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. 000-51268

RIDGEWOOD ENERGY M FUND, LLC

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

13-4285167

(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 1622, ~~2010~~ 2011 there are 535.6818 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY M FUND, LLC

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

TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	9
	ITEM 1B	UNRESOLVED STAFF COMMENTS	9
	ITEM 2	PROPERTIES	9
	ITEM 3	LEGAL PROCEEDINGS	10
	ITEM 4	(REMOVED AND RESERVED)	10
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	10
	ITEM 6	SELECTED FINANCIAL DATA	10
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1011
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	15
	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	1615
	ITEM 9B	OTHER INFORMATION	16
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	1716
	ITEM 11	EXECUTIVE COMPENSATION	1817
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	1817
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	18
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	1918
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	19
		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 M 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 August 2, 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 September 7, 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 November 30, 2004. The Fund raised $78.9 million, and after payment of $12.2 million in offering fees, commissions and investment fees, the Fund had $66.7 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, 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.

The Manager is entitled to a 15% interest in cash distributions made by the Fund. ~~Distributions~~Effective ~~paid~~July to2009, the Manager ~~for~~elected ~~the~~to ~~years~~waive ~~ended~~its ~~December 31,~~right ~~2009~~to ~~and~~distributions ~~2008~~of ~~were~~available ~~$0.1~~cash ~~million~~from ~~and~~operations ~~$37~~for ~~thousand,~~the ~~respectively.~~remaining ~~Effective July~~life 1,of ~~2009,~~the Fund. Distributions paid to the Manager ~~elected~~during tothe ~~permanently~~year ~~waive~~ended ~~its~~December ~~right~~31, ~~to distributions~~2009 ~~from~~were ~~the~~$0.1 ~~Fund~~million.

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.

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 Management Services (“MMS”). 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 investments may require the Fund to pay a disproportionate part of the drilling costs on the exploratory well of a project than its working interest would otherwise require. This is called a promote, which is common in the oil and natural gas exploration industry. 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.

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

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

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 were complete and a project 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 was made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee sought to balance the economics of the projects, the potential sizes of the projects, the diversity of the operators, and the likely timing of new projects,. The Investment Committee also considered the geological, financial and operating risks of the proposed project and compared these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further focused on the initial well cost relative to the overall revenue potential of the project.

Post-Investment Activities

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

~~Properties~~Project Information

~~The~~Existing ~~Fund owns~~projects, ~~working~~and ~~interests~~future ~~and~~projects, ~~has~~if ~~participated~~any, are located in the ~~drilling~~waters of ~~fifteen wells. Four~~the ~~wells~~Gulf ~~are~~of ~~currently~~Mexico ~~producing~~offshore from Texas, Louisiana and ~~eleven~~Alabama ~~wells~~on ~~have~~the ~~been determined~~OCS. The OCSLA governs certain activities with respect to beworking ~~dry~~interests ~~holes~~and orthe ~~have~~exploration ~~been~~of ~~fully~~oil ~~depleted~~and natural gas in the OCS. See further discussion under the heading “Regulation” in Item 1. “Business” of this Annual Report.

Leases in the OCS are generally issued for a primary lease term of 5, 8 or 10 years depending on the water depth of the lease block. 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.

Table of Contents

				Off-shore
				Location in			Total Spent
	Working			Gulf of	Well		through
Lease Block	Interest			Mexico	Depth		12/31/2009
Discoveries					(feet)		(in thousands)
Whistler Project		20.0	%	Louisiana		4,400	$	4,022
South Marsh Island 111		8.75	%	Louisiana		11,600	$	2,428
West Delta 68		8.75	%	Louisiana		14,000	$	1,788
West Delta 67		8.75	%	Louisiana		14,000	$	1,150
Dry Holes (a)
2008
South Marsh Island 213		5.5	%	Louisiana		N/A	$	1,645
Fully Depleted
2009
Eugene Island 337		20.0	%	Louisiana		N/A	$	6,019
Vermilion 344		8.75	%	Louisiana		N/A	$	2,854
West Cameron 57		12.5	%	Louisiana		N/A	$	4,768
2008
West Cameron 77		14.5	%	Louisiana		N/A	$	8,784

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.

~~(a)~~Royalty ~~Dry-hole costs represent costs incurred for wells that have been drilled but do not have commercially productive quantities of oil and/or natural gas reservoirs and have been plugged and abandoned.~~Payments

~~Whistler Project~~Generally, working interests in an offshore oil and natural gas lease under the OCSLA pay a 16.67% or 18.75% royalty to the BOE for shallow-water projects, dependent upon the lease date, and a 12.5% royalty to the BOE for deepwater projects. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 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 a lease block. Other than BOE royalties, the Fund does not have material royalty burdens.

In July 2008, the Fund acquired a 20.0% working interest in the Whistler Project, an exploratory well. The Whistler Project was determined to be a discovery in November 2008 and production commenced in January 2010. Through December 31, 2009, the Fund has spent $4.0 million relating to this well, for which the Fund’s total estimated budget is $4.8 million. During the year ended December 31 2009, the Fund recorded an impairment of $2.1 million related to the Whistler Project.Properties

~~LLOG Projects~~Productive Wells

InThe ~~2006,~~ following table sets forth the number of productive oil and natural gas wells in which the Fund ~~acquired~~owned an ~~8.75%~~interest ~~working~~as ~~interest~~of inDecember ~~six~~31, ~~exploratory~~2010. Productive wells ~~which~~ are ~~operated~~ byproducing ~~LLOG~~wells ~~Exploration~~and ~~Offshore,~~wells ~~Inc~~capable of production. Gross ~~(“LLOG”),~~wells ~~off~~are the ~~coast~~total number of ~~Louisiana~~ wells in which the Fund has an interest. OfNet wells are the ~~six~~sum ~~wells,~~of the Fund’s ~~elected~~fractional ~~not~~working tointerests ~~proceed~~owned ~~with~~in ~~one well~~the ~~and~~gross ~~one~~wells. All ~~well~~of ~~was~~the ~~determined~~wells toare belocated ain ~~dry~~the ~~hole~~offshore waters of the Gulf of Mexico and are operated by third-party operators.

The Fund spent $8.2 million related to the four exploratory wells, which were determined to be discoveries during 2007. At December 31, 2009, the Fund has additional budgets for these wells of $0.6 million related to various recompletion efforts. At December 31, 2009, Vermilion 344 was determined to be fully depleted by the Fund’s independent petroleum engineer, Ryder Scott Company, L.P. (“Ryder Scott”). During the years ended December 31, 2009 and 2008, the Fund recorded impairments related to Vermilion 344 totaling $1.1 million and $1.3 million, respectively.

	Total Productive Wells
	Gross		Net
Oil and natural gas		4		0.39
Natural gas		1		0.20
Total		5		0.59

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

Acreage Data

~~Eugene Island~~The ~~337~~following table sets forth the Fund’s interests in developed oil and gas acreage as of December 31, 2010. The Fund did not have any interests in undeveloped oil and gas acreage as of December 31, 2010. Ownership interests generally take the form of working interests in oil and gas leases that have varying terms. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

In 2005, the Fund acquired a 20.0% working interest in Eugene Island 337, an exploratory well. The well was determined to be a discovery in July 2006 and production commenced in November 2007. During the third quarter 2008, the pipeline utilized to transport oil and natural gas production for Eugene Island 337 suffered damage as a result of hurricane activity, shutting down production until June 2009. At December 31, 2009, Eugene Island 337 was determined to be fully depleted. The Fund has spent $6.0 million relating to this well and recorded impairments totaling $5.7 million, of which $0.2 million was recorded during the year ended December 31, 2009.

Developed Acres
Gross		Net
	17,161		2,252

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

Table of Contents

West Cameron 57

			Total Spent		Total
	Working		through		Fund
Lease Block	Interest		December 31, 2010		Budget		Status
Producing Properties			(in thousands)
Whistler Project		20.0%	$	4,166	$	4,166	Production commenced January 2010. Well ceased production on March 1, 2011. See discussion below.
South Marsh Island 111		8.75%	$	2,405	$	2,808	Production commenced February 2009. Recompletion efforts to access behind the pipe reserves are expected to commence in March 2011 at an estimated cost of $0.4 million.
West Delta 67		8.75%	$	1,328	$	1,328	Production commenced in 2008. Recompletion activities completed in July 2010 and December 2010 at a total cost of $0.2 million.
West Delta 68		8.75%	$	2,092	$	2,105	Production commenced in 2008. Recompletion activities completed in July 2010 and January 2011 at a total cost of $0.3 million. Additional recompletion planned for 2013 at an estimated cost of $13 thousand.
West Cameron 57		12.5%	$	4,768	$	4,768	Production commenced in 2008. Working interest conveyed to operator effective February 1, 2011. See discussion below.
Fully Depleted - 2009
Eugene Island 337		20.0%	$	6,019		N/A	Determined to be fully depleted at December 31, 2009.
Vermilion 344		8.75%	$	2,854		N/A	Determined to be fully depleted at December 31, 2009.

InOn ~~2007~~March 1, 2011, the Fund ~~acquired~~was anotified ~~12.5%~~by ~~working~~the ~~interest~~operator inof ~~West~~the ~~Cameron~~Whistler ~~57,~~Project anthat ~~exploratory well.~~the ~~The~~ well ~~was~~had ~~determined~~reached tothe beend aof ~~discovery~~its ineconomic ~~February~~life, ~~2008~~ and that the production ~~commenced~~ inhandling ~~December~~agreement ~~2008. The~~entered ~~Fund~~into ~~has~~for ~~spent~~the ~~$4.8~~Whistler ~~million~~Project, ~~relating to~~had ~~this~~been ~~well~~terminated. ~~During~~As a result, for the year ended December 31, ~~2009~~2010, the Fund recorded an impairment ~~totaling~~of ~~$4.3~~oil ~~million~~and gas properties related to ~~West~~a ~~Cameron~~revision ~~57 as the well was determined~~ to bereserve ~~fully depleted~~estimates.

~~Working Interest~~Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in ~~Oil~~West Cameron 57 to Marlin Coastal, L.L.C. (“Marlin”), the operator of the well, in exchange for Marlin’s assumption of all future obligations and ~~Gas~~liabilities ~~Leases~~of the well. During the year ended December 31, 2009, the Fund recorded an impairment relating to West Cameron 57 as the Fund’s independent petroleum engineers did not assign any reserves to this well. During the year ended December 31, 2010, and through the date of the conveyance agreement, the well continued to produce small amounts of oil and gas.

~~Existing projects~~In April 2010, ~~and~~the ~~future~~Deepwater ~~projects~~Horizon, ifwhich ~~any~~was drilling a BP-operated project in the deepwater of the Gulf of Mexico, sank after an apparent blowout and fire. As of the date of this filing, the well has been permanently capped and environmental remediation efforts are ~~expected~~ongoing. toNeither bethe ~~located~~Fund nor any operators of the Fund’s projects owns an interest in the ~~waters~~ affected field. As a result of the explosion and resultant oil spill, the U.S. government placed a six-month moratorium on deepwater drilling operations in the Gulf of Mexico, ~~offshore~~which ~~from~~was ~~Texas~~lifted effective October 12, ~~Louisiana~~2010. The U.S. government has also implemented additional safety and ~~Alabama~~certification onrequirements applicable to drilling activities in the ~~OCS~~Gulf of Mexico. The extent to which these recent events may impact the Fund’s future results is uncertain. The ~~OCSLA~~ ~~governs~~Fund ~~certain~~cannot ~~activities~~predict ~~with~~how ~~respect~~federal and state authorities will further respond to ~~working~~the ~~interests~~incident or whether additional changes in laws and ~~the exploration~~regulations ofgoverning oil and ~~natural~~ gas operations in the ~~OCS~~Gulf of Mexico will result. ~~See~~Such ~~further~~changes, ~~discussion under~~if any, may impact the ~~heading~~way ~~“Regulation”~~the inFund ~~this~~conducts ~~Item~~business 1.and ~~“Business”~~may increase the Fund’s cost of doing business.

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.Marketing/Customers

~~Leases~~During in 2010, the ~~OCS~~Fund ~~are~~had ~~generally~~engaged ~~issued for~~ a ~~primary~~third-party ~~lease~~marketer ~~term~~to ofsell 5,the 8Fund’s orproportionate 10share ~~years depending~~of onoil ~~the~~and ~~water~~natural ~~depth~~gas ofto the ~~lease~~public ~~block~~market. The ~~5-year~~Fund ~~lease~~did ~~term~~not iscontract ~~for blocks~~to insell ~~water~~oil ~~depths~~and ~~generally~~natural ~~less~~gas ~~than~~to ~~400~~customers ~~meters~~and therefore, 8had ~~years~~no ~~for~~customers ~~depths between~~or ~~400~~any ~~meters~~one ~~and~~or ~~800~~few ~~meters~~major ~~and~~customers 10upon ~~years~~which ~~for~~it ~~depths in excess of 800 meters~~depends. Effective ~~During~~December ~~this primary lease term~~2010, ~~except~~the inFund ~~limited~~sells ~~circumstances,~~its ~~lessees are~~oil ~~not~~and ~~subject~~gas tothrough ~~any~~an ~~particular requirements to conduct exploratory or development activities. However~~agent, ~~once~~Energy ~~a lessee drills a well and begins production~~Upgrade, ~~the lease term is extended for the duration of commercial production~~Inc.

The ~~lessee~~ ofFund’s acurrent ~~particular~~projects ~~block,~~are ~~for~~near ~~the~~existing ~~term~~transportation ofinfrastructure ~~the lease, has the right to drill~~ and ~~develop exploratory wells and conduct other activities throughout the block~~pipelines. If The ~~the~~Manager ~~initial~~believes ~~well~~that onit ~~the block~~ is ~~successful,~~likely athat ~~lessee,~~oil ~~or third-party operator for a project, may conduct additional geological studies~~ and ~~may determine~~natural togas ~~drill~~from ~~additional or development wells. If a development well is to be drilled in~~ the ~~block,~~Fund’s ~~each~~future ~~lessee~~projects ~~owning~~will ~~working~~have ~~interests~~access ~~in the block must be offered the opportunity~~ to ~~participate~~pipeline ~~in,~~transportation and ~~cover~~can ~~the~~be ~~costs~~marketed ~~of,~~through ~~the development~~its ~~well up to that particular lessee’s working interest ownership percentage~~agent.

~~Generally, working~~Natural ~~interests~~gas is sold in ~~an offshore natural gas lease under~~ the ~~OCSLA~~spot ~~pay~~market aat ~~16.67% or~~prevailing ~~18.75% royalty to the MMS for shallow-water projects~~prices, ~~dependent~~which ~~upon~~fluctuate ~~the lease~~with ~~date,~~demand ~~and~~as a ~~12.5%~~result ~~royalty~~of torelated ~~the~~industry ~~MMS for deepwater projects~~variables. Oil ~~Therefore, the~~is ~~net~~generally ~~revenue~~sold ~~interest~~one ofmonth ~~the~~at ~~holders~~a oftime ~~100%~~at ofprevailing ~~the~~market ~~working~~prices. Historically, ~~interest in~~ the ~~projects~~ inmarkets ~~which~~for, ~~the~~and ~~Fund~~prices ~~will~~of, ~~invest~~oil ~~is between 81.25%~~ and ~~83.33%~~natural ofgas ~~the~~have ~~total revenue~~been ~~for~~extremely ~~shallow-water~~volatile, ~~projects~~ and ~~87.5%~~they ofare ~~the~~likely ~~total~~to ~~revenue~~continue ~~for~~to ~~deepwater projects,~~be ~~and~~volatile ~~such~~in ~~net~~the ~~revenue~~future. ~~amount~~This volatility is ~~further~~ ~~reduced~~caused by ~~any~~numerous ~~other royalty~~factors ~~burdens~~and market conditions that ~~apply~~the toFund acannot ~~lease~~control ~~block. However,~~or asinfluence; ~~described below~~therefore, ~~the~~it ~~MMS~~is ~~has~~impossible ~~adopted~~to ~~royalty~~predict ~~relief~~the ~~for~~future ~~existing~~price ~~OCS~~of ~~leases for those who drill deep~~ oil and natural gas ~~projects~~with any certainty. ~~Other~~ Low ~~than~~commodity ~~MMS~~prices ~~royalties, the~~could ~~Fund~~have ~~does~~an ~~not~~adverse ~~have~~affect ~~material~~on ~~royalty~~the ~~burdens~~Fund’s future profitability.

Mineral Management Services Deep Gas Royalty Incentive

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. At ~~Currently~~December 31, 2010, the Fund’'s producing properties ~~are~~ were operated by Helis Oil and Gas Company, L.L.C., LLOG Exploration Offshore, Inc. and ~~LLOG~~Marlin Coastal, L.L.C.

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-~~evaluate~~evaluates ~~its~~the insurance coverage on an annual basis. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims to the Fund’'s affiliates, yearly insurance limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.

Salvage Fund

As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or salvage fund, ~~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 $1.9 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.

Seasonality

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

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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, West Delta 68 and West Delta 67 were shut-in for approximately one month, with production resuming in October 2008 and Eugene Island 337 well was shut-in for approximately ten months, with production resuming in June 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. As Although the Fund ~~has~~does ~~reached~~not ~~the~~compete ~~end~~for oflease ~~its~~acquisitions ~~investment~~from ~~cycle~~the BOE, it no ~~longer~~does ~~competes~~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 larger and have significant resources, they tend to focus more on projects that are larger, have greater reserve potential, and cost significantly more to explore and develop. The focus of these companies on larger projects does not necessarily mean that they will not investigate and/or acquire projects for which the Fund typically competes. The Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, (ii) Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint, and (iii) Ridgewood Energy is typically not viewed as a competitor by the syndicating operator, as Ridgewood Energy does not participate in lease block sales but principally invests in drill-ready syndicated projects.

Employees

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

Offices

The principal executive office of each 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.

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The ~~MMS~~ 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 ~~MMS~~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 ~~MMS~~ 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 ~~length~~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, ~~through~~to the ~~operator~~market ~~on the~~through ~~Fund’s~~an ~~behalf~~agent toor ~~the~~a ~~market~~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.

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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.

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~~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		0.20		1		0.09
Nonproductive		-		-		-		-
In-progress		-		-		1		0.20
Exploratory well total		1		0.20		2		0.29

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 primary technical person in charge of overseeing the Fund’s ~~reserve~~reserves estimates athas ~~December~~a ~~31,~~B.S. ~~2009~~degree ~~and~~in ~~2008~~Petroleum ~~were~~Engineering ~~prepared~~and byis ~~Ryder Scott,~~a anmember ~~independent~~of ~~petroleum~~the ~~engineering~~Society ~~firm. The~~of ~~information regarding~~Petroleum Engineers, the ~~qualifications~~Association of ~~the~~American ~~petroleum~~Drilling ~~engineer~~Engineers isand ~~included~~the ~~within~~American ~~the report~~Petroleum ~~from~~Institute. With ~~Ryder~~over ~~Scott~~twenty years of industry experience, ~~which~~he is ~~included~~currently asresponsible ~~Exhibit~~for 99reserve reporting, engineering and economic evaluation of ~~this~~exploration ~~Annual~~and ~~Report~~development opportunities, and isthe ~~incorporated~~oversight ~~herein~~of bydrilling ~~reference~~and production operations.

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.

Proved Undeveloped Reserves. At December 31, 2009, the Fund had approximately 934 barrels and 742 thousand mcf of proved undeveloped oil and natural gas reserves, respectively, attributable to South Marsh Island 111 and the Whistler Project. The proved undeveloped reserves relating to the Whistler Project, consisting of 556 thousand mcf of natural gas, were fully developed and the Whistler Project commenced production in January 2010. The Fund is currently evaluating the development alternatives for the proved undeveloped reserves related to South Marsh Island 111. At December 31, 2008, the Fund had no proved undeveloped oil reserves and approximately 556 thousand mcf of proved undeveloped natural gas reserves, which were attributable to the Whistler Project.

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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 934 barrels and 742 thousand mcf of proved undeveloped oil and natural gas reserves, respectively, attributable to South Marsh Island 111 and the Whistler Project. During 2010, the proved undeveloped reserves relating to the Whistler Project, consisting of 556 thousand mcf of natural gas, were developed and the Whistler Project commenced production in January 2010. Additionally, 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 were borne by the Manager.

Legal costs related to this claim are borne by the Manager.

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~~ ~~16,~~the ~~2010~~date of this filing, there were ~~954~~956 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. Effective July 2009, 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 totaling $01.74 million and $0.2 7 million, respectively. ~~Effective July 1, 2009, 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 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 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” for additional 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 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.

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ITEM 7.

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

Overview of the Fund’s Business

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

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

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

Critical Accounting Estimates

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

Accounting for Exploration and Development Costs

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

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~~expensed ~~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.

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.

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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

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Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, ~~2009~~2010 and ~~2008~~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.

	Year ended December 31,
	2009			2008
	2010			2009
	(in thousands)
Revenue
Oil and gas revenue	$	2,~~004~~764		$	12,~~369~~004
Expenses
Depletion and amortization		2,~~675~~199			~~732~~2,675
Dry-hole costs		~~(99~~74	)		~~1,700~~(99	)
Impairment of proved properties, net		7,688			7,688
Impairment of oil and gas properties		1,231			7,688
Workover expenses		25			909
Operating expenses		477			452
Operating expenses		427			246
General and administrative expenses		313			300
General and administrative expenses		300			489
Total expenses		4,294			11,016
Total expenses		11,016			11,764
Loss from operations		(1,530	)		(9,012	)
Loss from operations		(9,012	)		(10,395	)
Other income
Interest income		29			~~181~~29
Net loss	$	(81,~~983~~501	)	$	(108,~~214~~983	)

Overview. During the year ended December 31, 2009, the Fund had six producing wells. Eugene Island 337 commenced production in 2007, West Delta 67 and West Delta 68 commenced production in July 2008, West Cameron 57 and Vermilion 344 commenced production in December 2008, and South Marsh Island 111 commenced production in February 2009. Eugene Island 337, Vermilion 344 and West Cameron 57 were determined to be fully depleted at December 31, 2009. During the year ended December 31, 2008 the Fund had six producing wells consisting of Eugene Island 337, West Delta 67, West Delta 68, West Cameron 57, Vermilion 344 and West Cameron 77. West Cameron 77 was determined to be fully depleted at December 31, 2008. Oil and gas sales were all located within the United States.

As previously discussed in Item 1. “Business”, the pipeline utilized to transport Eugene Island 337’s oil and gas production suffered damage as a result of hurricane activity in the third quarter of 2008, thereby shutting down production for Eugene Island 337, which resumed production in June 2009.

Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, 2009 was $2.0 million, a $0.6 million increase from the year ended December 31, 2008. The increase is primarily attributable to an increase in sales volumes of $2.8 million, partially offset by the impact of lower average prices of $2.3 million.

Oil sales volumes were 6 thousand barrels during the year ended December 31, 2009 compared to 4 thousand barrels during the year ended December 31, 2008. The Fund’s oil prices averaged $52 per barrel and $88 per barrel during the years ended December 31, 2009 and 2008, respectively.

Gas sales volumes were 418 thousand mcf during the year ended December 31, 2009, compared to 111 thousand mcf during the year ended December 31, 2008. The Fund’s gas prices averaged $3.81 per mcf and $8.68 per mcf during the years ended December 31, 2009 and 2008, respectively.

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Overview. The ~~increase~~ inFund’s ~~oil~~revenue, depletion and ~~gas~~amortization, ~~volumes~~and ~~for~~lease operating expense were affected by the timing of the onset of production of the Fund’s wells and by the impact of well maintenance activities. During the year ended December 31, ~~2009~~2010, the Fund had five wells that produced for a total of 1,150 days, compared to six wells that produced for a total of 1,351 days during the year ended December 31, ~~2008~~2009. ~~was~~The ~~primarily~~decrease ~~attributable~~in tototal ~~the~~production ~~timing~~days ofwas the ~~onset~~ result of ~~production~~two of the Fund’s wells being fully depleted at December 31, as2009 ~~discussed~~coupled ~~above~~with inan ~~“Overview~~increase of the number of non-productive days related to maintenance activities.” ~~This increase~~These ~~was~~decreases were partially offset by ~~lower~~the ~~gas~~onset ~~sales~~of ~~volumes~~production ~~for~~of ~~West~~the ~~Cameron~~Whistler 77Project in January 2010. During the year ended December 31, ~~which~~ ~~was~~2010, ~~fully~~the ~~depleted~~Fund's atwells' production rate averaged 506 mcfe/producing day, compared to 349 mcfe/producing day during the year ended December 31, ~~2008~~2009. ~~and~~The ~~lower~~increase ~~gas~~was ~~sales~~primarily ~~volumes~~related ~~for Eugene~~to ~~Island~~the ~~337~~composite of the Fund’s wells, which ~~suffered~~have ~~damage~~varying asamounts aof ~~result~~working ofinterest ~~hurricane~~ownership, ~~activity~~partially offset by natural declines in production. Effective February 1, 2011, the ~~third~~Fund ~~quarter~~entered into an agreement to convey its working interest in West Cameron 57 to the operator of ~~2008~~the well, ~~shutting~~and ~~down~~in March 2011, the Fund was notified that the Whistler Project had reached the end of its ~~production~~economic ~~until~~life. ~~June 2009~~See Note 9 of Notes to Financial Statements – “Subsequent Events” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for additional information.

~~Depletion~~Oil and ~~Amortization~~ Gas Revenue. ~~Depletion~~ Oil and ~~amortization~~gas revenue for the year ended December 31, ~~2009~~2010 was $2.78 million, a $10.98 million increase from the year ended December 31, ~~2008~~2009. The increase ~~resulted~~is ~~from~~attributable to an increase in ~~production~~ sales volumes totaling $10.75 million, coupled with anthe ~~increase~~impact inof increased average ~~depletion~~ ~~rates~~prices totaling $0.23 million. The increase in depletion rates was primarily the result of higher cost reserve additions, principally attributable to Vermilion 344, South Marsh Island 111 and West Cameron 57, partially offset by lower cost reserve additions, principally attributable to West Delta 67 and West Delta 68 and decreased rates for Eugene Island 337 attributable to the impairment charges taken for that well.

~~Dry-hole Costs. Dry-hole~~Oil ~~costs~~sales ~~are~~volumes ~~those costs~~were ~~incurred~~3 tothousand ~~drill~~barrels and ~~develop~~6 athousand ~~well~~barrels ~~that~~for isthe ~~ultimately~~years ~~found~~ended toDecember ~~be incapable~~31, of2010 ~~producing~~and ~~either~~2009, ~~oil~~respectively. The orFund’s ~~natural~~oil ~~gas~~prices inaveraged ~~sufficient~~$78 ~~quantities~~per ~~to justify~~barrel ~~completion~~during of the ~~well. At~~year ~~times,~~ended ~~the~~December ~~Fund~~31, ~~receives~~2010 ~~credits on~~compared ~~certain~~to ~~wells~~$54 ~~from~~per ~~their~~barrel ~~respective~~during ~~operators upon review and audit of~~ the ~~wells’~~ ~~costs. Dry-hole~~year ~~costs,~~ended ~~inclusive~~December ~~of such credits~~31, ~~are detailed in the following table~~2009.

	Year ended December 31,
Lease Block	2009			2008
	(in thousands)
South Marsh Island 213	$	(43	)	$	1,688
Other wells		(56	)		12
	$	(99	)	$	1,700

Gas sales volumes were 508 thousand mcf and 417 thousand mcf for the years ended December 31, 2010 and 2009, respectively. The Fund’s gas prices averaged $4.24 per mcf during the year ended December 31, 2010 compared to $3.84 per mcf during the year ended December 31, 2009.

~~Impairment~~The decrease in oil volumes was principally attributable to a reduction in the number of ~~Proved~~ ~~Properties,~~production ~~net~~days. ~~During~~The increase in gas volumes was principally attributable to the ~~years~~onset ~~ended~~of ~~December~~production ~~31, 2009~~of ~~and~~the ~~2008~~Whistler Project, ~~the~~which ~~Fund~~produces ~~recorded~~only ~~impairments~~gas, topartially ~~proved~~offset ~~properties~~by asthe ~~detailed~~reduction in the ~~following~~number ~~table~~of production days. See “Overview” above for additional information.

	Year ended December 31,
	2009			2008
	(in thousands)
West Cameron 57	$	4,275		$	-
Whistler Project		2,073			-
Vermilion 344		1,083			1,325
Eugene Island 337		217			570
West Cameron 77		86			6,263
Eugene Island 364		(46	)		(470	)
	$	7,688		$	7,688

Depletion and Amortization. Depletion and amortization for the year ended December 31, 2010 was $2.2 million, a decrease of $0.5 million from the year ended December 31, 2009. The decrease resulted from a decrease in average depletion rates totaling $0.8 million, partially offset by an increase in production volumes totaling $0.3 million. The decrease in average depletion rates was primarily the result of the composite of productive wells.

~~During the~~Dry-hole ~~year~~Costs. Dry-hole ~~ended~~costs ~~December~~are ~~31,~~those ~~2009,~~costs ~~the~~incurred ~~impairments~~ to ~~Eugene~~drill ~~Island 337~~ and ~~West Cameron~~develop 57a ~~were~~well ~~primarily the result of the determination~~ that ~~such~~is ~~wells~~ultimately ~~were fully~~found ~~depleted. The impairments~~ to ~~Vermilion~~be ~~344~~incapable ~~were~~of ~~attributable~~producing ~~to lower~~either oil ~~and~~or natural gas ~~commodity~~in ~~prices,~~sufficient ~~revisions~~quantities to ~~reserve~~justify ~~estimates,~~completion ~~and~~of the ~~year-end~~ ~~determination that the~~ well ~~was fully depleted~~. ~~The impairment~~At totimes, the ~~Whistler~~Fund ~~Project~~receives ~~was~~credits ~~the~~on ~~result~~certain ofwells ~~increased~~from ~~project~~their ~~costs~~respective ~~and lower~~operators ~~oil~~upon review and ~~gas~~audit ~~commodity~~of ~~prices~~the wells’ costs. The ~~impairments~~Fund ~~related~~had todry ~~West Cameron~~hole 77costs ~~and Eugene Island 364 were the result~~ of ~~revisions~~$0.1 tomillion ~~asset retirement~~during ~~cost estimates. During~~ the year ended December 31, ~~2008, the~~2010 ~~impairments to Vermilion 344~~ and ~~Eugene~~credits ~~Island 337 were the result of lower oil and gas commodity prices and the impairment~~ to ~~West~~dry-hole ~~Cameron~~costs ~~77 was the result~~ of ~~the determination that such well was fully depleted~~$0. ~~Additionally,~~1 million during the year ended December 31, ~~2008, the Fund received a $0~~2009.~~5 million credit related to the previously impaired Eugene Island 364 as a result of its operator’s review of the well’s cost.~~

~~Workover Expenses.~~Impairment ~~Workover~~of ~~expenses~~Oil ~~represent~~and ~~costs~~Gas toProperties. During ~~restore~~the oryear ~~stimulate production~~ended ofDecember ~~existing~~31, ~~reserves~~2010, ofthe aFund ~~proved~~recorded ~~property. Workover expenses~~impairments of ~~$25~~oil ~~thousand~~and ~~during~~gas ~~the~~properties ~~year~~totaling ~~ended~~$1.2 ~~December 31~~million, ~~2009~~which were ~~primarily~~ attributable to ~~West~~revisions ~~Delta~~in ~~67. Workover~~reserve ~~expenses~~estimates ofrelated ~~$0.9~~to ~~million during~~South Marsh Island 111 and the Whistler Project and adjustments to asset retirement obligations for fully depleted wells. During the year ended December 31, ~~2008~~2009, ~~were~~the ~~attributable~~Fund torecorded ~~recompletion efforts~~impairments ~~for~~of ~~the~~oil ~~upper~~and ~~reservoir~~gas ~~zone~~properties oftotaling ~~West~~$7.7 ~~Cameron 77~~million, which ~~ultimately~~were ~~proved unsuccessful~~primarily attributable to revisions to reserve estimates, including revisions resulting from fully depleted wells.

Operating Expenses. Operating expenses ~~include~~represent ~~the~~ costs ofspecifically ~~operating~~identifiable ~~and maintaining~~or ~~wells~~allocable ~~and related facilities, geological costs and accretion expense related~~ to ~~asset~~the ~~retirement~~Fund's ~~obligations~~wells, as detailed in the following table.

	Year ended December 31,
	2010		2009
	(in thousands)
Lease operating expense	$	458	$	407
Accretion expense		19		20
Workover expense		-		25
	$	477	$	452

Lease operating expense was related to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $0.79 per mcfe for the year ended December 31, 2010 compared to $0.86 per mcfe during the year ended December 31, 2009. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties. Workover expenses represent costs to restore or stimulate production of existing reserves of a proved property. During the year ended December 31, 2009, workover expenses were primarily attributable to West Delta 67.

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	Year ended December 31,
	2009		2008
	(in thousands)
Lease operating expense	$	407	$	155
Geological costs		-		75
Accretion expense		20		16
	$	427	$	246

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 $0.86 per mcfe compared to $1.12 per mcfe for the year ended December 31, 2008. Geological costs for the year ended December 31, 2008 related primarily to the Whistler project. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.

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)	~~(in thousands)~~
Accounting fees		$	~~139~~124	$	~~175~~139
Management reimbursement			80		80
Insurance expense			109		80
Insurance expense			80		217
Management reimbursement and other			80		81
Trust fees and other			1		17
		$	313	$	300
		$	300	$	489

Accounting fees represent audit and tax preparation fees, quarterly ~~review~~reviews and filing fees incurred by the Fund. ~~Management reimbursement relates to reimbursement 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. ~~Trust~~ Management ~~fees~~reimbursement ~~represent~~and ~~bank~~other ~~fees~~expenses ~~associated~~relate ~~with~~primarily ~~the~~to ~~management~~reimbursements offor various administrative costs incurred on the Fund’s ~~cash accounts~~behalf.

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~~ was $29 thousand, afor ~~$0.2~~each ~~million~~of ~~decrease from~~ the ~~year~~years ended December 31, ~~2008. The~~ ~~decrease~~2010 ~~was attributable to a reduction in the average outstanding balances earning interest due to ongoing capital expenditures for oil~~ and ~~gas properties, coupled with lower interest rates earned~~2009.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, ~~2009~~2010 were $1.47 million, primarily related to revenue ~~receipts~~received of $2.17 million, partially offset by operating ~~and workover~~ expenses ~~totaling~~of $0.5 million, ~~and~~ general and administrative expenses of $0.3 million and settlement of asset retirement obligations of $0.2 million.

Cash flows ~~used~~provided inby operating activities for the year ended December 31, ~~2008~~2009 were $01.24 million, primarily related to ~~workover~~revenue ~~expenses~~received of $02.91 million, ~~general and~~partially ~~administrative~~offset ~~expenses~~by ~~of $0.5 million,~~ operating expenses of $0.25 million and ~~unfavorable~~general ~~working capital of $0.1 million, partially offset by revenue received of $1.4 million~~ and ~~interest~~administrative ~~received~~expenses of $0.23 million.

Investing Cash Flows

Cash flows used in investing activities for the year ended December 31, 2010 were $1.2 million, primarily related to capital expenditures for oil and gas properties of $1.4 million, inclusive of advances, partially offset by proceeds from the salvage fund totaling $0.2 million.

Cash flows used in investing activities for the year ended December 31, 2009 were $3.0 million, related to capital expenditures for oil and gas properties of $2.1 million and salvage fund investments of $0.9 million.

Cash flows used in investing activities for the year ended December 31, 2008 were $4.0 million, related to capital expenditures for oil and gas properties of $9.1 million, partially offset by proceeds from the maturity of U.S. Treasury securities of $5.1 million.

Financing Cash Flows

Cash flows used in financing activities for the year ended December 31, 2010 were $1.4 million related to shareholder distributions.

Cash flows used in financing activities for the year ended December 31, 2009 were $0.7 million related to manager and shareholder distributions.

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Cash flows used in financing activities for the year ended December 31, 2008 were $0.2 million related to manager and 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 $10.4 million ~~related~~relating to its investment properties~~. The~~, ~~Fund~~principally ~~does~~all ~~not~~of ~~expect~~which is expected to ~~participate~~be inspent ~~any~~during ~~additional investment~~the ~~properties~~next twelve months.

Capital expenditures for investment properties ~~are~~were 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 iswas limited and each unsuccessful project the Fund experienced reduced its ability to generate revenue and exhausted its capital.

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. ~~The Fund has reached the end of its investment cycle.~~ At December 31, ~~2009~~ 2010, the Fund ~~has~~had ~~capital~~ commitments ofrelated ~~$1.4~~to ~~million that exceed, by $1.0 million,~~ its ~~current~~investment ~~available~~properties ~~working~~totaling ~~capital of~~ $0.4 million. Based upon its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover these ~~deficiencies~~commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. In the event of a temporary production stoppage, causing the Fund’s wells to not produce cash flow from operations, the Fund may borrow from the Manager until such time that production is resumed. At such time the Manager determines that the Fund is no longer capable of continuing to fund its operations, the Manager would elect to dissolve the Fund.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and the Fund’s operations. Effective July 1, 2009, the Manager elected to permanently waive its right to distributions from the Fund. During the third quarter 2009, the Manager suspended Fund distributions to shareholders through December 2009. The Manager continues to evaluate the Fund’s ability to make distributions on a month-to-month basis. As of the date of this filing, the Manager has not resumed distributions to shareholders.14

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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. Effective July 1, 2009, the Manager elected to permanently waive its right to distributions of available cash from operations for the remaining life of the Fund.

Off-Balance Sheet Arrangements

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

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate ~~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.

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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.

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.15

~~Management of~~Table ~~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. 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, the Fund’s internal control over financial reporting is effective.Contents

~~This Annual~~Because ~~Report~~of ~~does~~its ~~not~~inherent ~~include~~limitations, aninternal ~~attestation~~control ~~report~~over offinancial ~~the~~reporting ~~Fund’s~~may ~~registered public~~not ~~accounting~~prevent ~~firm~~or ~~regarding~~detect ~~internal~~misstatements. Also, ~~control~~projections ~~over~~of ~~financial~~any ~~reporting. Management’s~~evaluation ~~report~~of ~~was~~effectiveness ~~not~~to ~~subject~~future toperiods ~~attestation~~are bysubject to the ~~Fund’s~~risk ~~registered public~~that ~~accounting~~controls ~~firm~~may ~~pursuant~~become toinadequate ~~temporary~~because ~~rules~~ of ~~the~~changes ~~Securities~~in ~~and Exchange~~conditions, ~~Commission~~or that ~~permit~~ the ~~Fund~~degree toof ~~provide~~compliance ~~only~~with ~~management’s~~the ~~report~~policies ~~in this~~or ~~Annual~~procedures ~~Report~~may deteriorate.

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

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

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, ~~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.

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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:

				Ridgewood Energy
			Officer of
Name, Age and Position with Registrant				Corporation Since
			Ridgewood Energy
Robert E. Swanson, 62
Name, Age and Position with Registrant			Corporation Since
	Chief Executive Officer			1982
Robert E. Swanson, 63
Kenneth W. Lang, 55
	Chief Executive Officer		1982
	President and Chief Operating Officer			2009
Kenneth W. Lang, 56
Kathleen P. McSherry, 44
	President and Chief Operating Officer		2009
	Executive Vice President and
Kathleen P. McSherry, 45
	Chief Financial Officer			2001
	Executive Vice President and
Robert L. Gold, 51
		Chief Financial Officer	2001
	Executive Vice President			1987
Robert L. Gold, 52
Daniel V. Gulino, 49
	Executive Vice President		1987
	Senior Vice President and General Counsel			2003
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 August 2, 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.16

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.

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 served as Senior Vice President and General Counsel of Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President and General Counsel of Ridgewood Renewable Power, Ridgewood Capital Management and 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.

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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.

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

Board of Directors and Board Committees

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

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 table sets forth information with respect to beneficial ownership of the ~~shares~~Shares as of March 1622, ~~2010~~2011 (no person owns more than 5% of the ~~shares~~Shares) by:

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•

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 535.6818 shares outstanding at March 1622, ~~2010~~2011. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

Name of beneficial owner	Number of shares	Percent
Robert E. Swanson, Chief Executive Officer (1)	7.~~3333~~0	1.373%
Executive officers as a group (1)	7.~~3333~~0	1.373%

(1) Includes ~~shares~~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 2007, 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.

18The Manager is entitled to receive a 15% interest in the cash distributions made by the Fund. Effective July 2009, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. Distributions paid to the Manager for the year ended December 31, 2009 were $0.1 million.

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The Manager is entitled to receive a 15% interest in the cash distributions made by the Fund. For the years ended December 31, 2009 and 2008, the Manager was paid distributions totaling $0.1 million and $37 thousand, respectively. Effective July 1, 2009, the Manager elected to permanently waive its distributions.

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.

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.

(a) (3)
Exhibit Number	Title of Exhibit	Method of Filing

3.1	Certificate of Formation of Ridgewood Energy M Fund, LLC dated August 2, 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 M Fund, LLC dated September 7, 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 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

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(a) (3)
Exhibit Number	Title of Exhibit	Method of Filing
3.1	Articles of Formation of Ridgewood Energy M Fund, LLC dated August 2, 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 M Fund, LLC dated September 7, 2004	Incorporated by reference to the Fund's Form 10 filed on April 29, 2005
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Securities Exchange Act Rule 13a-14(a)	Filed herewith
31.2	Certification of Kathleen P. McSherry, Chief Financial Officer of the Fund, pursuant to Securities Exchange Act Rule 13a-14(a)	Filed herewith
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Chief Financial Officer of the Fund	Filed herewith
99	Report of Ryder Scott Company, L.P.	Filed herewith

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 M FUND, LLC


Date: March 22, 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

		March 22, 2011
/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)	March 22, 2011
Robert E. Swanson	Chief Executive Officer (Principal Executive Officer)


/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 22, 2011
Kathleen P. McSherry

RIDGEWOOD ENERGY CORPORATION

BY: /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	March 22, 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, 2009 and 2008	F-3
Balance Sheets as of December 31, 2010 and 2009	F-3
Statements of Operations for the years ended December 31, 2009 and 2008	F-4
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, 2009 and 2008	F-5
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, 2009 and 2008	F-6
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-1312

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying balance sheets of Ridgewood Energy M 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 M 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 1622, ~~2010~~ 2011

F-2

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RIDGEWOOD ENERGY M FUND, LLC

RIDGEWOOD ENERGY M FUND, LLC
BALANCE SHEETS
(in thousands, except share data)
	December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	421		$	1,304
Production receivable		131			51
Other current assets		39			29
Total current assets		591			1,384
Salvage fund		1,777			2,025
Oil and gas properties:
Advances to operators for working interests and expenditures		156			-
Proved properties		10,430			9,982
Less: accumulated depletion and amortization		(6,983	)		(3,503	)
Total oil and gas properties, net		3,603			6,479
Total assets	$	5,971		$	9,888

LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators	$	96		$	799
Asset retirement obligations		862			-
Accrued expenses		96			235
Total current liabilities		1,054			1,034
Asset retirement obligations		863			1,910
Total liabilities		1,917			2,944

Commitments and contingencies (Note 8)
Members' capital:
Manager:
Distributions		(1,551	)		(1,551	)
Retained earnings		324			60
Manager's total		(1,227	)		(1,491	)
Shareholders:
Capital contributions (834 shares authorized; 535.6818 issued and outstanding)		78,887			78,887
Syndication costs		(8,597	)		(8,597	)
Distributions		(10,178	)		(8,789	)
Accumulated deficit		(54,831	)		(53,066	)
Shareholders' total		5,281			8,435
Total members' capital		4,054			6,944
Total liabilities and members' capital	$	5,971		$	9,888

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

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	1,304		$	3,687
Production receivable		51			110
Other current assets		29			87
Total current assets		1,384			3,884
Salvage fund		2,025			1,139
Oil and gas properties:
Unproved properties		-			1,882
Proved properties		9,982			20,346
Less: accumulated depletion and amortization		(3,503	)		(7,537	)
Total oil and gas properties, net		6,479			14,691
Total assets	$	9,888		$	19,714
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators	$	799		$	1,337
Accrued expenses		235			50
Total current liabilities		1,034			1,387
Asset retirement obligations		1,910			1,651
Total liabilities		2,944			3,038
Commitments and contingencies (Note 8)
Members' capital:
Manager:
Distributions		(1,551	)		(1,439	)
Retained earnings (accumulated deficit)		60			(28	)
Manager's total		(1,491	)		(1,467	)
Shareholders:
Capital contributions (834 shares authorized; 535.6818 issued and outstanding)		78,887			78,887
Syndication costs		(8,597	)		(8,597	)
Distributions		(8,789	)		(8,152	)
Accumulated deficit		(53,066	)		(43,995	)
Shareholders' total		8,435			18,143
Total members' capital		6,944			16,676
Total liabilities and members' capital	$	9,888		$	19,714

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

F-3

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RIDGEWOOD ENERGY M FUND, LLC

RIDGEWOOD ENERGY M FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)

	Year ended December 31,
	2010			2009
Revenue
Oil and gas revenue	$	2,764		$	2,004

Expenses
Depletion and amortization		2,199			2,675
Dry-hole costs		74			(99	)
Impairment of oil and gas properties		1,231			7,688
Operating expenses		477			452
General and administrative expenses		313			300
Total expenses		4,294			11,016
Loss from operations		(1,530	)		(9,012	)
Other income
Interest income		29			29
Net loss	$	(1,501	)	$	(8,983	)

Manager Interest
Net income	$	264		$	88

Shareholder Interest
Net loss	$	(1,765	)	$	(9,071	)
Net loss per share	$	(3,295	)	$	(16,934	)

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

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2009			2008
Revenue
Oil and gas revenue	$	2,004		$	1,369
Expenses
Depletion and amortization		2,675			732
Dry-hole costs		(99	)		1,700
Impairment of proved properties, net		7,688			7,688
Workover expenses		25			909
Operating expenses		427			246
General and administrative expenses		300			489
Total expenses		11,016			11,764
Loss from operations		(9,012	)		(10,395	)
Other income
Interest income		29			181
Net loss	$	(8,983	)	$	(10,214	)
Manager Interest
Net income (loss)	$	88		$	(125	)
Shareholder Interest
Net loss	$	(9,071	)	$	(10,089	)
Net loss per share	$	(16,934	)	$	(18,834	)

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

F-4

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RIDGEWOOD ENERGY M FUND, LLC

RIDGEWOOD ENERGY M FUND, LLC
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(in thousands, except share data)


	# of Shares		Manager			Shareholders			Total

Balances, December 31, 2008		535.6818	$	(1,467	)	$	18,143		$	16,676
Distributions		-		(112	)		(637	)		(749	)
Net income (loss)		-		88			(9,071	)		(8,983	)
Balances, December 31, 2009		535.6818		(1,491	)		8,435			6,944
Distributions		-		-			(1,389	)		(1,389	)
Net income (loss)		-		264			(1,765	)		(1,501	)
Balances, December 31, 2010		535.6818	$	(1,227	)	$	5,281		$	4,054

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

STATEMENTS OF CHANGES IN MEMBERS’ CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2007		535.6818	$	(1,305	)	$	28,439		$	27,134
Distributions		-		(37	)		(207	)		(244	)
Net loss		-		(125	)		(10,089	)		(10,214	)
Balances, December 31, 2008		535.6818	$	(1,467	)	$	18,143		$	16,676
Distributions		-		(112	)		(637	)		(749	)
Net income (loss)		-		88			(9,071	)		(8,983	)
Balances, December 31, 2009		535.6818	$	(1,491	)	$	8,435		$	6,944

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

F-5

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RIDGEWOOD ENERGY M FUND, LLC

RIDGEWOOD ENERGY M FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
	Year ended December 31,
	2010			2009
Cash flows from operating activities
Net loss	$	(1,501	)	$	(8,983	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion and amortization		2,199			2,675
Dry-hole costs		74			(99	)
Impairment of oil and gas properties		1,231			7,688
Accretion expense		19			20
Changes in assets and liabilities:
(Increase) decrease in production receivable		(80	)		59
(Increase) decrease in other current assets		(5	)		58
Increase in due to operators		48			3
Decrease in accrued expenses		(89	)		(35	)
Settlement of asset retirement obligations		(204	)		-
Net cash provided by operating activities		1,692			1,386

Cash flows from investing activities
Payments to operators for working interests and expenditures		(156	)		-
Capital expenditures for oil and gas properties		(1,278	)		(2,134	)
Proceeds from (investments in) salvage fund, net		248			(886	)
Net cash used in investing activities		(1,186	)		(3,020	)

Cash flows from financing activities
Distributions		(1,389	)		(749	)
Net cash used in financing activities		(1,389	)		(749	)

Net decrease in cash and cash equivalents		(883	)		(2,383	)
Cash and cash equivalents, beginning of year		1,304			3,687
Cash and cash equivalents, end of year	$	421		$	1,304


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

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2009			2008
Cash flows from operating activities
Net loss	$	(8,983	)	$	(10,214	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion and amortization		2,675			732
Dry-hole costs		(99	)		1,700
Impairment of proved properties		7,688			7,688
Settlement of asset retirement obligations		-			(35	)
Accretion expense		20			16
Interest earned on marketable securities		-			(36	)
Changes in assets and liabilities:
Decrease in production receivable		59			9
Decrease in other current assets		58			9
Increase in due to operators		3			27
Decrease in accrued expenses		(35	)		(87	)
Net cash provided by (used in) operating activities		1,386			(191	)
Cash flows from investing activities
Capital expenditures for oil and gas properties		(2,134	)		(9,124	)
Proceeds from the maturity of marketable securities		-			5,111
Investments in salvage fund		(886	)		(28	)
Net cash used in investing activities		(3,020	)		(4,041	)
Cash flows from financing activities
Distributions		(749	)		(244	)
Net cash used in financing activities		(749	)		(244	)
Net decrease in cash and cash equivalents		(2,383	)		(4,476	)
Cash and cash equivalents, beginning of year		3,687			8,163
Cash and cash equivalents, end of year	$	1,304		$	3,687
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$	-		$	66

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

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RIDGEWOOD ENERGY M FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Purpose

The Ridgewood Energy M Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 2, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated September 7, 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. ~~Effective~~Federally ~~January 1, 2010, the federally~~ insured limits of the Fund’s deposits are $250 thousand per insured financial institution. ~~Based~~At ~~upon these limits, at~~ December 31, ~~2009~~ 2010, the Fund’s bank balances ~~would have~~ exceeded federally insured limits by $0.9 2 million, of which $0.61 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 held-to-maturity investments in U.S. Treasury securities, within its salvage fund, of $0.7 million, ~~$0.2~~which ~~million~~matured in March 2011 and $1.10 million, which ~~mature~~ matures in ~~November 2010, December 2010 and~~ February 2012~~, respectively, that are classified as held-to-maturity investments~~. 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.

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

Oil and Gas Properties

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

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

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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 to dry-hole expense. 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.

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 $~~0.8 million~~4 thousand and $10.38 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

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

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, ~~2009~~ 2010 and ~~2008~~2009.

	2009			2008
	2010			2009
	(in thousands)
Balance, beginning of year	$	1,~~651~~910		$	~~476~~1,651
Liabilities incurred		~~285~~-			~~770~~285
Liabilities settled		-(204	)		~~(35~~-	)
Accretion expense		2019			1620
Revision to prior estimate		~~(46~~-	)		~~424~~(46	)
Balance, end of year	$	1,~~910~~725		$	1,~~651~~910

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 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.

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Impairment of Long-Lived Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or ~~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 $7.7 million, primarily the result of three of the Fund’s wells being fully depleted, lower oil and gas commodity prices and increased project costs. During the year ended December 31, 2008, the Fund recorded impairments to proved properties totaling $7.7 million, primarily the result of one well being fully depleted and lower oil and gas commodity prices, partially offset by a credit received a $0.5 million related to a previously impaired well. 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.

During the year ended December 31, 2010, the Fund recorded impairments of oil and gas properties totaling $1.2 million, which were attributable to revisions in reserve estimates related to South Marsh Island 111 and the Whistler Project and adjustments to asset retirement obligations for fully depleted wells. During the year ended December 31, 2009, the Fund recorded impairments of oil and gas properties totaling $7.7 million, which were primarily attributable to revisions to reserve estimates, including revisions resulting from 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.

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.

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. The Fund had dry hole costs of $0.1 million during the year ended December 31, 2010 and credits to dry-hole costs of $0.1 million during the year ended December 31, 2009.

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Table of Contents

In April 2009, the FASB issued guidance on interim disclosures about fair value of financial instruments, which requires quarterly disclosure of information about the fair value of financial instruments. The guidance was adopted effective for the second quarter 2009 and did not have a material impact on the Fund’s financial statements.

In April 2009, the FASB issued guidance on the recognition and presentation of other-than-temporary impairments, which amends the other-than-temporary impairment guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This guidance does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. This guidance does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after initial adoption, this guidance requires comparative disclosures only for periods ending after initial adoption. The guidance was adopted effective for the second quarter 2009 and did not have a material impact on the Fund’s financial statements.

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	$	1,882		$	7,357
Additions to capitalized exploratory well costs pending the determination of proved reserves		546			6,940
Reclassification to proved properties based on the determination of proved reserves		(2,428	)		(12,415	)
Capitalized exploratory well costs charged to dry-hole costs		-			-
Balance, end of year	$	-		$	1,882

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. Dry-hole costs, inclusive of such credits, for the years ended December 31, 2009 and 2008 are detailed in the following table.

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Table of Contents

	Year ended December 31,
Lease Block	2009			2008
South Marsh Island 213	$	(43	)	$	1,688
Other wells		(56	)		12
	$	(99	)	$	1,700

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. ~~Effective~~ In July 1, 2009, the Manager elected to ~~permanently~~ waive its right to distributions of available cash from operations for the remaining life of the Fund.

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

6. Related Parties

~~Effective October~~In 1,accordance ~~2007,~~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 2007, 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.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund. In July 2009, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. Distributions paid to the Manager for the year ended December 31, 2009 were $0.1 million.

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 approximate fair value.

8. Commitments and Contingencies

Capital Commitments

~~The~~At ~~Fund has~~December ~~entered~~31, ~~into~~2010, ~~multiple agreements for~~ the ~~drilling~~Fund ~~and~~had ~~development~~commitments ofrelated to its investment properties totaling $0.4 ~~The~~million. Based ~~estimated~~upon ~~capital~~its ~~expenditures~~current ~~associated~~reserve ~~with~~estimates, the Fund expects cash flow from operations to be sufficient to cover these ~~agreements~~ ~~vary~~commitments, ~~depending~~as onwell ~~the~~as ~~stage~~ongoing ofoperations. Reserve ~~development~~estimates are projections based on aengineering ~~property-by-property basis.~~data ~~The~~that ~~Fund~~cannot ~~has~~be ~~reached~~measured ~~the~~with ~~end~~precision, ofrequire ~~its~~substantial ~~investment~~judgment, ~~cycle~~and are subject to frequent revision. ~~At December~~In ~~31,~~the ~~2009~~event of a temporary production stoppage, causing the Fund’s ~~has~~wells ~~capital~~to ~~commitments~~not ofproduce ~~$1.4~~cash ~~million~~flow ~~that~~from ~~exceed~~operations, by ~~$1.0~~the ~~million,~~Fund ~~its~~may ~~current~~borrow ~~available~~from ~~working~~the ~~capital~~Manager ofuntil $0such time that production is resumed.~~4 million.~~ ~~Based~~At ~~upon~~such ~~its~~time ~~current~~the ~~reserve~~Manager ~~estimates,~~determines that the Fund ~~expects cash~~is ~~flow~~no ~~from~~longer ~~operations~~capable of continuing to befund ~~sufficient~~its operations, the Manager would elect to ~~cover~~dissolve ~~these deficiencies~~the Fund.

Environmental Considerations

The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At December 31, ~~2009~~2010 and ~~2008~~2009, there were no known environmental contingencies that required the Fund to record a liability.

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Table of Contents

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.

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~~On March 1, 2011, the Fund ~~has~~ ~~assessed~~was notified by the ~~impact~~operator of ~~subsequent~~the ~~events~~Whistler ~~through~~ Project that the ~~date~~well ofhad ~~issuance~~ reached the end of its ~~financial~~ ~~statements~~economic life, and ~~has~~that ~~concluded~~the ~~that~~production ~~there~~handling ~~were~~agreement noentered ~~such events~~into ~~that~~for ~~require~~the ~~adjustment~~Whistler toProject, orhad ~~disclosure~~been interminated. As a result, for the ~~notes~~year toended December 31, 2010, the ~~financial statements~~Fund recorded an impairment of oil and gas properties related to a revision to reserve estimates. See Note 2. “Summary of Significant Accounting Policies - Impairment of Long-Lived Assets,” for additional information regarding impairments.

~~F-12~~Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in West Cameron 57 to Marlin Coastal, L.L.C. (“Marlin”), the operator of the well, in exchange for Marlin’s assumption of all future obligations and liabilities of the well. As a result, during the first quarter 2011, the Fund has relieved the asset retirement obligation of $0.2 million that it had previously established for the well.

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Ridgewood Energy M Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities - Unaudited

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

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
	December 31,
	2009			2008
	2010			2009
	(in thousands)
Unproved properties	$	-		$	1,882
Advances to operators for working interests and expenditures	$	156		$	-
Proved properties		910,~~982~~430			209,~~346~~982
Total oil and gas properties		910,~~982~~586			229,~~228~~982
Accumulated depletion and amortization		(36,~~503~~983	)		(73,~~537~~503	)
Oil and gas properties, net	$	63,~~479~~603		$	146,~~691~~479
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
	Year ended December 31,
		2010			2009
	(in thousands)
Exploration costs	$	164		$	1,682
Development costs		528			196
	$	692		$	1,878

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
	Year ended December 31,
		2009		2008
	(in thousands)
Exploration costs	$	1,682	$	8,097
Development costs		196		2,713
	$	1,878	$	10,810

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Table of Contents

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, 2010 and 2009. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

	December 31, 2010						December 31, 2009
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)

Proved developed and undeveloped reserves:
Beginning of year		49,139			1,406,986			61,910			1,401,583
Extensions and discoveries		-			-			3,516			837,000
Revisions of previous estimates (a)		(1,616	)		(238,429	)		(10,293	)		(393,128	)
Production		(3,319	)		(561,197	)		(5,994	)		(438,469	)
End of year		44,204			607,360			49,139			1,406,986

Proved developed reserves:
Beginning of year		48,205			664,653			61,910			845,583
End of year		44,204			607,360			48,205			664,653

Proved undeveloped reserves:
Beginning of year		934			742,333			-			556,000
End of year		-			-			934			742,333

(a) Revisions of previous estimates during 2010 were primarily attributable to well performance. Revisions of previous estimated during 2009 were primarily attributable to well performance coupled with revisions attributable to fully depleted wells.

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Table ~~III~~IV - ~~Reserve~~Standardized ~~Quantity~~Measure ~~Information Oil and gas reserves~~ of ~~the~~Discounted ~~Fund~~Future ~~have~~Net ~~been~~Cash ~~estimated~~Flows byRelating anto ~~independent~~Proved ~~petroleum~~Oil ~~engineer, Ryder Scott Company, L.P. ("Ryder Scott") at December 31, 2009~~ and ~~2008.~~Gas AtReserves ~~December~~Summarized ~~31,~~in ~~2008,~~ the ~~Fund~~following ~~had~~table ~~one~~is ~~non-producing~~information ~~property~~ for ~~which reserve data is based upon internal estimates. 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~~with ~~reserve~~respect ~~data~~to ~~disclosed in~~ the ~~following~~standardized ~~tables~~measure ~~represent the Fund's share~~ of ~~such~~discounted ~~reserves~~future ~~based on the Fund's~~ net ~~revenue~~cash ~~interest~~flows inrelating ~~each property. Due~~ to ~~inherent~~proved ~~uncertainties~~oil and ~~the~~gas ~~limited~~reserves. ~~nature~~At ofDecember ~~recovery data~~31, ~~estimates~~2010 ofand ~~reserve~~2009, ~~information~~future ~~are~~cash ~~subject~~inflows towere ~~change~~determined asbased ~~additional~~on ~~information~~average ~~becomes~~first-of-the-month ~~available.~~pricing ~~Ryder~~for ~~Scott's~~the ~~report~~prior ~~included~~twelve-month ~~remaining reserves and projected income associated with Eugene Island 337~~period. ~~Subsequent~~Future ~~to their study,~~ production atand ~~Eugene~~development ~~Island~~costs ~~337~~are ~~ceased~~derived ~~with~~based noon current ~~plans~~costs toassuming ~~restore.~~continuation ~~Accordingly,~~of ~~Eugene~~existing ~~Island~~economic ~~337 reserves have been excluded from this filing~~conditions.

	December 31, 2009						December 31, 2008
	December 31,
	United States
	2010			2009
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)
	(in thousands)
Proved developed and undeveloped reserves:
Future cash inflows	$	6,222		$	8,534
Beginning of year		61,910			1,401,583			36,699			2,718,400
Future production costs		(930	)		(1,352	)
Extensions and discoveries		3,516			837,000			66,053			1,392,012
Future development costs		(2,174	)		(1,251	)
Revisions of previous estimates (a)		(10,293	)		(393,128	)		(36,443	)		(2,597,673	)
Future net cash flows		3,118			5,931
Production		(5,994	)		(438,469	)		(4,399	)		(111,156	)
10% annual discount for estimated timing of cash flows		(469	)		(1,090	)
End of year		49,139			1,406,986			61,910			1,401,583
Standardized measure of discounted future net cash flows	$	2,649		$	4,841
Proved developed reserves:
Beginning of year		61,910			845,583			26,848			1,960,400
End of year		48,205			664,653			61,910			845,583
Proved undeveloped reserves:
Beginning of year		-			556,000			9,851			758,000
End of year		934			742,333			-			556,000

(a) Revisions of previous estimates are primarily attributable to the year-end determination that three of the Fund's wells were fully depleted at December 31, 2009 and one of the Fund's wells at December 31, 2008, coupled with revisions due to well performance.

Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. At December 31, 2009, future cash inflows were determined based on average 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
	(in thousands)
Future cash inflows	$	8,534		$	10,825
Future production costs		(1,352	)		(1,038	)
Future development costs		(1,251	)		(1,985	)
Future net cash flows		5,931			7,802
10% annual discount for estimated timing of cash flows		(1,090	)		(1,063	)
Standardized measure of discounted future estimated net cash flows	$	4,841		$	6,739

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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	$	(1,~~503~~241	)	$	3(1,~~200~~503	)
Sales and transfer of oil and gas produced during the period		(1,597	)		(1,214	)
Sales and transfers of oil and gas produced during the period		(2,306	)		(1,597	)
Net change due to extensions, discoveries, and improved recovery		~~1,798~~-			71,~~113~~798
Changes in estimated future development costs		~~1,618~~(923	)		-1,618
Net change due to revisions in quantity estimates		(2,398	)		(18,571	)
Net change due to revisions in quantities estimates		(1,063	)		(2,398	)
Accretion of discount		~~674~~484			~~1,555~~674
Other		~~(490~~375	)		(~~893~~490	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(12,~~898~~192	)	$	(81,~~810~~898	)

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 M FUND, LLC
Date: March 16, 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	March 16, 2010
Robert E. Swanson	Executive Officer)
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer	March 16, 2010
Kathleen P. McSherry	(Principal Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
BY: /s/ ROBERT E. SWANSON	Chief Executive Officer of Manager	March 16, 2010
Robert E. Swanson

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