron~~and 76gas ~~A-1~~acreage ~~well~~as of December 31, ~~which~~ ~~began~~2010. Ownership ~~producing~~interests generally take the form of working interests in ~~October~~oil ~~2007~~and gas leases that have varying terms. ~~The~~All ~~Fund~~of ~~capitalized~~the ~~$1.8 million~~wells ~~related~~are tolocated ~~this~~in ~~well~~the offshore waters of the Gulf of Mexico and are operated by third-party operators.

Developed Acres
Gross			Net
12,161			831

Table of Contents

~~Working Interest~~Information regarding the Fund’s current projects, all of which are located in ~~Oil~~the ~~and~~offshore ~~Natural~~waters ~~Gas~~of ~~Leases~~the Gulf of Mexico, is provided in the following table.

Existing projects, and future projects, if any, are expected to be located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The OCSLA, which was enacted in 1953, 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 this Item 1. “Business”.

		Total Spent		Total
	Working	through		Fund
Lease Block	Interest	December 31, 2010		Budget		Status
		(in thousands)
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.

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.

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.

West Cameron 76 A-1	11.24%	$	1,781	$	1,781	Production commenced in 2007.

Fully Depleted
2010
East Cameron 299	10.00%	$	6,020		N/A	Determined to be fully depleted at December 31, 2010.
West Cameron 556	20.00%	$	11,604		N/A	Determined to be fully depleted at December 31, 2010.
2009
Vermilion 344	3.75%	$	1,223		N/A	Determined to be fully depleted at December 31, 2009.

AsIn ~~part~~ April 2010, the Deepwater Horizon, which was drilling a BP-operated project in the deepwater of the ~~leasing~~Gulf ~~activity~~of ~~and~~Mexico, assank ~~required~~after byan apparent blowout and fire. As of the ~~OCSLA~~date of this filing, the ~~leases~~well ~~auctioned include~~has ~~specified~~been ~~lease~~permanently ~~terms~~capped ~~such~~and asenvironmental remediation efforts are ongoing. Neither the ~~length~~Fund nor any operators of the ~~lease,~~Fund’s projects owns an interest in the ~~amount~~affected field. As a result of ~~royalty~~ tothe beexplosion ~~paid~~and resultant oil spill, ~~lease~~the ~~cancellation~~U.S. ~~and~~government ~~suspension~~placed a six-month moratorium on deepwater drilling operations in the Gulf of Mexico, ~~and~~which was lifted effective October 12, 2010. The U.S. government has also implemented additional safety and certification requirements applicable to adrilling ~~degree,~~activities in the ~~planned~~ ~~activities~~Gulf of ~~exploration~~Mexico. The extent to which these recent events may impact the Fund’s future results is uncertain. The Fund cannot predict how federal and ~~production~~state authorities will further respond to bethe ~~conducted~~incident byor whether additional changes in laws and regulations governing oil and gas operations in the ~~lessee~~ 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.

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. 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 this 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.Marketing/Customers

~~The lessee~~During ~~of a particular block~~2010, ~~for~~ the ~~term~~Fund ofhad ~~the~~engaged ~~lease,~~a ~~has~~third-party ~~the~~marketer ~~right~~ to ~~drill and~~sell ~~develop~~the ~~exploratory~~Fund’s ~~wells~~proportionate ~~and~~share ~~conduct~~of ~~other~~oil ~~activities~~and ~~throughout~~natural ~~the~~gas ~~block. If~~to the ~~initial~~public ~~well~~market. The onFund ~~the~~did ~~block~~not iscontract ~~successful,~~to asell ~~lessee,~~oil orand ~~third-party operator~~natural ~~for~~gas ato ~~project,~~customers ~~may conduct additional geological studies~~ and ~~may determine~~therefore, tohad ~~drill~~no ~~additional~~customers or ~~development~~any ~~wells.~~one Ifor afew ~~development~~major ~~well~~customers isupon ~~to be~~which ~~drilled~~it independs. Effective ~~the~~December ~~block~~2010, ~~each lessee owning working interests in~~ the ~~block~~Fund ~~must be~~sells ~~offered~~its ~~the~~oil ~~opportunity to participate in,~~ and ~~cover~~gas ~~the~~through ~~costs~~an ofagent, ~~the development~~Energy ~~well~~Upgrade, ~~up to that particular lessee’s working interest ownership percentage~~Inc.

~~Generally, working~~The ~~interests~~Fund’s incurrent anprojects ~~offshore~~are ~~natural~~near ~~gas~~existing ~~lease~~transportation ~~under~~infrastructure ~~the~~and ~~OCSLA pay a 16~~pipelines.~~67% or~~ The ~~18.75%~~Manager ~~royalty~~believes tothat ~~the~~it ~~MMS~~is ~~for~~likely ~~shallow-water~~that ~~projects,~~oil ~~dependent upon the lease date,~~ and anatural ~~12.5%~~gas ~~royalty~~from to the ~~MMS~~Fund’s ~~for~~future ~~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~~have isaccess between 81.25% and 83.33% of the total revenue for shallow-water projects and 87.5% of the total revenue for deepwater projects, and such net revenue amount is further reduced by any other royalty burdens that apply to apipeline ~~lease~~transportation ~~block. However, as described below, the MMS has adopted royalty relief for existing OCS leases for those who drill deep oil~~ and ~~natural~~ ~~gas~~can ~~projects. Other~~be ~~than~~marketed ~~MMS~~through ~~royalties,~~its ~~the Fund does not have material royalty burdens~~agent.

~~Mineral Management~~Natural ~~Services~~gas is ~~Deep~~sold in ~~Gas~~the ~~Royalty~~spot ~~Incentive~~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 on the Fund’s future profitability.

On January 26, 2004, the MMS promulgated a rule providing incentives for companies to increase deep oil and natural gas production in the Gulf of Mexico (the “Royalty Relief Rule”). Under the Royalty Relief Rule, lessees will be eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief would be available for wells drilled and perforated deeper than 18,000 feet subsea. It should be noted that the Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the continental shelf nor does it apply if the price of natural gas exceeds $10.48 Million British Thermal Units (“mmbtu”) adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters.

In addition to the Royalty Relief Rule promulgated by the MMS, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Relief Act”) was enacted to promote exploration and production of natural gas and oil in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Relief Act expired in the year 2000 but was extended by the MMS to promote continued interest in deepwater. For purposes of royalty relief, under the Deepwater Relief Act, the MMS defines deepwater as depths in excess of 656 feet or 200 meters. In order for a lease to be eligible for royalty relief, under the Deepwater Relief Act, it must be located in the Gulf of Mexico and west of 87 degrees and 30 minutes West longitude (essentially the Florida-Alabama boundary).

Currently, for leases entered into after November 2000, the MMS assigns a lease a specific volume of royalty suspension based on how the suspension amount would affect the economics of the lease’s development. Any such royalty suspension applicable to a particular lease is generally set forth in the lease auction materials prepared by the MMS. The amount of the suspension, if any, is not determined by water depth levels (as it had in the past) but rather based upon the MMS’ view of the characteristics and economics of the project. For example, projects deemed relatively secure and safe such as those near existing transportation infrastructure may receive no royalty relief while a similar project far away from any such infrastructure or in an area deemed more risky may receive significant royalty relief. As a result, unlike the royalty relief associated with deep drilling in shallow waters, there is no formulaic or predictable means of determining in advance whether and to what extent royalty relief would be available for a potential deepwater project.

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~~Oil and Natural Gas Agreements~~Seasonality

~~The~~Generally, the Fund ~~has~~'s ~~entered~~business ~~into~~operations aare ~~month-to-month~~not ~~agreement~~subject ~~with~~to aseasonal ~~third-party~~fluctuations ~~marketer,~~in ~~who is currently marketing and selling~~ the ~~Fund’s~~demand ~~proportionate~~for ~~share of~~ oil and natural gas tothat ~~the~~would ~~public~~result ~~market. The~~in ~~Fund~~more isof ~~receiving market prices for~~ the Fund's oil and natural gas itbeing ~~sells.~~sold, ~~All~~or oflikely ~~the~~to ~~Fund’s~~be ~~current~~sold, ~~projects~~during ~~are~~one ~~near existing~~or ~~transportation~~more ~~infrastructure~~particular ~~and~~months ~~pipelines~~or seasons. ~~The Manager~~ ~~believes~~Once ~~that~~a itproject is ~~likely~~producing, ~~that~~the operator of the project extracts oil and natural gas ~~from~~reserves throughout the ~~Fund’s future~~year. ~~projects~~Once ~~will~~extracted, ~~have~~oil ~~access~~and tonatural ~~pipeline~~gas ~~transportation and~~ can be ~~marketed in~~sold aat ~~similar~~any ~~fashion~~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.

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 ~~ATP~~LLOG Exploration Offshore, Inc. and BHP Billiton Petroleum, Ltd.~~, and LLOG.~~

Because the Fund does not operate any of the projects in which it has acquired an 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 ~~and maintains~~ 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 ~~period~~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 ~~will~~re-evaluates ~~reevaluate~~the ~~its~~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, ~~which is in the nature of a sinking 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 to the salvage fund will 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 does not compete for lease acquisitions from the BOE, it does compete with other companies for the acquisition of percentage ownership interests in oil and natural gas working interests in the secondary market.

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~~Seasonality~~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.

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 1st through November 30th. During third quarter 2008, two hurricanes struck in the Gulf of Mexico, which significantly impacted the Fund’s operations. These two storms, Hurricanes Gustav and Ike, came ashore in Louisiana and Texas, respectively, and caused production curtailments due to damage to third-party pipelines and disrupted the operations of crews that could assess and repair the damage. While the Fund’s platforms avoided major damage, the Fund’s production was curtailed from the time personnel were evacuated for safety purposes, until assessment and repair to the Fund’s platforms were completed and until repairs to third-party pipelines and facilities, for which the Fund was not responsible, were completed. As a result, East Cameron 299/West Cameron 556 and West Delta 67/68 were shut-in for approximately one month, with production resuming during October 2008 and West Cameron 76 was shut-in for approximately three months, with production resuming during October 2008. The Fund did not experience any damage or shut-ins, or production stoppages, due to hurricane activity during 2009.

Customers

All of the oil and natural gas production from the Fund’s producing properties is sold by a third party. As a result, the Fund did not contract to sell oil and natural gas to customers. Therefore, the Fund had no customers or any one or few major customers upon which it depends.

Energy 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 on the Fund’s future profitability. The Fund has not engaged in any price risk management programs or hedges.

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 does not compete for lease acquisitions from the MMS, 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 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 so large and have such 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 large oil and gas companies; such processes enable Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and 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 well in advance of most large oil and gas companies, (ii) Ridgewood Energy is one of the most active exploration and production participants in the Gulf of Mexico, and as a result the management team is in regular contact with all the major operators and is therefore able to contribute valuable 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 only invests in drill-ready syndicated projects.

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Employees

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

Offices

The principal executive office of each of the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and ~~its~~their phone number is 800-942-5550. The Manager leases additional office space at 11700 Old Katy Road, Houston, TX 77079. 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’s 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. ~~described~~The ~~herein~~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 ~~MMS~~BOE, an agency of the United States Department of Interior. The ~~MMS~~BOE administers federal offshore leases pursuant to regulations promulgated under the OCSLA. Lessees must obtain ~~MMS~~ 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 USU.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. ~~MMS~~BOE regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

The MMS 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 MMS 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.7

The MMS 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 length of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a 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 through the operator on the Fund’s behalf to the market 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 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.

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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 an agent 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:

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 ~~MMS~~BOE, 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.8

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 major 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.

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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.

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 ~~heading~~headings “Project Information” and “Properties,” is incorporated herein by reference.

Drilling Activity

The following table sets forth the Fund’s drilling activity for the years ended December 31, 2010 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 Fund’s reserve estimates at December 31, 2009 and 2008 were prepared by 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.9

Proved oil and gas reserves are the 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.~~ Contents

~~Proved~~The ~~Undeveloped~~primary ~~Reserves. At~~technical ~~December~~person ~~31,~~in ~~2009,~~charge of overseeing the Fund’s ~~had~~reserves ~~approximately~~estimates ~~400~~has ~~barrels~~a ~~and~~B.S. 80degree ~~thousand~~in ~~mcf of~~Petroleum ~~proved~~Engineering ~~undeveloped oil~~ and ~~natural gas reserves, respectively, attributable to South Marsh Island 111. The Fund~~ is ~~currently~~a ~~evaluating~~member of the ~~development~~ ~~alternatives~~Society ~~for~~of ~~these~~Petroleum ~~proved undeveloped reserves. At December 31~~Engineers, ~~2008,~~ the ~~Fund~~Association ~~had~~of ~~approximately~~American 10Drilling ~~thousand~~Engineers ~~barrels~~ and ~~593 thousand~~the ~~mcf~~American ofPetroleum ~~proved~~Institute. With ~~undeveloped~~over ~~oil~~twenty years ~~and~~of ~~natural~~industry ~~gas reserves~~experience, ~~respectively, attributable~~he tois ~~East~~currently ~~Cameron~~responsible ~~299~~for ~~and~~reserve ~~West Cameron 556. During the year ended December 31~~reporting, ~~2009,~~engineering itand ~~was~~economic ~~determined~~evaluation ~~that~~of itexploration ~~was~~and ~~not~~development ~~economical~~opportunities, toand ~~develop~~ the ~~proved~~ ~~undeveloped~~oversight ~~reserves~~of ~~attributable~~drilling ~~to East Cameron 299~~ and ~~West~~production ~~Cameron 556~~operations.

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 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.

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, ~~2009~~2010 and ~~2008~~2009 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” and “Results of Operations – Operating Expenses” is incorporated herein by reference.

Delivery Commitments

As of December 31, 2010, 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 v. 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. ~~Discovery~~During isMay ~~ongoing and~~2010, a ~~trial~~settlement ~~date~~was isreached ~~currently~~by ~~set~~the ~~for~~parties ~~May~~at ~~2010~~no cost to the Fund. Legal costs related to this claim ~~are~~were borne by the Manager.

ITEM 4. (REMOVED AND RESERVED)

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ITEM 4. (REMOVED AND RESERVED)

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 ~~March~~ ~~23,~~the ~~2010~~date of this filing, there were ~~855~~856 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 years ended December 31, ~~2009~~2010 and ~~2008~~2009, the Fund paid distributions to shareholders totaling $20.14 million and $32.81 million, respectively. ~~During 2006, the Manager waived its right to cash distributions for the remaining life of the Fund.~~

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 ~~also~~ Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for ~~additional~~ more information regarding the projects of the Fund.

Revenues are subject to ~~the~~ market pricing for oil and natural gas, which has been ~~extremely~~ volatile, and ~~are~~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.

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.

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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.

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 charged to expense 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.11

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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 ~~initially~~ 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 ~~producing~~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.

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 and 2009, 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.

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Results of Operations

	Year ended December 31,
	2010			2009
	(in thousands)
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	)

Overview. The ~~following~~ ~~table~~Fund’s ~~summarizes~~revenue, depletion and amortization, and lease operating expense were affected by the timing of the onset of production of the Fund’s ~~results~~wells and by the impact of ~~operations~~well maintenance activities. During the year ended December 31, 2010, the Fund had six wells that produced for a total of 1,436 days, compared to seven wells that produced for a total of 2,038 days during the ~~years~~year ended December 31, 2009. The ~~and~~decrease ~~2008~~in total ~~and~~production ~~should~~days bewas ~~read~~the inresult ~~conjunction~~of ~~with~~one of the Fund’s ~~financial~~ ~~statements~~wells ~~and~~being fully depleted at December 31, 2009 coupled with increased non-productive days related to maintenance activities. During the ~~notes~~year ~~thereto~~ended ~~included~~December ~~within~~31, ~~Item~~2010, 8the Fund's wells' production rate averaged 120 mcfe/producing day, compared to 262 mcfe/producing day during the year ended December 31, 2009. The ~~“Financial Statements~~decrease ~~and~~was ~~Supplementary~~primarily ~~Data”~~related to natural declines in ~~this~~production ~~Annual~~for ~~Report~~two of the Fund’s wells, which were determined to be fully depleted at December 31, 2010.

	Year ended December 31,
	2009			2008
	(in thousands)
Revenue
Oil and gas revenue	$	2,385		$	4,810
Expenses
Depletion and amortization		2,895			2,357
Impairment of proved properties		2,394			568
Operating expenses		613			468
General and administrative expenses		273			296
Total expenses		6,175			3,689
(Loss) income from operations		(3,790	)		1,121
Other income
Interest income		44			137
Net (loss) income	$	(3,746	)	$	1,258

Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, 2010 was $0.9 million, a $1.4 million decrease from the year ended December 31, 2009. The decrease is 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.

~~Overview. During~~Oil ~~the~~sales ~~year~~volumes ~~ended~~were ~~December~~2 ~~31,~~thousand ~~2009,~~barrels ~~the~~and ~~Fund had~~5 ~~seven~~thousand ~~producing~~barrels ~~wells,~~for ~~East~~the ~~Cameron~~years ~~299,~~ended ~~which~~December ~~commenced production during 2004~~31, ~~West~~2010 ~~Cameron~~and ~~556~~2009, ~~which~~respectively. The ~~commenced~~Fund’s ~~production~~oil ~~during~~prices ~~2005,~~averaged ~~West~~$78 ~~Cameron~~per ~~76 A-1,~~barrel ~~which commenced production~~ during ~~2007,~~the ~~West~~year ~~Delta~~ended ~~67/68,~~December ~~which commenced production in July 2008~~31, ~~Vermilion~~2010 ~~344~~compared ~~which commenced production in December 2008 and South Marsh Island 111 which commenced production in February 2009. Vermilion 344 was determined~~ to be$53 ~~fully~~per ~~depleted~~barrel atduring ~~December 31, 2009. During~~ the year ended December 31, ~~2008, the Fund had six producing wells~~2009. ~~Oil and gas sales were all located within the United States.~~

~~Oil~~Gas ~~and~~sales ~~Gas Revenue.~~volumes ~~Oil~~were 146 thousand mcf and ~~gas~~492 ~~revenue~~thousand mcf for the ~~year~~years ended December 31, 2010 and 2009, ~~was $2~~respectively.4 The ~~million,~~Fund’s agas prices averaged $2.4.89 ~~million~~per ~~decrease~~mcf ~~from~~during the year ended December 31, ~~2008. The~~ ~~decrease~~2010 iscompared ~~attributable~~ to ~~the impact of lower average prices totaling~~ $24.820 ~~million,~~per ~~partially~~mcf ~~offset~~during bythe anyear ~~increase~~ended inDecember ~~sales~~31, ~~volumes totaling $0~~2009.~~4 million.~~

~~Oil~~The ~~sales volumes~~decreases ~~were~~in 5oil ~~thousand~~and ~~barrels~~gas ~~during~~volumes ~~the~~were ~~year~~principally ~~ended~~attributable ~~December 31, 2009 as compared~~ to 6a ~~thousand~~reduction ~~barrels~~in ~~during~~ the ~~year~~number ~~ended~~of ~~December~~production ~~31, 2008. The~~days ~~Fund’s~~coupled ~~oil~~with ~~prices~~a ~~averaged~~decrease ~~$56~~in ~~per barrel and $94 per barrel during~~ the ~~years~~average ~~ended~~production ~~December~~rate. See ~~31,~~“Overview” ~~2009~~above ~~and~~for ~~2008, respectively~~additional information.

~~Gas~~Depletion ~~sales volumes~~and ~~were~~Amortization. Depletion ~~493~~and ~~thousand~~amortization ~~mcf~~for ~~during~~ the year ended December 31, ~~2009~~2010 ~~compared to~~was ~~438~~$0.7 ~~thousand~~million, ~~mcf~~a ~~during~~decrease of $2.2 million from the year ended December 31, ~~2008~~2009. The ~~Fund’s~~ ~~gas~~decrease ~~prices~~resulted ~~averaged~~primarily from a decrease in production volumes totaling $42.200 ~~per~~million ~~mcf~~coupled ~~and~~with a decrease in average depletion rates totaling $90.592 ~~during~~million. The decrease in average depletion rates was primarily the ~~years~~result ~~ended December~~of ~~31,~~the ~~2009~~composite ~~and~~of ~~2008,~~productive ~~respectively~~wells coupled with a reduction in depletable costs resulting from impairments recorded during 2009.

~~The decrease~~Impairment inof ~~oil~~Oil ~~volumes~~and ~~for~~Gas Properties. During the year ended December 31, ~~2009~~2010, ~~compared~~the toFund ~~the year~~recorded ~~ended~~impairments ~~December~~of 31oil and gas properties totaling $3.0 million, ~~2008~~which ~~was~~were ~~due~~attributable to ~~lower~~revisions ~~production~~in ~~rates~~reserve ~~for~~estimates related to East Cameron 299, West Cameron 556, ~~West~~and ~~Cameron~~South 76Marsh ~~A-1~~Island 111 and ~~West~~adjustments ~~Delta~~to 68asset retirement obligations for fully depleted wells. At December 31, ~~partially~~2010, ~~offset by~~the Fund’s independent petroleum engineer determined that both the ~~onset~~East ofCameron ~~production~~299 and West Cameron 556 wells were fully depleted. During the year ended December 31, 2009 the Fund recorded impairments of ~~South~~oil ~~Marsh~~and ~~Island~~gas ~~111~~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.

The increase in gas volumes for the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily attributable to the onset of production of West Delta 67, West Delta 68, Vermilion 344 and South Marsh Island 111, partially offset by a decrease in production rates for East Cameron 299, West Cameron 556 and West Cameron 76 A-1.

Depletion and Amortization. Depletion and amortization for the year ended December 31, 2009 was $2.9 million, a $0.5 million increase from the year ended December 31, 2008. The increase resulted from an increase in production volumes totaling $0.3 million coupled with an increase in average depletion rates totaling $0.3 million. The increase in depletion rates was the result of higher cost reserve additions, principally attributable to Vermilion 344 and South Marsh Island 111, partially offset by decreased rates for East Cameron 299 and West Cameron 556, attributable to the impairment charges taken for those wells.

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~~Impairment~~Operating ~~of Proved Properties~~Expenses. ~~During~~ Operating ~~the~~expenses ~~years~~represent ~~ended~~costs ~~December~~specifically ~~31,~~identifiable ~~2009 and~~or ~~2008,~~allocable ~~the Fund recorded impairments of proved properties of $2.4 million and $0.6 million, respectively. During the year ended December 31, 2009, impairments of $1.9 million, relating~~ to East Cameron 299 and West Cameron 556 were attributable to lower oil and gas commodity prices and revisions to reserve estimates. The impairments to Vermilion 344 of $0.5 million were attributable to lower oil and gas commodity prices, a reduction in the Fund’'s ~~estimates of proved oil and gas reserves~~wells, as ~~and~~detailed ~~the year-end~~in ~~determination that~~ the ~~well~~following ~~was fully depleted~~table. During the year ended December 31, 2008, the impairment to Vermilion 344 of $0.6 million was attributable to increased project costs, lower oil and gas commodity prices and a reduction in the Fund’s estimates of proved oil and gas reserves.

Operating Expenses. Operating expenses include the costs of operating and maintaining wells and related facilities, accretion expense related to asset retirement obligations, and dry-hole costs, as detailed in the following table.

	Year ended December 31,
	2010			2009
	(in thousands)
Lease operating expense	$	530		$	610
Workover expense		14			11
Accretion expense		9			8
Dry-hole costs		(3	)		(16	)
	$	550		$	613

	Year ended December 31,
	2009			2008
	(in thousands)
Lease operating expense	$	621		$	481
Accretion expense		8			5
Dry-hole costs, net		(16	)		(18	)
	$	613		$	468

Lease operating expense was related to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $3.07 per mcfe during the year ended December 31, 2010 compared to $1.14 per mcfe during the year ended December 31, 2009. Workover expenses represent costs to restore or stimulate production of existing reserves of a proved property. During the years ended December 31, 2010 and 2009, workover expenses were attributable to East Cameron 299 and West Delta 67, respectively. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.

Lease operating expense for the years ended December 31, 2009 and 2008 related to the Fund’s producing properties during each period as outlined above in “Overview”. For the year ended December 31, 2009, the average production cost was $1.15 per mcfe compared to $0.97 per mcfe for the year ended December 31, 2008. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. 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,
	2009		2008
	2010		2009
	(in thousands)
Accounting fees	$	~~131~~121	$	~~153~~131
Management reimbursement and other		8180		8581
Insurance expense		6169		5861
	$	~~273~~270	$	~~296~~273

Accounting 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 ~~dependent~~depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance.

Interest Income. Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities ~~within the Fund’s salvage fund~~. Interest income for the year ended December 31, ~~2009~~ 2010 was $4430 thousand, a $~~0.1~~14 ~~million~~thousand decrease from the year ended December 31, ~~2008~~ 2009. The decrease was the result of a reduction in average outstanding balances earning interest, due to ~~ongoing~~ capital expenditures for oil and gas properties, coupled with lower interest rates earned.

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Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, ~~2009~~2010 were $10.93 million, primarily related to revenue ~~receipts of $2.6 million, $0.1 million~~ received ~~as a refund~~ of ~~estimated royalty payments made in 2008 and favorable working capital of~~ $01.1 million~~. These~~, ~~cash receipts were~~ partially offset by operating expenses paid of $0.65 million and general and administrative expenses of $0.3 million.

Cash flows provided by operating activities for the year ended December 31, ~~2008~~2009 were $41.29 million, primarily related to revenue ~~receipts~~received of $52.06 million and ~~interest income~~favorable ~~received~~working capital of $0.12 million~~. These~~, ~~cash receipts were~~ partially offset by operating expenses of $0.56 million, and general and administrative expenses of $0.3 million ~~and estimated royalty payments of $0~~.~~1 million.~~

Investing Cash Flows

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.

~~Cash flows used in investing activities for the year ended December 31, 2008 were $2.7 million, primarily related to capital expenditures for oil and gas properties.~~14

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Financing Cash Flows

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.

Cash flows used in financing activities for the year ended December 31, 2008 were $3.8 million, related to shareholder distributions.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the 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, ~~2009~~2010, the Fund had committed to spend an additional $0.32 million ~~related~~relating to its investment properties, principally all of which is expected to be spent during the next twelve months.

~~When~~Capital ~~the Manager~~expenditures ~~makes~~for ainvestment ~~decision~~properties towere ~~participate~~funded inwith ~~an exploratory project, it assumes that~~ the ~~well will be successful and allocates enough~~ capital toraised ~~budget~~by ~~for~~ the ~~completion~~ ofFund ~~that~~in ~~well~~its ~~and~~private ~~the~~placement ~~additional~~offering, ~~development~~which ~~wells and infrastructure anticipated. If an exploratory well~~ is ~~deemed~~all athe ~~dry~~capital ~~hole~~it orwill ifobtain. The itnumber isof ~~determined to~~projects bein ~~un-economical,~~which the ~~capital~~Fund ~~allocated~~can toinvest ~~the~~was ~~completion~~limited ofand ~~that~~each ~~well~~unsuccessful ~~and~~project to the ~~development~~Fund ofexperienced ~~additional~~reduced ~~wells~~its isability ~~then reallocated~~ to agenerate ~~new~~revenue ~~project~~and orexhausted ~~used to~~its ~~make additional investments~~capital.

Capital expenditures for investment properties 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 will naturally be limited and each unsuccessful project the Fund experiences reduces its ability to generate revenue and exhaust its capital. Typically, the Manager seeks an investment portfolio that combines high and low risk exploratory projects.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its operations, ~~and~~inclusive ~~capital~~ of expenditures for its investment properties. Operations are funded utilizing operating income, existing cash on-hand and income earned therefrom.

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 ~~subject~~. During 2006, the Manager elected to waive its right to distributions of available cash from operations, ~~reserve~~for ~~requirements~~the ~~and~~remaining life of the Fund~~’s operations~~.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at December 31, ~~2009~~2010 and ~~2008~~2009 and does not anticipate the use of such arrangements in the future.

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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 ~~any~~such contracts. No contractual obligations exist at December 31, ~~2009~~2010 and ~~2008~~2009 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

See Note 3 of Notes to Financial Statements – “Recent Accounting Standards” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of recent accounting pronouncements.

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 ~~Rule~~of ~~13a-15~~1934, as amended (ethe “Exchange Act”) as of December 31, ~~2009~~2010. 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.

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, ~~2009~~2010. 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, ~~2009~~2010, 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 ~~temporary~~ rules of the Securities and Exchange Commission that permit the Fund to provide only management’s report in this Annual Report.

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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, ~~2009~~2010 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, ~~2009~~2010 are as follows:

		Officer of
		Ridgewood Energy
Name, Age and Position with Registrant		Corporation Since
Robert E. Swanson, 62
	Chief Executive Officer	1982
Kenneth W. Lang, 55
	President and Chief Operating Officer	2009
Kathleen P. McSherry, 44
	Executive Vice President and
	Chief Financial Officer	2001
Robert L. Gold, 51
	Executive Vice President	1987
Daniel V. Gulino, 49
	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 Renewable Power, LLC and Ridgewood Capital Management, LLC and President of Ridgewood Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is a 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.

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 also serves as Vice President of Systems and Administration of Ridgewood Power. Ms. McSherry holds a Bachelor of Science degree in Accounting.

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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 a 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.

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 ~~has~~is ~~served as~~ Senior Vice President of Legal Affairs for Ridgewood Energy and ~~General~~has ~~Counsel~~served ofas counsel for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President ~~and~~of ~~General~~Legal ~~Counsel~~Affairs of Ridgewood ~~Renewable~~ ~~Power, 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 ~~of the Fund~~ 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 ~~of the Fund~~ grants any waiver, including any implicit waiver, from a provision of the code tothat ~~any~~applies ofto 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, ~~2009~~ 2010, all filing requirements applicable to its officers, directors and 10% beneficial owners were met.

ITEM 11.

EXECUTIVE COMPENSATION

The executive officers of the Fund do not receive compensation from the Fund. The Manager, or its affiliates, compensates 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

~~The following~~Beneficial ~~table~~ownership ~~sets~~is ~~forth~~determined ~~information~~in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership ~~of the~~is based on 480.7046 shares asoutstanding ofat March 2315, ~~2010~~2011. No (officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the ~~shares) by:~~Shares.

• each executive officer (there are no directors); and

• all of the executive officers as a group.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them. Percentage of beneficial ownership is based on 480.7046 shares outstanding at March 23, 2010. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

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Name of beneficial owner	Number of shares		Percent
Robert E. Swanson, Chief Executive Officer (1)		0.6667		*
Executive officers as a group (1)		0.6667		*

* Represents less than one percent.

(1) Includes shares owned by Mr. Swanson’s family members and trusts, which he controls.

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 totaled $80 thousand for each of the years ended December 31, ~~2009~~2010 and ~~2008~~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 paid to the Manager has 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. ~~See the discussion under the heading “Properties” in Item 1. “Business”.~~

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, ~~2009~~2010 and ~~2008~~2009.

	Year ended December 31,
	2009		2008
	2010		2009
	(in thousands)
Audit fees (1)	$	~~105~~90	$	105
Audit-related fees (2)		3-		-3
	$	~~108~~90	$	~~105~~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.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1)

Financial Statements

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

(a) (2)

Financial Statement Schedules

None.

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(a) (3)

Exhibit
Number	Title of Exhibit	Method of Filing
3.1	~~Articles~~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
14	Code of Ethics	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~~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

2119

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INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2009 and 2008	F-3
Statements of Operations for the years ended December 31, 2009 and 2008	F-4
Statements of Changes in Members’ Capital for the years ended December 31, 2009 and 2008	F-5
Statements of Cash Flows for the years ended December 31, 2009 and 2008	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-12

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
		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	Date

/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal	March 15, 2011
Robert E. Swanson	Executive Officer)


/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief	March 15, 2011
Kathleen P. McSherry	Financial Officer (Principal Financial
	and Accounting Officer)

RIDGEWOOD ENERGY CORPORATION

/s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	March 15, 2011
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
Statements of Operations for the years ended December 31, 2010 and 2009	F-4
Statements of Changes in Members’ Capital for the years ended December 31, 2010 and 2009	F-5
Statements of Cash Flows for the years ended December 31, 2010 and 2009	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, ~~2009~~2010 and ~~2008~~2009, and the related statements of operations, changes in members’ capital, and cash flows for the years ended December 31, ~~2009~~2010 and ~~2008~~2009. 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 ~~audits~~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, ~~2009~~2010 and ~~2008~~ 2009, and the results of its operations and its cash flows for the years ended December 31, ~~2009~~2010 and ~~2008~~2009, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the financial statements, the Fund adopted the reserve estimation and disclosure requirements of Extractive Activities – Oil and Gas as of December 31, 2009.

/s/ Deloitte & Touche LLP

Parsippany, New Jersey

March 2315, ~~2010~~ 2011

F-2

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RIDGEWOOD ENERGY K FUND, LLC

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

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	2,786		$	3,295
Production receivable		209			422
Other current assets		25			185
Total current assets		3,020			3,902
Salvage fund		1,189			1,162
Oil and gas properties:
Unproved properties		-			807
Proved properties		21,972			22,216
Less: accumulated depletion and amortization		(16,795	)		(12,904	)
Total oil and gas properties, net		5,177			10,119
Total assets	$	9,386		$	15,183
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators	$	156		$	245
Accrued expenses		65			46
Total current liabilities		221			291
Asset retirement obligations		478			348
Total liabilities		699			639
Commitments and contingencies (Note 8)
Members' capital:
Manager:
Distributions		(290	)		(290	)
Retained earnings		1,153			982
Manager's total		863			692
Shareholders:
Capital contributions (534 shares authorized; 480.7046 issued and outstanding)		70,860			70,860
Syndication costs		(7,775	)		(7,775	)
Distributions		(11,998	)		(9,887	)
Accumulated deficit		(43,263	)		(39,346	)
Shareholders' total		7,824			13,852
Total members' capital		8,687			14,544
Total liabilities and members' capital	$	9,386		$	15,183

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

F-3

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RIDGEWOOD ENERGY K FUND, LLC

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	)

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2009			2008
Revenue
Oil and gas revenue	$	2,385		$	4,810
Expenses
Depletion and amortization		2,895			2,357
Impairment of proved properties		2,394			568
Operating expenses		613			468
General and administrative expenses		273			296
Total expenses		6,175			3,689
(Loss) income from operations		(3,790	)		1,121
Other income
Interest income		44			137
Net (loss) income	$	(3,746	)	$	1,258
Manager Interest
Net income	$	171		$	578
Shareholder Interest
Net (loss) income	$	(3,917	)	$	680
Net (loss) income per share	$	(8,148	)	$	1,415

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

F-4

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RIDGEWOOD ENERGY K FUND, LLC

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

STATEMENTS OF CHANGES IN MEMBERS’ CAPITAL

(in thousands, except share data)

	# of Shares		Manager		Shareholders			Total
Balances, December 31, 2007		480.7046	$	114	$	16,985		$	17,099
Net income		-		578		680			1,258
Distributions		-		-		(3,813	)		(3,813	)
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

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

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RIDGEWOOD ENERGY K FUND, LLC

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

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2009			2008
Cash flows from operating activities
Net (loss) income	$	(3,746	)	$	1,258
Adjustments to reconcile net (loss) income to net cash
provided by operating activities:
Depletion and amortization		2,895			2,357
Dry-hole costs		(16	)		(18	)
Impairment of proved properties		2,394			568
Accretion expense		8			5
Changes in assets and liabilities:
Decrease in production receivable		213			173
Decrease (increase) in other current assets		160			(135	)
Increase in due to operators		5			23
Decrease in accrued expenses		(8	)		(23	)
Net cash provided by operating activities		1,905			4,208
Cash flows from investing activities
Capital expenditures for oil and gas properties		(276	)		(2,695	)
Interest reinvested in salvage fund		(27	)		(29	)
Net cash used in investing activities		(303	)		(2,724	)
Cash flows from financing activities
Distributions		(2,111	)		(3,813	)
Net cash used in financing activities		(2,111	)		(3,813	)
Net decrease in cash and cash equivalents		(509	)		(2,329	)
Cash and cash equivalents, beginning of year		3,295			5,624
Cash and cash equivalents, end of year	$	2,786		$	3,295

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

F-6

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RIDGEWOOD ENERGY K FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Purpose

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.

The Manager has direct and exclusive control over the management of the Fund’s operations. 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, 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. See Notes 2, 6 and 8.

2. Summary of Significant Accounting Policies

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, ~~bank~~ deposits may be in excess of federally insured limits. Federally ~~Effective January 1, 2010, the federally~~ insured limits of the Fund’s deposits are $250 thousand per insured financial institution. ~~Based~~ ~~upon~~At ~~these limits, at~~ December 31, ~~2009~~2010, the Fund’s bank balances ~~would have~~ exceeded federally insured limits by $2.5 0 million, principally all of which ~~$2.4 million~~ 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, ~~2009~~2010, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity, ~~totaling~~of $1.1 million, which mature 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.

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 toas dry-hole ~~expense~~ 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

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, ~~2009~~2010 and ~~2008~~2009, amounts recorded in due to operators totaling $~~0.1 million~~2 thousand and $0.21 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 ~~right~~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, ~~2009~~ 2010 and ~~2008~~2009.

	2009		2008
	2010		2009
	(in thousands)
Balance, beginning of year	$	~~348~~478	$	81348
Liabilities incurred		~~122~~101		~~183~~122
Liabilities settled		-		-
Accretion expense		9		8
Accretion expense		8		5
Balance, end of year	$	588	$	478
Revision to prior estimate		-		79
Balance, end of year	$	478	$	348

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 ~~natural~~ 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.

~~The~~Impairment ~~Fund uses the sales method~~ of ~~accounting~~Long-Lived 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.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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~~Impairment~~ During the year ended December 31, 2010, the Fund recorded impairments of ~~Long-Lived~~oil ~~Assets~~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. The fair value of the impaired wells was determined based on level 3 inputs, which include projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.

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 that 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.

During the year ended December 31, 2009, the Fund recorded impairments to its proved properties totaling $2.4 million, resulting from the determination that one of the Fund’s wells was fully depleted, lower oil and gas commodity prices and revisions to reserve estimates. During the year ended December 31, 2008, the Fund recorded impairments to proved properties totaling $0.6 million, attributable to increased project costs, lower oil and gas commodity prices and a reduction in the Fund’s estimates of proved oil and gas reserves. The fair value of the impaired wells was determined based on level 3 inputs, which include projected income from proved and probable reserves utilizing forward price curves, net of anticipated costs, discounted.

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. 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

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 iswas effective ~~for the first reporting period~~ beginning ~~after December 15, 2009, which will be effective for the Fund 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.

~~In June 2009, the FASB issued Accounting Standards Codification as the source of GAAP to be applied to nongovernmental agencies~~4. Oil ~~This guidance explicitly recognizes rules~~ and ~~interpretive~~Gas releases of the SEC under authority of federal securities laws as authoritative GAAP for SEC registrants. It was effective for interim or annual periods ending after September 15, 2009. The guidance was adopted for the third quarter 2009 and did not have a material impact on the Fund’s financial statements.Properties

~~In May 2009,~~Leasehold ~~the~~acquisition ~~FASB~~and ~~issued~~exploratory ~~guidance~~drilling oncosts ~~subsequent~~are ~~events,~~capitalized ~~which~~pending ~~sets~~determination ~~forth general standards~~ of ~~accounting~~whether ~~for and disclosure of events that occur after~~ the ~~balance~~well ~~sheet~~has ~~date~~found ~~but~~proved ~~before~~reserves. Unproved ~~financial~~properties ~~statements~~ are ~~issued~~assessed oron ~~are available~~a toquarterly bebasis ~~issued.~~by ~~The~~evaluating ~~guidance~~and ~~was~~monitoring ~~adopted~~if ~~effective~~sufficient ~~for~~progress ~~the~~is ~~second quarter~~made ~~2009~~on ~~and~~assessing ~~did~~the ~~not~~reserves. At ~~have~~December a31, ~~material~~2010 ~~impact~~or on2009, the Fund’s ~~financial statements~~had no unproved properties.

~~In April 2009,~~Capitalized exploratory well costs are expensed as dry-hole costs in the ~~FASB~~event ~~issued~~that ~~guidance~~reserves onare ~~interim~~not ~~disclosures~~found ~~about~~or ~~fair value~~are ofnot ~~financial~~in ~~instruments,~~sufficient ~~which~~quantities ~~requires~~to ~~quarterly~~complete ~~disclosure~~the ~~of information~~well ~~about~~and develop the ~~fair~~field. At ~~value~~times, the Fund receives credits on certain wells from their respective operators upon review and audit of ~~financial~~the ~~instruments~~wells’ costs. The ~~guidance was~~Fund ~~adopted~~had ~~effective~~credits ~~for~~to ~~the~~dry-hole ~~second~~costs ~~quarter~~of ~~2009~~$3 thousand and ~~did~~$16 ~~not~~thousand ~~have~~during athe ~~material impact~~years onended ~~the~~December ~~Fund’s~~31, ~~financial~~2010 ~~statements~~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.

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InAvailable ~~April 2009,~~cash ~~the~~from ~~FASB~~dispositions, ~~issued~~as ~~guidance~~defined onin the ~~recognition~~LLC ~~and presentation of other-than-temporary impairments~~Agreement, ~~which~~will ~~amends~~be ~~the~~paid ~~other-than-temporary impairment~~99% ~~guidance for debt securities~~ to ~~make~~shareholders ~~the guidance more operational~~ and 1% to ~~improve~~ the ~~presentation~~Manager ~~and~~until ~~disclosure of other-than-temporary impairments on debt and equity securities in~~ the ~~financial~~shareholders ~~statements.~~have ~~This guidance~~received ~~does~~total ~~not~~distributions ~~amend~~equal ~~existing recognition and measurement guidance related~~ to ~~other-than-temporary~~ ~~impairments~~their ofcapital ~~equity securities~~contributions. ~~This~~After ~~guidance~~shareholders ~~does~~have ~~not require~~received ~~disclosures~~distributions ~~for~~equal ~~earlier~~to ~~periods~~their ~~presented~~capital ~~for comparative purposes at initial adoption. In periods after initial adoption~~contributions, ~~this~~85% ~~guidance~~of ~~requires comparative~~available ~~disclosures~~cash ~~only~~from ~~for~~dispositions ~~periods~~will ~~ending~~be ~~after~~distributed ~~initial~~to ~~adoption.~~shareholders ~~The guidance was adopted effective for the second quarter 2009~~ and ~~did~~15% ~~not~~to ~~have a material impact on~~ the ~~Fund’s financial statements~~Manager.

In September 2006, the FASB issued guidance related to fair value measurements. This guidance provides a common definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The FASB also issued guidance on the methods used to measure fair value and required expanded disclosures related to fair value measurements. The Fund adopted this guidance for financial assets and financial liabilities effective January 1, 2008 and for non-financial assets and non-financial liabilities effective January 1, 2009. The adoption did not have a material impact on the Fund’s financial statements.

In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release No. 33-8995”), amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K. The new requirements provide for consideration of new technologies in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations. The final rules were effective for fiscal years ending on or after December 31, 2009. In January 2010, the FASB issued guidance on oil and gas reserve estimation and disclosures to align the Accounting Standards Codification with the disclosure requirements of Release No. 33-8995. The FASB and SEC guidance has been adopted for the year ended December 31, 2009. In the unaudited supplementary financial information, the 2009 future estimated cash inflows are determined on average price based on the prior 12-month period whereby 2008 future estimated cash inflows are determined based on year-end prices.

4. Unproved Properties - Capitalized Exploratory Well Costs

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, 2009, the Fund had no unproved properties. The following table reflects the net changes in unproved properties for the years ended December 31, 2009 and 2008.

	2009			2008
	(in thousands)
Balance, beginning of year	$	807		$	1,869
Additions to capitalized exploratory well costs pending the determination of proved reserves		234			1,230
Reclassification to proved properties based on the determination of proved reserves		(1,041	)		(2,292	)
Capitalized exploratory well costs charged to dry-hole costs		-			-
Balance, end of year	$	-		$	807

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, 2009 and 2008, the Fund recorded net dry-hole credits of $16 thousand and $18 thousand, respectively, which are included in the Fund’s Statements of Operations as Operating Expenses.

5. Distributions

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. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.

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6. Related Parties

~~Effective October~~In 1,accordance ~~2005~~with ~~and~~the ~~continuing~~LLC ~~for~~Agreement, the ~~remaining~~Manager ~~life~~is entitled to an annual management fee equal to 2.5% of the ~~Fund~~total shareholder capital. During 2005, the Manager ~~elected~~ towaived ~~waive~~ 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~~, totaling~~ totaled $80 thousand for each of the years ended December 31, ~~2009~~2010 and ~~2008~~2009, ~~respectively,~~ 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 paid to the Manager has 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.

7. Fair Value ~~of Financial Instruments~~Measurements

At December 31, ~~2009~~2010 and ~~2008~~2009, cash and cash equivalents, production receivable, salvage fund, ~~and~~ accrued expenses and other liabilities approximate fair value.

8. 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, ~~2009~~2010, the Fund had committed to spend an additional $0.32 million related to its investment properties, principally all of which is expected to be spent during the next twelve months.

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, ~~2009~~2010 and ~~2008~~2009, there were no known environmental contingencies that required the Fund to record a liability.

In response to the recent 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.

9. 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

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
	December 31,
	2010			2009
	(in thousands)
Advances to operators for working interests and expenditures	$	67		$	-
Proved properties		4,381			21,972
Total oil and gas properties		4,448			21,972
Accumulated depletion and amortization		(2,241	)		(16,795	)
Oil and gas properties, net	$	2,207		$	5,177

	December 31,
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
	2009			2008
	Year ended December 31,
	2010			2009
	(in thousands)
Unproved properties	$	-		$	807
Exploration costs	$	69		$	253
Proved properties		21,972			22,216
Development costs		291			52
Total oil and gas properties		21,972			23,023
	$	360		$	305
Accumulated depletion and amortization		(16,795	)		(12,904	)
Oil and gas properties, net	$	5,177		$	10,119

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2009		2008
	(in thousands)
Exploration costs	$	253	$	955
Development costs		52		934
	$	305	$	1,889

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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, ~~2009~~2010 and ~~2008~~ 2009. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules ~~and represent all reserves managed by Ridgewood Energy Corporation, the Manager of the Fund~~. ~~The reserve data disclosed in the following tables represent the Fund's share of such reserves based on the Fund's net revenue interest in each property.~~ 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, 2009								December 31, 2008
		December 31, 2010								December 31, 2009
		United States	~~United States~~
		Oil (BBLS)	~~Oil (BBLS)~~			Gas (MCF)	~~Gas (MCF)~~			Oil (BBLS)	~~Oil (BBLS)~~			Gas (MCF)	~~Gas (MCF)~~
Proved developed and undeveloped reserves:
Beginning of year			33,855	~~49,675~~			979,499	~~1,689,276~~			49,675	~~38,482~~			1,689,276	~~2,508,424~~
Extensions and discoveries			-	~~1,507~~			-	~~358,714~~			1,507	~~23,374~~			358,714	~~222,093~~
Revisions of previous estimates (a)			(7,335	~~(12,367~~)	)		(392,358	~~(567,434~~)	)		(12,367	~~(5,735~~)	)		(567,434	~~(603,601~~)	)
Production			(1,849	~~(4,960~~)	)		(162,091	~~(501,057~~)	)		(4,960	~~(6,446~~)	)		(501,057	~~(437,640~~)	)
End of year			24,671	~~33,855~~			425,050	~~979,499~~			33,855	~~49,675~~			979,499	~~1,689,276~~
Proved developed reserves:
Beginning of year			33,455	~~39,490~~			899,437	~~1,096,603~~			39,490	~~35,223~~			1,096,603	~~2,377,243~~
End of year			24,671	~~33,455~~			425,050	~~899,437~~			33,455	~~39,490~~			899,437	~~1,096,603~~
Proved undeveloped reserves:
Beginning of year			400	~~10,185~~			80,062	~~592,673~~			10,185	~~3,259~~			592,673	~~131,181~~
End of year			-	~~400~~			-	~~80,062~~			400	~~10,185~~			80,062	~~592,673~~
(a)	Revisions of previous estimates are primarily attributable to the year-end determination that one of the Fund's wells was fully depleted at December 31, 2009, coupled with revisions due to well performance.
(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.

Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas ~~Reserve Quantities~~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. ~~At December 31, 2008, future cash inflows were determined based on year-end prices.~~ Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

	December 31,
	2009			2008
	2010			2009
	(in thousands)
Future cash inflows	$	63,~~015~~981		$	126,~~328~~015
Future production costs		(~~1,246~~880	)		(1,~~675~~246	)
Future development costs		(~~808~~1,142	)		(~~2,232~~808	)
Future net cash flows		31,~~961~~959			83,~~421~~961
10% annual discount for estimated timing of cash flows		(~~735~~348	)		(~~1,578~~735	)
Standardized measure of discounted future estimated net cash flows	$	3,226		$	6,843
Standardized measure of discounted future net cash flows	$	1,611		$	3,226

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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,
	2009			2008
	2010			2009
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	~~(2,038~~416	)	$	(2,~~331~~038	)
Sales and transfer of oil and gas produced during the period		(1,775	)		(4,349	)
Sales and transfers of oil and gas produced during the period		(418	)		(1,775	)
Net change due to extensions, discoveries, and improved recovery		~~771~~-			~~1,688~~771
Changes in estimated future development costs		~~1,803~~(334	)		-1,803
Net change due to revisions in quantity estimates		(2,610	)		(4,022	)
Net change due to revisions in quantities estimates		(1,247	)		(2,610	)
Accretion of discount		~~684~~323			~~1,448~~684
Other		(~~452~~355	)		(71452	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(31,~~617~~615	)	$	(73,~~637~~617	)

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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SIGNATURES

	RIDGEWOOD ENERGY K FUND, LLC
Date: March 23, 2010	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson
		Chief Executive Officer
		(Principal Executive Officer)

Signature	Capacity	Date
/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)	March 23, 2010
Robert E. Swanson
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer (Principal Accounting Officer)	March 23, 2010
Kathleen P. McSherry
RIDGEWOOD ENERGY CORPORATION
/s/ ROBERT E. SWANSON	Chief Executive Officer of Manager	March 23, 2010
Robert E. Swanson

Filing Compare · RIDGEWOOD ENERGY K FUND LLC