10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2006

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

  For the transition period from _____ to _____

Commission File No. 000-51268

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.)

1314 King Street, Wilmington, Delaware 19801

(Address of principal executive offices) (Zip code)

(302) 888-7444

(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 ý

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 ý

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 ý No o

Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained herein, 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. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer ý

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

There is no market for the Shares. The aggregate capital contributions made for the Registrant's voting Shares held by non-affiliates of the Registrant at April 10, 2007 was approximately $78.9 million and as of that date there are 535.6818 Shares outstanding.

2006 Annual Report on Form 10-K
Table of Contents
Part I			Page
	Item 1	Business	7
	Item 1A	Risk Factors	19
	Item 1B	Unresolved Staff Comments	28
	Item 2	Properties	29
	Item 3	Legal Proceedings	30
	Item 4	Submission of Matters to a Vote of Security Holders	30
Part II
	Item 5	Market for Registrant's Common Equity, Related Security Holder Matters, and Issuer Purchases of Equity Securities	31
	Item 6	Selected Financial Data	34
	Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
	Item 7A	Quantitative and Qualitative Disclosures about Market Risk	44
	Item 8	Financial Statements and Supplementary Data	44
	Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
	Item 9A	Controls and Procedures	45
	Item 9B	Other Information	46
Part III
	Item 10	Directors, Executive Officers and Corporate Governance	47
	Item 11	Executive Compensation	48
	Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Security Holder Matters	49
	Item 13	Certain Relationships and Related Transactions and Director Independence	50
	Item 14	Principal Accountant Fees and Services	51
Part IV
	Item 15	Exhibits and Financial Statement Schedules	52
		Signatures	53
		Exhibit Index

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents the Fund has incorporated by reference into this Annual Report, includes “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995, and the “safe harbor” provisions thereof. These forward-looking statements are usually accompanied by the words “anticipates,” “believes,” “plan,” “seek,” “expects,” “intends,” “estimates,” “projects,” “will,” “would,” “will likely result,” “will continue,” “future” and similar terms and expressions. The forward-looking statements in this Form 10-K reflect the current views of the management of Ridgewood Energy M Fund, LLC (the “Fund”) with respect to future events and financial performance. These forward-looking statements are subject to certain risks and uncertainties, including, among other things, the high-risk nature of oil and natural gas exploratory operations, the fact that the Fund’s drilling activities are managed by third parties, the volatility of oil and natural gas prices and extraction, and those other risks and uncertainties discussed in this report and in the Fund’s registration statement on Form 10, as amended, filed with the United States Securities and Exchange Commission (the “SEC”), that could cause actual results to differ materially from historical results or those anticipated. A detailed discussion of these and other risks and uncertainties that could cause actual results and events to differ materially from such forward-looking statements is included in Item 1A. “Risk Factors” beginning on page 21 of this Annual Report. You are urged to carefully consider all such factors.

In light of these risks and uncertainties, there can be no assurance that the forward-looking information contained in this Annual Report will in fact occur or prove to be accurate. Readers should not place undue reliance on the forward-looking statements contained herein, which speak only as of today’s date. We undertake no obligation to publicly revise these forward-looking statements to reflect events or circumstances that may arise after today. All subsequent written or oral forward-looking statements attributable to the Fund or persons acting on the Fund’s behalf are expressly qualified in their entirety by this section.

AVAILABLE INFORMATION

The Fund’s registered shares are under Section 12(g) of the Exchange Act. The Fund must therefore comply with, among other things, the periodic reporting requirements of Section 13(a) of the Exchange Act. As a result, the Fund prepares and files annual reports with the SEC on Form 10-K, quarterly reports on Form 10-Q and, from time to time, current reports on Form 8-K. Moreover, the Manager maintains a website at http://www.ridgewoodenergy.com that contains important information about the Manager, including biographies of key management personnel, as well as information about the oil and natural gas investments made by the Fund and the other investment programs managed by the Manager. Such information includes, without limitation, a map of the Gulf of Mexico that provides the location of every well and project managed by the Manager along with information as to whether the project is exploratory, in completion or producing. This information is publicly available (i.e., not password protected) and is updated regularly.

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REPORTS TO SHAREHOLDERS

The Fund does not anticipate providing annual reports to shareholders but will make available upon request copies of the Fund's periodic reports to the SEC on Form 10-K and on Form 10-Q.

WHERE YOU CAN GET MORE INFORMATION

The Fund files annual, quarterly and current reports and certain other information with the SEC. Persons may read and copy any documents the Fund files at the SEC’s public reference room at 100 F Street, NE, Washington D.C. 20549. You may obtain information on the operation at 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. A copy of any such filings will be provided free of charge to any shareholder upon written request to the Fund at its business address 947 Linwood Avenue, Ridgewood, New Jersey 07450, ATTN: General Counsel.

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Commonly Used Oil and Gas Terms

Below are explanations of some commonly used terms in the oil and gas business.

AFE. Authorization for expenditures.

Barrel (Bbl.) A standard measure of volume for crude oil and liquid petroleum products. One barrel equals 42 U.S. gallons liquid volume, used herein in reference to crude oil or condensate.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf gas to one Bbl of crude oil or condensate.

Btu. British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas from a recently drilled well.

Deep shelf. Structures located on the Outer Continental Shelf at depths generally greater than 14,000 feet in over pressured horizons where there has been limited or no production from deeper stratigraphic zones.

Deepwater. Generally considered to be water depths in excess of 1,000 feet.

Development well. A well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive, including a well drilled to find and produce probable reserves.

Dry-hole. A well found to be incapable of producing hydrocarbons in sufficient or commercial quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploration or exploratory well. A well drilled to find and produce oil or natural gas reserves in an unproved area.

FERC. The Federal Energy Regulatory Commission.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. The standard measure of volume for natural gas, one thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

MMS. The Minerals Management Service of the United States Department of the Interior.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBTU. Million British Thermal Units.

MMcf. One million cubic feet.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

Non-Consent. The option to elect not to participate in a well or project.

NYMEX. The New York Mercantile Exchange.

OCS. The U.S. Outer Continental Shelf of the Gulf of Mexico. Water depths generally range from 50 feet to 1,000 feet.

Overriding Interest. The seller of ownership interest may retain a right for some period of time to payments from the sale of oil and natural gas production from a well or project.

Probable reserves. Reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery.

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Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Promote. The payment of a larger portion of the costs than ownership interest would require.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved reserves. The estimated quantities of crude oil or 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.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

SEC. United States Securities and Exchange Commission.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

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PART I

ITEM 1. BUSINESS

General Overview

Ridgewood Energy M Fund, LLC (the “Fund”) is a Delaware limited liability company and was formed on August 2, 2004 to acquire interests primarily in oil and natural gas projects located in the U.S. waters of the Gulf of Mexico. Ridgewood Energy Corporation ("Ridgewood Energy" or the “Manager”), a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management and control of Fund operations. The Fund is engaged in the acquisition, development and production of oil and natural gas projects in the Gulf of Mexico. To date, the Fund has focused primarily on acquiring oil and natural gas projects in the shallow waters of the Gulf of Mexico in locations with access to existing gathering and processing infrastructure or where such infrastructure can be constructed economically and efficiently.

The Fund initiated its private placement offering on September 7, 2004, selling whole and fractional shares of membership interests primarily at $150 thousand per share. There is no public market for these shares and one is not likely to develop. In addition, the shares are subject to severe restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund's limited liability company operating agreement (“LLC agreement”) and applicable federal and state securities laws. The offering was terminated on November 4, 2004. The Fund raised $78.9 million. After payment of $12.2 million in offering fees, commissions and investment fees, the Fund had $66.7 million for investments and operating expenses. As of April 10, 2007 the Fund had 946 shareholders.

Manager

Ridgewood Energy was founded in 1982 by Robert E. Swanson. As the Manager, Ridgewood Energy has direct and exclusive control over the management of the Fund's operations. With respect to project investment, Ridgewood Energy locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made. This includes not only review of existing title documents, reserve information, and other technical specifications regarding a project, but also the review and preparation of participation agreements and other agreements relating to an investment.

In addition, Ridgewood Energy performs (or arranges for the performance of) the management and administrative services required for Fund operations. Among other services, Ridgewood Energy administers the accounts and handles relations with the shareholders, including tax and other financial information. In addition, Ridgewood Energy provides the Fund with office space, equipment and facilities and other services necessary for its operation. Finally, Ridgewood Energy manages and conducts the Fund's relations with custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others, as required.

The Fund is required to pay all other expenses it incurs, including expenses of preparing and printing periodic reports for shareholders and the United States Securities and Exchange Commission (the “SEC”), commission fees, taxes, outside legal, accounting and consulting fees, litigation expenses and other expenses, if any, properly payable by the Fund. The Fund is required to reimburse the Manager for all such Fund expenses paid by it.

As compensation for its management services, the Manager is entitled to (i) an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by our shareholders and (ii) a 15% interest in the cash distributions made to the Fund’s shareholders. In January 2007, the Manager changed its policy regarding the 2.5% annual management fee. Effective January 1, 2007, the annual management fee, payable monthly, will be equal to 2.5% of total shareholder capital contributions, net of cumulative dry-hole expenses incurred by the Fund. As set forth in Item 7. Management's Discussion and Analysis, the Manager received from the Fund for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004 approximately $1.9 million, $2.0 million and $0.5 million, respectively, for its management services. Additionally, for the years ended December 31, 2006 and 2005, and for the period August 2, 2004 (Inception) through December 31, 2004, the Manager received approximately $0.8 million, nil and nil, respectively, representative of the 15% interest of cash distributions.

Business Strategy

The Fund’s primary investment objective is to generate cash flow from the acquisition, exploration, production and sale of crude oil and natural gas from oil and natural gas projects. The Fund has invested and participates in exploration and production projects located in the waters of the Gulf of Mexico offshore Texas, Louisiana and Alabama 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 Minerals Management Service of the Department of the Interior (“MMS”). The Fund generally looks to invest in projects 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 a project. These investments may require the Fund to pay a disproportionate part of the drilling costs on the exploratory well of a project than its ownership interest would otherwise require. This is called a promote and 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 relatively common in this industry. Notwithstanding any such promote or overriding interest, the Fund has tried to invest in projects that it believes contain sufficient commercial quantities of oil or natural gas and which are near (i) existing oil or natural gas gathering and processing infrastructure and (ii) developed markets where the Fund can sell its oil or natural gas.

The Fund tries to focus on projects that have significant reserve potential and which are projected to have the shortest time period from investment to first production. However, 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. Moreover, when performing due diligence with respect to a project, the Fund must rely on the independent reservoir engineers who are hired and paid, in most cases, by the operator. The Fund does engage certain consultants to examine and review such reserve estimates and seismic information on its behalf.

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Manager’s Investment Committee and Investment Criteria

The New Jersey office has four executives on the investment committee, three of whom have been working together at Ridgewood Energy for 20 years. The Houston office, which opened in 2003, has five executives on the investment committee who provide operational, scientific and technical oil and natural gas expertise.

In considering projects, the Manager and investment committee investigates each such project against a list of factors that it believes will result in the selection of those projects that have the highest probability of success. These factors, in no particular order, include, but are not limited to, the following (i) targeting projects that have or are expected to have operators with significant resources and experience in oil and natural gas exploration; (ii) targeting projects that have or are expected to have partners that also have significant resources and experience in oil and natural gas exploration; (iii) technical quality of the project including its geology, seismic profile, locational trends, and whether the project has potential for multiple prospects; (iv) oil or natural gas reserve potential; (v) whether and the extent to which the operator participates as a working interest owner in the project; (vi) economic factors, such as potential revenues from the project, the rate of return, and estimated time to first production; (vii) risk factors associated with exploration, as more fully described in this filing; (viii) existence of drilling rigs, platforms and other infrastructure, at or nearby the project; (ix) proposed drilling schedule; (x) terms of the proposed transaction, including contractual restrictions and obligations and lease term; and (xi) overall cost of the project.

Working Interest in Oil and Natural Gas Leases

Existing projects, and future projects, if any, are expected to be, located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The OCSLA, which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS.

Under OCSLA, the United States federal government has jurisdiction over oil and natural gas exploration and 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, an agency of the United States Department of Interior. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the length of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.

The winning bidder(s) at the lease sale, or the lessee(s), are given a lease by the MMS that grants such lessee(s) the exclusive right to conduct oil and natural gas exploration and production activities within a specific lease block, or working interest. 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 to 800 meters and 10 years for depths in excess of 800 meters. During this primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

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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.

Generally, working interests in an offshore gas lease under the OCSLA pay a 16.67% royalty to the MMS. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is approximately 83.33% of the total revenue of the project, and, is further reduced by any other royalty burdens that apply to a lease block. However, as described below, the MMS has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects.

Mineral Management Services Deep Natural 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 $9.91 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.

Oil and Natural Gas Agreements

We have entered into a short-term month to month agreement with Energy Upgrade Inc. who is currently marketing and selling the Fund's proportionate share of the gas to the public market. The Fund is receiving market prices for such natural gas. The Manager believes however, that it is likely that oil and natural gas from  the Fund's other projects, will also have access to pipeline transportation and can be marketed in a similar fashion. As mentioned above in Manager’s Investment Committee and Investment Criteria, as part of the Manger’s review of a potential project, access to existing transportation infrastructure is an extremely important factor as the existence of such infrastructure enables production from a successful well to get to market quickly.

Operator

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operator is responsible for drilling, administration and production activities for leases jointly owned by working interest owners and acts on behalf of all working interest owners under the terms of the applicable offshore operating agreements. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's projects are operated by BHP Billiton (“BHP”), Devon Energy (“Devon”), El Paso (“El Paso”), ENI Petroleum (currently known as Woodside Energy) (“Woodside”), LLOG Exploration Company (“LLOG”), and Newfield Exploration (“Newfield”).

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Because the Fund does not operate any of the projects in which it has acquired an interest, shareholders must 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 hazard, property, general liability and other insurance in commercially reasonable amounts to cover the projects, as well as general 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. 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. These projects are owned by affiliates of the Fund. 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 become exhausted and be insufficient to cover a claim made by the Fund in that year.

Salvage Fund

As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or a salvage fund, which is in the nature of a sinking fund, money to help provide for the Fund’s proportionate share of the cost of dismantling production platforms and facilities, plugging and abandoning the projects, and removing the platforms, facilities and projects in respect of each of such projects after their useful life, in accordance with applicable federal and state laws and regulations. There is no assurance that the salvage fund will have sufficient assets to meet these requirements and any unfunded expenses, and the Fund may be liable for such expenses. The Fund has deposited approximately $1.0 million from capital contributions into a salvage fund which the Fund estimates to be sufficient to meet its potential requirements. If management later determines the deposit and earned interest is not enough to cover the Fund’s proportionate share of expense, the Fund will deposit payments from operating income to make up any differences. 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 of the salvage fund.

Seasonality

Generally, the Fund's business operations are not subject to seasonal fluctuations in the demand for oil and natural gasthat 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 drilled and reserves of oil and natural gas are determined to exist, the operator of the project extracts such reserves throughout the year. Oil and natural gas, once extracted, can be sold at any time during the year.

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However, the Fund's drilling, production and transportation operations are subject to seasonal risks, such as hurricanes, that may affect our ability to bring such oil or natural gas to the market and, consequently, affect the price for such oil and natural gas. The National Hurricane Center defines hurricane season in the Atlantic Region, Caribbean, and Gulf of Mexico to be from June 1 through November 30. During hurricane season, the number and intensity of and resulting damage from hurricanes in the Gulf of Mexico region could affect the gathering and processing infrastructure, drilling platforms or the availability or price of repair or replacement equipment. As a result, these factors may affect the supply and, consequently, the price of oil and natural gas resulting in an increase in price if supplies are reduced. However, even if commodity prices increase because of weather related shortages, the Fund may not be in a position to take immediate advantage of any such price increase if, as a result of such weather related incident, damage occurred to its projects, the gathering infrastructure or in the transportation network.

The Manager has experienced the range of possible interruptions in operations due to hurricanes from as little as no damage and insignificant or no interruptions to significant damage and extended interruptions. However, it is of course impossible to predict whether and to what extent hurricanes and damage may occur and to what projects.

Customers

All of the oil and natural gas production from the Fund’s producing properties is sold by a third party on the Fund’s behalf. As a result, the Fund did not contract to sell oil and natural gas to third parties. Therefore, the Fund had no customers or any one customer upon which the Fund depends for more than ten percent (10%) of its revenues.

Energy Prices

Historically, the markets for crude 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 which the Fund cannot control or influence. Therefore, it is impossible to predict the future price of crude oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability. Also, the Fund has not engaged in any price risk management programs or hedges to date and does not anticipate engaging in those types of transactions in the future.

Competition

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

In many instances, the Fund competes for projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position that they could outbid the Fund for a project. However, because these companies are so large and have such significant resources, they tend to focus more on projects that are larger, have greater reserve potential, but cost significantly more to explore and develop. These larger projects increasingly tend to be projects in the deepwater areas of the Gulf of Mexico

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and the North Sea off the coast of Great Britain. However, the focus of these companies on larger projects does not necessarily mean that they will not investigate and/or acquire smaller projects in shallow waters for which the Fund competes. Many of these larger companies have participated in the auctions for lease blocks directly from the U.S. Government. In such cases, these companies obtain from the U.S. Government 100% of the leasehold of a particular lease block in the Gulf of Mexico. In order to obtain even more resources to invest in other larger and more expensive projects, they diversify current holdings, including projects they own in the shallow waters of the Gulf of Mexico, by selling off percentage interests in these lease blocks. As a result, very good projects in the shallow waters of the Gulf of Mexico become available. The Fund, therefore, has opportunities to acquire interests in these smaller, yet economically attractive projects.

Employees

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

Offices

The Manager’s principal executive offices are located at 947 Linwood Avenue, Ridgewood, NJ 07450, and its phone number is 800-942-5550. The Manager also leases additional office space at 11700 Old Katy Road, Houston, TX 77079.

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, our 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.

Outer Continental Shelf Lands Act

The Fund’s projects are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities, therefore, are governed by, among other things, the OCSLA.

Under 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, an agency of the United States Department of Interior. The MMS administers federal offshore leases pursuant to regulations promulgated under the OCSLA. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition,

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approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. 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 regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

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

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

Sales and Transportation of Natural Gas/Oil

The Fund expects to sell its proportionate share of oil and natural gas to the market and to receive 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 the Fund 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 OSCLA, the Natural Gas Policy Act and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge us, although regulated, are beyond our control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, the impact to the Fund of any changes in such rates, terms or conditions would not impact its operations differently in any material way 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 the Fund 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 is caused by our projects.

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

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The Oil Pollution Act. The Oil Pollution Act (“OPA”) amends Section 311 of the Federal Water Pollution Act (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to and increases penalties for 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 which 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 as the operator is responsible for such compliance. However, notwithstanding the operator's responsibility for compliance, in the event of an oil spill, the Fund, along with the operator and other working interest owners, could be liable under the OPA for the resulting environmental damage.

Federal Water Pollution Act/Clean Water Act. Generally, the Federal Water Pollution Act/Clean Water Act imposes liability for the unauthorized discharge of 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. Again, 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 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, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation and Liability Act which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment.

The above represents a brief outline of the major environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated there under.

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Potential Tax Benefits

The following discussion is a summary of the primary tax benefits of ownership of a membership interest in the Fund and does not include all possible tax benefits or other tax implications of such ownership.

Deduction of Intangible Drilling and Development Costs

Section 263(c) of the Internal Revenue Code of 1986, as amended (the “Code”) authorizes an election by the Fund to deduct as expenses intangible drilling and development costs incurred in connection with oil and natural gas properties at the time such costs are incurred in accordance with the Fund's method of accounting, provided that the costs are not more than would be incurred in an arm's length transaction with an unrelated drilling contractor. Such costs include, for example, amounts paid for labor, fuel, wages, repairs, supplies and hauling necessary to the drilling of the project and preparation of the project for production. Generally, this election applies to items that in themselves do not have salvage value. Alternatively, each Fund shareholder may elect to capitalize their share of the intangible drilling and development costs and amortize them ratably over a 60-month period.

The Fund may enter into carried interest arrangements whereby the Fund would purchase interests in certain leases and agree to pay a disproportionate part of the costs of drilling the first project thereon. In such situations, the party who is paying more than their share of costs of drilling may not deduct all such costs as intangible drilling and development costs unless their percentage of ownership of the lease is not reduced before they have recovered from the first production of the project an amount equal to the cost they incurred in drilling, completing, equipping and operating the project. The Fund may not have this right in certain of the transactions of this type in which it may engage. If circumstances permit, however, the Fund will adopt the position that all of the intangible drilling and development costs incurred are deductible (even though such costs may be disproportionate to its ownership of the lease) on the basis that such arrangements constitute partnerships for federal income tax purposes and that the excess intangible drilling and development costs are specifically allocable to the Fund. There can be no assurance that this position would prevail against challenge by the Internal Revenue Service (the “IRS”).

In the case of a shareholder who constitutes an integrated oil company, 30% of the amount otherwise allowable as a deduction for intangible drilling costs under Section 263(c) must be capitalized and deducted ratably over a 60-month period beginning with the month the costs are paid or incurred. This provision does not apply to nonproductive projects. For this purpose, an integrated oil company is generally defined as an individual or entity with retail sales of oil and natural gas aggregating more than $5 million and refining more than 50,000 barrels per day for the taxable year.

To the extent that drilling and development services were performed for the Fund in 2006, amounts incurred pursuant to bona fide arm's-length drilling contracts and constituting intangible drilling and development costs were deductible by the Fund in 2006. To the extent that such services are performed in 2007, however, the Fund will only be allowed to deduct for the year 2007 amounts that are:

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·   incurred pursuant to bona fide arm's-length drilling contracts which provide for absolute noncontingent liability for payment, and

·   attributable to wells spud within 90 days after December 31, 2006.

Sections 461(h)(1) and 461(i)(2) of the Code provide, in relevant part:

...in determining whether an amount has been incurred with respect to any item during any taxable year, the all events tests shall not be treated as met any earlier than when economic performance with respect to such item occurs.

* * *

...economic performance with respect to the act of drilling an oil or natural gas well shall be treated as having occurred within a taxable year if drilling of the well commences before the close of the 90th day after the close of a taxable year.

The clear implication of these provisions is that an amount incurred during a taxable year for drilling or completion services which could otherwise be accrued for federal tax purposes will not be disqualified as a deduction merely because the services are performed during the subsequent taxable year (provided that the services commence within the first 90 days of such subsequent year).

Consequently, intangible drilling and development costs meeting the above criteria were deducted by the Fund in 2006 even though a portion of such costs are attributable to services performed during 2007.

Each shareholder, however, may deduct their share of amounts paid in 2006 for services performed in 2007 only to the extent of their cash basis in the Fund as of the end of 2006. For this purpose, a taxpayer's cash basis in a tax shelter which is taxable as a partnership (such as the Fund) is the taxpayer's basis in the Fund determined without regard to any amount borrowed by the taxpayer with respect to the Fund which (a) is arranged by the Fund or by any person who participated in the organization, sale or management of the Fund (or any person related to such person within the meaning of Section 461(b)(3)(c)) of the Code, or (b) is secured by any asset of the Fund. Inasmuch as cash basis excludes borrowing arranged by an extremely broad group of persons who could be related to a person who participated in the organization, sale or management of the Fund, it is not possible to express an opinion as to whether each shareholder of the Fund will be allowed to deduct their allocable share of any prepaid drilling expenses to the extent that they exceed their actual cash investment in the Fund.

Depletion Deductions

Subject to the limitations discussed hereafter, the shareholders will be entitled to deduct, as allowances for depletion under Section 611 of the Code, their share of percentage or cost depletion, whichever is greater, for each oil and natural gas producing project owned by the Fund.

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Cost depletion is computed by dividing the basis of the project by the estimated recoverable reserves to obtain a unit cost, then multiplying the unit cost by the number of units sold in the current year. Cost depletion cannot exceed the adjusted basis of the project to which it relates. Thus, cost depletion deductions are limited to the capitalized cost of the project, while percentage depletion may be taken as long as the project is producing income. The depletion allowance for oil and natural gas production will be computed separately by each shareholder and not by the Fund. The Fund will allocate to each shareholder their proportionate share of production and the adjusted basis of each Fund project. Each shareholder must keep records of their share of the adjusted basis and any depletion taken on the project and use their adjusted basis in the computation of gain or loss on the disposition of the project by the Fund.

Percentage depletion with respect to production of oil and natural gas is available only to those qualifying for the independent producer's exemption, and is limited to an average of 1,000 barrels per day of domestic oil production or 6,000,000 cubic feet per day of domestic natural gas production. The applicable rate of percentage depletion on production under the independent producer exemption is 15% of gross income from oil and natural gas sales. The depletion deduction under the independent producer exemption may not exceed 65% of the taxpayer's taxable income for the year, computed without regard to certain deductions. Any percentage depletion not allowed as a deduction due to the 65% of adjusted taxable income limitation may be carried over to subsequent years subject to the same annual limitation. For a shareholder that is a trust, the 65% limitation shall be computed without deduction for distributions to beneficiaries during the taxable year.

The determination of whether a shareholder will qualify for the independent producer exemption will be made at the shareholder level. A shareholder who qualifies for the exemption, but whose average daily production exceeds the maximum number of barrels on which percentage depletion can be computed for that year, will have to allocate their exemption proportionately among all of the properties in which they have an interest, including those owned by the Fund. In the event percentage depletion is not available, the shareholder would be entitled to utilize cost depletion as discussed above.

The independent producer exemption is not available to a taxpayer who refines more than 50,000 barrels of oil on any one day in a taxable year or who directly or through a related person sells oil or natural gas or any product derived therefrom (i) through a retail outlet operated by them or a related person or (ii) to any person who occupies a retail outlet which is owned and controlled by the taxpayer or a related person. In general, a related person is defined by Section 613A of the Code as a corporation, partnership, estate, or trust in which the taxpayer has a 5% or greater interest. For the purpose of applying this provision: (a) bulk sales of oil or oil and natural gas to commercial or industrial users are excluded from the definition of retail sales; (b) if the taxpayer or a related person does not export any domestic oil or natural gas production during the taxable year or the immediately preceding year, retail sales outside the U.S. are not deemed to be disqualifying sales; and (c) if the taxpayer's combined receipts from disqualifying sales do not exceed $5 million for the taxable year of all retail outlets taken into account for the purpose of applying this restriction, such taxpayer will not be deemed a retailer.

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Depreciation

Costs of equipment, such as casing, tubing, tanks, pumping units, pipelines, production platforms and other types of tangible property and equipment generally cannot be deducted currently, but may be eligible for accelerated cost recovery. All or part of the depreciation claimed may be subsequently recaptured upon disposition of the property by the Fund or of a share by any shareholder.

In addition, the Code provides for certain uniform capitalization rules which could result in the capitalization rather than deduction of Fund management fee and administration costs.

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ITEM 1A. RISK FACTORS

In addition to the other information set forth elsewhere in this report, you should carefully consider the following factors when evaluating the Fund:

RISKS INHERENT IN THE FUND’S BUSINESS

The Fund’s exploration and production activities are subject to risks that it cannot control and it may have insufficient insurance to cover these risks. To the extent the Fund is not covered by insurance, it could incur losses and liabilities that could reduce revenues, increase costs or eliminate dollars available for future exploration and development projects.

Costs of drilling, completing and operating projects are often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:

·   Fires, explosions, blowouts and cratering

·   Equipment failures, casing collapse, pipe and cement failures

·   Marine risks such as capsizing or collisions

·   Adverse weather conditions, including hurricanes

·   Shortages or delays in the delivery of equipment

·   Acts of terrorism

·   Environmental hazards

·   Pipeline ruptures and discharge of toxic gases

Many of the above-mentioned risks could result in damage to life and / or property, or cause sustained interruption of production.

There is no guarantee that future such costs will be covered by insurance. In such instances, the cost for repairs would have to be covered by the Fund and, if the Fund is unable to pay for such costs, its interest in the particular well or project could be forfeited as a non-consent interest, which means that the Fund will have lost its right to participate in, but not ownership of, the well for certain period of time while and until the non-consent owner earns a generally stated amount of return from the well or project.

Insurance to cover certain of these risks may be prohibitively expensive or unavailable, particularly with respect to acts of terrorism. Additionally, insurance coverage may not be sufficient to cover certain catastrophic events. The Fund could be liable for costs in excess of its insurance coverage.

In addition, it is significantly less costly for insurance to be acquired and maintained by the Manager as a package that covers all of the oil and natural gas projects under its management. The majority of these projects are owned by other entities that are likewise managed by Ridgewood Energy. As a result, given insurance limits, if significant damage occurs to other projects owned by other investment vehicles managed by the Manager in any given year, the amount of insurance available to cover any damage to the Fund's projects could be significantly reduced.

The Fund’s investment activities may result in unsuccessful projects.

There is always significant risk that a project will not have commercially productive oil or natural gas reservoirs. In other words, the well may be a dry-hole. The successful acquisition of producing properties requires assessment of reserves, seismic and other engineering information, future commodity prices, operating costs and potential environmental liabilities. The Fund’s assessment of these factors may not be successful.

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The Fund has already experienced dry-holes and further dry-holes will adversely impact the fund’s profitability and returns.

The Fund has had four dry-holes, Eugene Island 357, East Breaks 157, Main Pass 155, and Vermilion 7/8. Cumulative dry-hole costs to the Fund for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004 totaled approximately $6.4 million, $4.1 million and $3.9 million, respectively. With respect to the dry-holes, the Fund does not anticipate incurring any significant future costs as all the wells have been plugged and abandoned. However, given that the Fund’s capital is limited to the amount it raised (less various fees) in the offering of its shares, the aforementioned dry-holes, and every other dry-hole that the Fund may experience, has the effect of reducing the limited capital available for investment. In addition, because dry-holes reduce the capital available for additional investment, a significant number of dry-holes will reduce the returns of the Fund because the remaining capital, even if invested in successful wells, may not generate enough cash for investors to realize significant or positive returns on their investments.

The actual costs to drill a well, or dry-hole costs, can materially exceed estimates due to cost overruns. In such event, the risks associated with the well increase.

When the Fund invests in a particular project the operator will generally provide what is referred to as an AFE or authorization for expenditures. The AFE(s) for a particular project generally represent the dry-hole costs associated with that project and not the development costs should the project be successful. Dry-hole costs are generally an estimate made by the Operator after considering numerous factors, such as water depth, drilling depth, seismic information, and equipment costs and availability. Notwithstanding the Operator’s best estimates of drilling cost, the actual drilling of the well may result in cost overruns that materially increase the costs of the drilling the project. The cost overrun can occur for any number of reasons including but not limited to, weather delays, equipment unavailability, pressure or irregularities in formations and other risks identified herein. The Fund has little choice but to pay these costs overruns or potentially lose its right to participate in the well by going non-consent. Significant cost overruns will increase the risk associated with the project as additional Fund capital that would otherwise be used for other projects is being allocated to cover the overruns.

The Fund’s reserve estimates are inherently uncertain and may be inaccurate and if so, may adversely affect the Fund’s revenue and profitability.

Once reserves are proved, there are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Fund’s control. Estimates of reserves by necessity are projections based on engineering and geological data, including but not limited to volumetrics, reservoir size, reservoir characteristics, the projection of future rates of production and the timing of future expenditures. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary and may not be accurate. Development of the Fund’s reserves may not occur as scheduled and the actual results may not be as estimated.

In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such reserve and cost estimate upward or downward. Accordingly, reserve estimates are often different, sometimes materially, from the quantities ultimately recovered. The Manager reviews the reserve estimates provided by the operators of projects in which the Fund participates and may retain independent reserve engineers to review such

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reserve estimates and/or conduct an independent review, as appropriate. Future performance that deviates significantly from reserve estimates could have a material effect (positive or negative) on the Fund’s operations, business and prospects, as well as on the amounts of such reserves.

Moreover, the Fund's estimated or proved oil and natural gas reserves and the estimated future net revenues from such reserves will be based upon various assumptions, including available geological, geophysical, engineering and production data. The process also requires certain economic assumptions such as oil and natural gas prices, drilling and operating expenses, capital expenditures, and availability of funds. As a result, the Fund is required to make assumptions and judgments, all of which can be wrong or inaccurate. Thus, these estimates are inherently imprecise and the quality and reliability of this information can vary, perhaps significantly, from actual results.

The prices that the Fund may receive for its oil or natural gas are highly volatile and unpredictable and may not be sufficient to generate enough cash flow to make distributions to investors.

When oil and natural gas production begins, the Fund's revenue, profitability and cash flow are highly dependent on the prices of oil and natural gas. Historically, the markets for crude 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. Therefore, it is impossible to predict the future price of crude oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability and, in such an event, the Fund may be required by accounting rules to write-down the carrying value of its projects.

The Fund has not engaged in any price risk management programs or hedges to date and does not anticipate engaging in those types of transactions in the future.

The Fund may be required to take write-downs if oil and natural gas prices decline

The Fund may be required under successful efforts accounting rules to write-down the carrying value of the Fund’s properties if oil and natural gas prices decline or if the Fund has substantial downward adjustments to the Fund’s estimated proved reserves, increases in the Fund’s estimates of development costs or deterioration in the Fund’s exploration results.

The Fund utilizes the successful efforts method of accounting for natural gas and oil exploration and development activities. If the net book value of the Fund’s natural gas and oil properties exceeds the Fund’s undiscounted cash flows, principles generally accepted in the United States (“GAAP”) require the Fund to impair or "writedown" the book value of the Fund’s natural gas and oil properties. Depending on the magnitude of any future impairments, a writedown could significantly reduce the Fund’s income, or produce a loss. As impairment computations involve the prevailing price on the last day of the quarter, it is impossible to predict the timing and magnitude of any future impairment. To the extent the Fund’s finding and development costs continue to increase as the Fund expects, the Fund will become more susceptible to impairments in low price environments. For the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004, the Fund recorded no impairment losses.

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The unavailability and cost of needed equipment may adversely affect the Fund’s profitability and operations.

As a result of the increase in oil and natural gas prices, drilling activity in the Gulf of Mexico has increased significantly. Drilling rigs and other equipment have become harder to obtain and more costly to acquire, especially if weather occurrences, such as hurricanes, occur with frequency in the Gulf of Mexico. These circumstances could have a negative impact on the Fund's operations.

The Fund has a limited amount of capital available to invest and therefore has limited ability to invest in many more projects. Further, each unsuccessful project erodes the Fund’s limited capital.

The capital raised by the Fund in its private placement is more than likely all the capital it will be able to obtain for investments in projects. Given its structure, obtaining traditional financing from public markets is unlikely and it is not practical to assume the Fund can raise additional funds through a supplemental offering or through debt financing. As a result, it has little, if any, ability to grow its business beyond its current projects or through investing its available cash in new projects. In any event, the number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund has experienced not only reduced its ability to generate revenue, but has also exhausted its limited supply of capital.

The Fund may incur costs to comply with the many environmental and other governmental regulations that apply to its operations, which may adversely impact its ability to generate cash flow for distributions.

The oil and natural gas industry, in general, and offshore activities, in particular, are subject to numerous governmental laws and regulations which may affect the ongoing and future operational decisions and financial results of the Fund. United States legislation affecting the oil and natural gas industry is under constant review for amendment and expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of projects, impose construction, abandonment and remediation requirements, prevent the waste of natural gas and liquid hydrocarbons through restrictions on flaring, require drilling bonds and regulate environmental and safety matters. Additionally, governmental regulations may also impact the demand for oil and natural gas, which could adversely affect the price at which oil and natural gas is sold. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, subsequently, affects its profitability. Finally, as additional legislation or amendments may be enacted in the future, the Fund is unable to predict the ultimate cost of compliance.

The Fund relies on third parties to operate, manage, and maintain its projects over which it has limited control. Therefore, decisions may be made by these third parties that adversely affect the Fund or its operations.

Neither the Fund nor the Manager currently own or have any plans to acquire drilling or production equipment nor does the Fund or Manager maintain a staff of technical employees required for on-site drilling operations. Therefore,

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the Fund must rely on unrelated third party operators to oversee and/or perform all drilling, completion and ongoing maintenance and production activities for the projects in which it participates. For example, lack of operating control could lead to higher operating costs, drilling delays, increased rig costs or labor issues. As such, the Fund has little or no control over the day-to-day operations of these projects. However, the Fund has acquired and will continue to seek projects, to the extent of its available capital, in which the operators have significant resources, are experienced in offshore operations and have a long term presence and track record of success in the Gulf of Mexico.

The Fund owns projects jointly with other companies over whom it has no control and who may influence the manner in which the project is operated.

The Fund participates in projects as a working interest owner along with other unrelated third party entities, including the operator. While the Manager may monitor and participate in decisions affecting exploration and development of the leases or projects in which the Fund participates, other decisions with respect to lease exploration and development activities may be controlled by the other participants and could be unfavorable to the Fund. Finally, the Fund could be held liable for the joint activity obligations or tortuous actions of the operator or other working interest owners. If the Fund’s co-participants fail to pay their portion of the drilling and completion or ongoing maintenance costs, the project may lack sufficient funds to perform such work. As a result, the Fund, as well as the remaining working interest owners, may be required to pay such additional sums in order to complete drilling or development of the project.

The Fund faces competition from larger entities with greater capital resources that could limit the number and availability of economically attractive projects.

As an independent oil and natural gas producer, the Fund faces competition in all aspects of its business. Many of its competitors are large, well-established companies that have significantly larger staffs and have greater capital resources. These companies may be able to pay more for a project or sustain losses for a longer period of time than the Fund.

The Fund maintains a salvage fund that may be insufficient to cover such salvage costs, in which event, the Fund could be liable for any excess.

The Fund has created a salvage fund to cover certain anticipated salvage costs associated with the Fund’s projects. The salvage fund may not have sufficient assets to meet salvage costs and thus the Fund may be liable for its proportionate share of the unfunded expenses if in excess of the salvage fund.

The Fund’s projects and operations are located exclusively in the Gulf of Mexico and are subject to interruptions and damage from hurricanes that could adversely affect the Fund’s cash flow.

The Fund has invested in projects exclusively within the Gulf of Mexico and any future investments by the Fund in projects will likewise be located in the Gulf of Mexico. As a result of such exclusivity in location, the Fund is particularly susceptible to hurricane risks in that the impact to the Fund’s operations of a severe storm or storms could be more pronounced and severe (depending on the storm, its path, and resulting damage) because the Fund does

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not have projects in other areas of the globe to offset such damage. If, for example, the Fund had projects in areas not affected by hurricanes those projects could still operate and generate cash flow during the interruptions in operations in the Gulf of Mexico. As it is, a hurricane, or series of hurricanes in a season, has the potential of interrupting all of the Fund’s operations, at least for some period of time, if all of the Fund’s projects were affected. In such event, the Fund would not have sufficient cash flow to make distributions to investors and, additionally and as disclosed earlier, insurance may not be sufficient to cover all of the damages caused by the hurricanes.

The Fund’s internal control over financial reporting could be adversely affected by material weaknesses in the Fund’s internal controls.

In the Fund’s Form 10-K/A for the year ended December 31, 2005, filed March 27, 2007, the Fund reported material weaknesses with respect to its lack of technical accounting resources on staff and the need for additional training, formalized policies and procedures on documenting financial controls. These control deficiencies resulted in the restatement of the Fund’s Form 10-K. As a result of these material weaknesses, the Fund concluded in its Form 10-K/A that its control over financial reporting was not effective as of the end of the periods covered by the reports. The Fund has remediated these material weaknesses. Investors, however, should be aware that the Fund cannot guarantee that future material weaknesses will not develop or be identified. Any new material weaknesses identified could harm the Fund’s operating results, cause the Fund to fail to meet its reporting obligations or result in material misstatements in it financial statements. Any such failure also could affect the ability of management to certify that the Fund's internal controls are effective when it provides an assessment of the Fund’s internal control over financial reporting.

RISKS RELATED TO THE NATURE OF THE FUND’SSHARES

The Fund’s shares have severe restrictions on transferability and liquidity and shareholders are required to hold the shares indefinitely.

The Fund's shares are illiquid investments. There is currently no market for these shares and one is not likely to develop. Because there will be a limited number of persons who purchase shares and because there are significant restrictions on the transferability of such shares under the Fund’s LLC agreement and under applicable federal and state securities laws, it is expected that no public market will develop. Moreover, neither the Fund nor the Manager will provide any market for the shares. Shareholders are generally prohibited from selling or transferring their shares except in the circumstances permitted under the LLC agreement and applicable law, and all such sales or transfers require the Fund's consent, which it may withhold at its sole discretion. Accordingly, shareholders have no assurance that an investment can be transferred and must be prepared to bear the economic risk of the investment indefinitely.

Shareholders are not permitted to participate in the Fund’s management or operations and must rely exclusively on the Manager.

Shareholders have no right, power or authority to participate in the Fund’s management or decision making or in the management of the Fund’s projects. The Manager has the exclusive right to manage, control and operate the Fund’s affairs and business and to make all decisions relating to its operation.

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The Fund’s assets are illiquid and, therefore, cash flow for distributions, if any, must come from operations and not dispositions of assets.

The Fund's interest in projects is illiquid. The Fund does not anticipate selling any interests in the projects, or any part thereof. Even if the Fund elected to sell, it is likely that there will be little or no market for these assets. However, if the Fund were to attempt to sell any such interest, a successful sale would depend upon, among other things, the operating history and prospects for the project or interest being sold, proven oil and natural gas reserves, the number of potential purchasers and the economics of any bids made by them and the current economics of the oil and natural gas market. In addition, any such sale may result in adverse tax consequences to the shareholders. The Manager has full discretion to determine whether any project, or any partial interest, should be sold and the terms and conditions under which such project would be sold. Consequently, shareholders will depend on the Manager for the decision to sell all or a portion of a project, or retain it, for the benefit of the shareholders and for negotiating and completing the sale transaction.

The Fund indemnifies its officers, as well as the Manager and its employees, for certain actions taken on its behalf and therefore, Fund assets may be used to reimburse such officers.

The LLC agreement provides that the Fund's officers and agents, the Manager, the affiliates of the Manager and their respective directors, officers and agents when acting on behalf of the Manager or its affiliates on the Fund's behalf, will be indemnified and held harmless by the shareholders from any and all claims rising out of the Fund's management, except for claims arising out of bad faith, gross negligence or willful misconduct or a breach of the LLC agreement. Therefore, the Fund may have difficulty sustaining an action against the Manager, or its affiliates and their officers based on breach of fiduciary responsibility or other obligations to the shareholders.

The Manager receives a management fee regardless of the Fund’s profitability and also receives cash distributions.

The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. The annual fee, payable monthly, is equal to 2.5% of total capital contributed by shareholders. In September 2006, the Manager changed its policy regarding the 2.5% annual management fee. Effective September 1, 2006, the annual management fee, payable monthly, will be equal to 2.5% of total shareholder capital contributions, net of cumulative dry-hole expenses incurred by the Fund.

In addition to an annual management fee, the Manager, as compensation for its management services, receives 15% of the Fund’s cash distributions to shareholders although the Manager has not contributed any cash to the Fund. Accordingly, shareholders contribute all of the cash utilized for the Fund's investments and activities. If the Fund's projects are unsuccessful, the shareholders lose 100% of their investment while the Manager, not having contributed any capital, will lose nothing. For the year ended December 31, 2006, distributions to the Manager were approximately $0.8 million. There were no distributions to the Manager for the year ended December 31, 2005 and for the period August 2, 2004 (Inception) through December 31, 2004.

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Inherent in these fee arrangements is the possibility of conflicts between the Fund's interests and the best interests of the Manager. The Manager may have incentive to act in its best interests rather than in the Fund’s best interest by taking actions designed to increase its fees but with significant risk to the Fund. Any such conflict of interests will be addressed by the Manager as described in the risk factor below headed “Because the Manager manages many other oil and natural gas funds, it may have conflicts of interest in its management of the Fund’s operations”.

None of the compensation to be received by the Manager has been derived as a result of arm's length negotiations.

Under Delaware law, shareholders have limited access to information and therefore, the Fund and Manager can restrict certain information, including shareholder information, making communications with other shareholders difficult. As a result, the information you receive about the Fund and its activities will be limited to what the Manager chooses to provide.

Delaware law permits Delaware limited liability companies to restrict access to certain information provided that such restricted access is set forth in the LLC agreement. The Fund's LLC agreement contains provisions that limit shareholder access to certain sensitive or confidential information such as trade secrets, agreements or confidential or proprietary information. Moreover, shareholder access to information regarding other shareholders is likewise limited and the Fund may refuse to give shareholder information, such as name and address of other shareholders, which could make it difficult for a shareholder to contact other shareholders. Nevertheless, shareholders do have access to tax, other financial information or any other reasonable information regarding Fund operations.

Cash distributions are not guaranteed and may be less than anticipated or estimated.

Distributions depend primarily on available cash from oil and natural gas operations. At times, distributions may be delayed to repay the principal and interest on fund borrowings, if any, or to fund other costs, although the Fund does not anticipate such borrowings. The Fund's taxable income will be taxable to the shareholders in the year earned, even if cash is not distributed.

Because the Manager manages many other oil and natural gas funds, it may have conflicts of interest in its management of the Fund’s operations.

Shareholders will not be involved in the management of the Fund's operations. Accordingly, they must rely on the Manager's judgment in such matters. Inherent with the exercise of its judgment, the Manager will be faced with conflicts of interest. While neither the Fund nor the Manager have specific procedures in place in the event of any such conflicting responsibilities, the Manager recognizes that it has fiduciary duties to the Fund in connection with its position and responsibilities as Manager and it intends to abide by such fiduciary responsibilities in performing its duties. Therefore, the Manager and its affiliates will attempt, in good faith, to resolve all conflicts of interest in a fair and equitable manner with respect to all parties affected by any such conflicts of interest. The Manager is not liable to the Fund for how conflicts of interest are resolved unless it has acted in bad faith, or engaged in gross negligence or willful misconduct.

TAX RISKS ASSOCIATED WITH AN INVESTMENT IN SHARES

The Fund is organized as a Delaware limited liability company and the Manager has qualified the Fund as a partnership for federal tax purposes. The principal tax risks to shareholders are that:

26

·   The Fund may recognize income taxable to the shareholders but may not distribute enough cash to cover the income taxes on the Fund's taxable income.

·   The allocation of Fund items of income, gain, loss, and deduction may not be recognized for federal income tax purposes.

·   All or a portion of the Fund's expenses could be considered either investment expenses (which would be deductible by a shareholder only to the extent the aggregate of such expenses exceeded 2% of such shareholder's adjusted gross income) or as nondeductible items that must be capitalized.

·   All or a substantial portion of the Fund's income could be deemed to constitute unrelated business taxable income, such that tax-exempt shareholders could be subject to tax on their respective portions of such income.

·   If any Fund income is deemed to be unrelated business taxable income, a shareholder that is a Charitable Remainder Trust could have all of its income from any source deemed to be taxable.

·   All or a portion of the losses, if any, allocated to the shareholders will be passive losses and thus deductible by the shareholder only to the extent of passive income.

·   The shareholders could have capital losses in excess of the amount that is allowable as a deduction in a particular year.

Although the Fund has obtained an opinion of counsel regarding the matters described in the preceding paragraph, it will not obtain a ruling from the IRS as to any aspect of the Fund's tax status. The tax consequences of investing in the Fund could be altered at any time by legislative, judicial, or administrative action.

If the IRS audits the Fund, it could require investors to amend or adjust their tax returns or result in an audit of their tax.

The IRS may audit the Fund's tax returns. Any audit issues will be resolved at the Fund level by the Manager. If adjustments are made by the IRS, corresponding adjustments will be required to be made to the federal income tax returns of the shareholders, which may require payment of additional taxes, interest, and penalties. An audit of the Fund's tax return may result in the examination and audit of a shareholder's return that otherwise might not have occurred, and such audit may result in adjustments to items in the shareholder's return that are unrelated to the Fund operations. Each shareholder bears the expenses associated with an audit of that shareholder's return.

In the event that an audit of the Fund by the IRS results in adjustments to the tax liability of a shareholder, such shareholder will be subject to interest on the underpayment and may be subject to substantial penalties. In addition, a number of substantial penalties could potentially be asserted by the IRS on any such deficiencies.

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The tax treatment of the Fund can not be guaranteed for the life of the Fund. Changes in law or regulations may adversely affect any such tax treatment.

Deductions, credits or other tax consequences may not be available to shareholders. Legislative or administrative changes or court decisions could be forthcoming which would significantly change the statements herein. In some instances, these changes could have substantial effect on the tax aspects of the Fund. Any future legislative changes may or may not be retroactive with respect to transactions prior to the effective date of such changes. Bills have been introduced in Congress in the past and may be introduced in the future which, if enacted, would adversely affect some of the tax consequences of the Fund.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

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ITEM 2. PROPERTIES

In 2004, the Fund acquired from BHP a 14.54% working interest in the West Cameron 77 #2 project of which one well has been drilled and is producing. The Fund anticipates drilling a second well in the future.
Well Name	Operator	Offshore	Working Interest %	Costs Incurred through 12/31/06 (in thousands)	Status
West Cameron 77#2	BHP Billiton	LA	14.54%	$ 9,127	Currently producing
In 2006, the Fund acquired Eugene Island 364 from El Paso. The well was deemed a success and began production in June 2006. After two months, the well encountered mechanical problems and has been shut in since for review by the partners.
Well Name	Operator	Offshore	Working Interest %	Costs incurred through 12/31/06 (in thousands)	Status
Eugene Island 364	El Paso	LA	50%	$ 13,036	Temporarily shut in for mechanical problems
In 2005, the Fund acquired Eugene Island 357 from Newfield. The well was deemed a dry-hole and was plugged and abandoned in March 2006.
Well Name	Operator	Offshore	Working Interest %	Costs incurred through 12/31/06 (in thousands)	Status
Eugene Island 357	Newfield	LA	7%	$ 1,707	DRY:March 2006
In 2005, the Fund acquired East Breaks 157 from ENI Petroleum (now Woodside). The well was deemed a dry-hole and was plugged and abandoned in March 2006.
Well Name	Operator	Offshore	Working Interest %	Costs incurred through 12/31/06 (in thousands)	Status
East Breaks 157	Woodside	TX	18%	$ 4,632	DRY:March 2006
In 2005, the Fund acquired a 20% working interest in Eugene Island 337 from Devon which was drilled in two zones, one at 12,500 feet which was dry and one at 7,500 feet which will be completed once a platform-based rig becomes available to Devon.
Well Name	Operator	Offshore	Working Interest %	Costs incurred through 12/31/06 (in thousands)	Status
Eugene Island 337	Devon	LA	20%	$ 5,184	Discovery July 2006: Waiting on Production

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In 2005, the Fund acquired a 30% working interest in Main Pass 155 from Samson Energy ("Samson") which was drilled and deemed a dry-hole in July 2005.
Well Name	Operator	Offshore	Working Interest %	Costs incurred through 12/31/06 (in thousands)	Status
Main Pass 155	Samson	AL	30%	$ 3,953	DRY:July 2005
In 2004, the Fund acquired a 26% working interest in Vermilion 7/8 from Apache Corporation ("Apache") in 2004. The well was drilled and deemed to be non-commercial and in April 2005, the blocks were released back to Apache.
Well Name	Operator	Offshore	Working Interest %	Costs incurred through 12/31/06 (in thousands)	Status
Vermilion 7/8	Apache	LA	26%	$ 4,069	DRY:January 2005
In October 2006, the Fund acquired a working interest in the following wells operated by LLOG.
Well Name	Operator	Offshore	Working Interest %	Drilling Risk (in thousands)	Status
Galveston 248	LLOG	TX	8.75%	$ 800	2nd quarter 2007 drilling date
Ship Shoal 81	LLOG	LA	8.75%	$ 600	3rd quarter 2007 drilling date
South Marsh Island 111	LLOG	LA	8.75%	$ 800	2nd quarter 2007 drilling date
Vermilion 344	LLOG	LA	8.75%	$ 1,100	Successful-completion in progress
West Delta 67	LLOG	LA	8.75%	$ 800	2nd quarter 2007 drilling date
West Delta 68	LLOG	LA	8.75%	$ 800	Successful-completion in progress

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 ("PW"), 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 PW. Thereafter, PW 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 is ongoing and no trial date has been set.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

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PART II.

ITEM 5. MARKET FOR REGISTANT’S COMMON EQUITY, RELATED SECURITY HOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Price of Common Units, Distributions and Related Shareholder Matters

There is currently no established public trading market for the shares of membership interest of the Fund. The Fund is not currently offering or proposing to offer any shares for sale to the public. There are no outstanding options or warrants to purchase, or securities convertible into shares and the Fund does not have any equity-based compensation plans. The shares are restricted as to resale. Shareholders wishing to transfer shares should also consider the applicability of state securities laws. The shares have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or under any other similar law of any state (except for certain registrations that do not permit free resale) in reliance upon what the Fund believes to be exemptions from the registration requirements contained therein. Because the shares have not been registered, they are restricted securities as defined in Rule 144 under the Securities Act. As of March 30, 2007, no shares of the Fund could be sold pursuant to Rule 144. The Fund has not agreed to register any shares under the Securities Act for sale by security holders.

As of the date of this filing, there were approximately 946 holders of Fund shares.

During the year ended December 31, 2006, the Fund paid $4.7 million and $0.8 million of distributions to its Shareholders and Manager, respectively. No Distributions were paid for the year ended December 31, 2005 and for the period August 2, 2004 (Inception) through December 31, 2004.

Participation in Costs and Revenues

The Fund’s investment objective is primarily to generate current cash flow for distribution to shareholders from the operation of the Fund projects to the extent that such distributions are consistent with the reserve requirements and operational needs of those projects. If the Fund does make distributions, this section describes how the Fund will:

·   determine what cash flow will be available for distributions to Investors,

·   distribute available cash flow,

·   give the Manager a share of cash flow, if available,

·   handle returns of capital contributions,

·   allocate income and deductions for tax purposes, and

·   maintain capital accounts for Investors.

Available cash determines what amounts in cash the Fund will be able to distribute in cash to Investors. There are three types of available cash as follows:

“Available Cash from Capital Transactions” is total cash received by the Fund from the proceeds of the sale or other disposition of the Fund’s property (including items such as insurance proceeds, refinancing proceeds, condemnation proceeds and other amounts received out of the ordinary course of business), but excluding dispositions of temporary investments of the Fund.

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“Available Cash from Temporary Investments” is cash from short-term investments (i.e. U.S. Treasury Bills, certificates of deposits) and other interest bearing cash accounts.

“Available Cash from Operations” is all other available cash.

There is no fixed requirement to distribute available cash; instead, it will be distributed to shareholders to the extent and at such times as the Manager believes is advisable. Once the amount and timing of a distribution is determined, it shall be made to shareholders as described below.

Distributions from Operations

At various times during a calendar year, the Fund will determine whether there is enough Available Cash from Operations for a distribution to shareholders. The amount of Available Cash from Operations determined to be available, if any, will be distributed to the shareholders. At all times, the Manager will be entitled to 15% and shareholders will be entitled to 85% of the Available Cash from Operations distributed.

Distributions of Available Cash from Capital Transactions

Available Cash from Capital Transactions that the Fund decides to distribute will be paid as follows:

·   Before shareholders have received total distributions equal to their capital contributions, 99% of Available Cash from Capital Transactions will be distributed to shareholders and 1% to the Manager.

·   After shareholders have received total distributions equal to their capital contributions, 85% of Available Cash from Capital Transactions will be distributed to Investors and 15% to the Manager.

General Distribution Provisions

Distributions to shareholders under the foregoing provisions will be apportioned among them in proportion to their ownership of their shares. The Manager has the sole discretion to determine the amount and frequency of any distributions; provided, however, that a distribution may not be made selectively to one shareholder or group of shareholders but must be made ratably to all shareholders entitled to that type of distribution at that time. The Manager in its discretion nevertheless may credit select persons with a portion of its compensation from the Fund or distributions otherwise payable to the Manager.

Because distributions, if any, will be dependent upon the earnings and financial condition of the Fund, its anticipated obligations, the Manager’s discretion and other factors, there can be no assurance as to the frequency or amounts of any distributions that the Fund may make.

Return of Capital Contributions

If the Fund for any reason at any time does not find it necessary or appropriate to retain or expend all capital contributions, in its sole discretion it may return any or all of such excess capital contributions ratably to shareholders. A return of capital contributions is not treated as a distribution. The Fund and the Manager will not be required to return any fees deducted from the original capital contribution or any costs and expenses incurred and paid by the Fund. Any such return of capital will decrease the shareholders’ capital contributions.

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Capital Accounts and Allocations

The tax consequences of an investment in the Fund to a shareholder in the event of dissolution depend on the shareholder’s capital account and on the allocations of profits and losses to that account. The Fund’s taxable profits or losses are allocated among the shareholders as described below and profits or losses are added to or subtracted from the shareholders’ capital accounts. The amounts allocated to each shareholder will generally not be equal to the distributions the shareholder receives until final liquidating distributions are made to shareholders.

The Fund does not currently anticipate that any contributions or distributions of property will be made. Certain additional adjustments to capital accounts will be made if necessary to account for the effects of non-recourse debt incurred by the Fund, if any, or contributions of property, if any, to the Fund.

The Fund issued an aggregate 535.6818 shares for gross proceeds of approximately $78.9 million. All sales of unregistered securities relied on Section 4(2) of the Securities Act and Rule 506 of Regulation D promulgated thereunder. All of the sales were made without the use of an underwriter. All purchasers of shares represented and warranted to the Fund that they were accredited investors as defined in Rule 501(a) under the Securities Act and that the shares were being purchased for investment and not for resale.

From the amount raised, approximately $8.6 million was disbursed for commissions and legal syndication fees. Additionally, approximately $3.6 million was paid as an investment fee to Ridgewood Energy Corporation, the Manager, for the investigation and evaluation of investment property prospects. Remaining funds are expected to be used for exploration and development activities of oil and natural gas properties as well as the operation of the Fund.

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ITEM 6. SELECTED FINANCIAL DATA

The following table summarizes certain selected financial data for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004 and is derived from the audited financial statements included herein. Although the date of formation of the Fund is August 2, 2004, the Fund did not begin business operations until September 7, 2004 when it began its private offering of shares. There were no business activities prior to September 7, 2004. The information summarized below should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and the Fund’s audited Financial Statements and related Notes.

	For the years ended December 31,						For the period August 2, 2004
($ in thousands except for share and per share amount)	2006			2005			(Inception) through December 31, 2004
Statement of Operations Data:
Revenues	$	7,780		$	-		$	-
Loss from operations		(6,074	)		(6,552	)		(8,035	)
Net loss		(4,427	)		(5,259	)		(7,965	)
Net loss per share	$	(9,353	)	$	(9,147	)	$	(14,566	)
Statement of Cash Flows Data:
Net cash flows provided by (used in) operating activities	$	5,176		$	(1,372	)	$	(3,887	)
Net cash flows used in investing activities		(35,543	)		(17,687	)		(3,890	)
Net cash flows (used in) provided by financing activities		(5,579	)		51			70,239
		December 31,
Balance Sheet Data:		2006			2005
Cash and cash equivalents	$	7,508		$	43,454
Short-term investment in marketable securities		15,656			-
Salvage fund		1,060			1,014
Oil and gas properties, net		23,418			11,883
Total assets		48,157			57,611
Total current liabilities		872			522
Total members' capital		47,060			57,066
Total liabilities and members' capital		48,157			57,611
Number of shares outstanding		535.6818			535.6818

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of Our Business

The Fund is an independent oil and natural gas producer. The Fund’s primary investment objective is to generate cash flow for distribution to our shareholders through participation in oil and natural gas exploration and development projects in the Gulf of Mexico. The Fund began its operations by offering shares in a private offering on September 7, 2004. As a result of such offering, it raised approximately $78.9 million through the sale of 535.6818 shares of LLC membership interests. After the payment of approximately $12.2 million in offering fees, commissions and investment fees to Ridgewood Energy Corporation, affiliates, and broker-dealers, the Fund retained approximately $66.7 million available for investment. Investment fees represent a one time fee of 4.5% of initial capital contributions. The fee is payable to the Manager for the service of investigating and evaluating investment opportunities and affecting transactions.

The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing 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. As compensation for the above duties, the Manager is paid a onetime investment fee (4.5% of capital contributions less dry-hole costs) for the evaluation of projects on the Fund’s behalf and an annual management fee (2.5% of capital contributions), payable monthly, for ongoing administrative and advisory duties as well as reimbursement of expenses. The Manager also participates in distributions as additional compensation for its administrative and management services. See also Item 1. “Business”.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in conformity with 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 our assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of the Fund’s 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.

35

However, future events and their effects cannot be predicted with absolute certainty. Therefore, the determination of estimates requires the exercise of judgment. Actual results inevitably will differ from these estimates and assumptions under different circumstances or conditions, and such differences may be material to the financial statements. See Note 2 - Summary of Significant Accounting Policies of Item 8. contained in this Form 10-K 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 exploratory dry-hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.

The costs of exploratory wells that find oil and natural gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. 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.

Proved Reserves

The Fund’s reserves are fully engineered on an annual basis by independent petroleum engineers. The Fund's estimates of proved reserves are based on the 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. 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 to change, as well as causing estimates of future net revenues to change. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving the Fund’s rate for recording depreciation, depletion and amortization.

Unproved Properties

Unproved properties is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress, wells pending determination and related capitalized interest. These costs are initially excluded from the

36

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 unevaluated property balance on an ongoing basis for possible impairment or reduction in value. The Fund believes that substantially all of the costs included in its unevaluated property balance will be evaluated in the next two years.

Asset Retirement Obligations

For oil and natural 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 fair value of legally required asset retirement obligations once it can be reasonably estimated. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.

Impairment of Long-Lived Assets

The Fund reviews long-lived assets, including oil and natural gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested based on identifiable cash flows (the field level for oil and gas assets) and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by undiscounted future net cash flow estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

In the case of oil and natural gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.

Results of Operations

The following review of operations and present financial condition should be read in conjunction with the Fund’s financial statements and the notes thereto.

Net loss. Net loss for the year ended December 31, 2006 was approximately $4.4 million, a decrease of approximately $0.9 million, or 16% compared to a net loss of approximately $5.3 million for the year ended December 31, 2005.

37

Net loss for the year ended December 31, 2005 was approximately $5.3 million, a decrease of approximately $2.7 million, or 34% compared to a net loss of approximately $8.0 million for the period August 2, 2004 (Inception) through December 31, 2004. 

See discussion below for details regarding results.

Oil and gas revenues. Oil and natural gas revenues for the year ended December 31, 2006 were approximately $7.8 million, an increase of approximately $7.8 million, or 100% compared to nil for the year ended December 31, 2005. This increase is the result of production in 2006 as compared to no production in 2005. Production volume for natural gas was approximately 890 thousand cubic feet (“MCF”) for the year ended December 31, 2006. Average sales price for natural gas was approximately $6.47 per MCF for the year ended December 31, 2006. Production volume for oil was approximately 29 thousand barrels for the year ended December 31, 2006. Average sales price for oil was approximately $68.76 per barrel for the year ended December 31, 2006.

There were no oil and natural gas revenues for the year ended December 31, 2005 and for the period August 2, 2004 (Inception) through December 31, 2004.

Investment fees. The Manager is paid a one time investment fee of 4.5% of initial capital contributions. The fee is payable for the service of investigating and evaluating investment opportunities and affecting transactions when the capital contributions are made. Investment fees incurred and paid for the period ended December 31, 2004 were approximately $3.6 million. There were no investment fees incurred or paid in 2006 and 2005.

Dry-hole costs. Dry-hole costs for the year ended December 31, 2006 were approximately $6.4 million, an increase of approximately $2.3 million, or 58% compared to approximately $4.1 million for the year ended December 31, 2005. This increase is predominately the result of plug and abandonment expenses incurred and paid in 2006 relating to two projects determined to be dry-holes, as compared to one project that was determined to be a dry-hole in 2005.

Dry-hole costs for the year ended December 31, 2005 were approximately $4.1 million, an increase of approximately $0.2 million, or 4% compared to approximately $3.9 million for the period August 2, 2004 (Inception) through December 31, 2004. Dry-hole costs in 2005 primarily related to Main Pass 155 while dry-hole costs in 2004 related to Vermilion 7/8.

The following table summarizes dry-hole costs for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004.

38

($ in thousands)	For the year ended December 31,				For the period August 2, 2004 (Inception) through December 31,
Dry-hole Costs:	2006		2005		2004
East Breaks 157	$	4,632	$	-	$	-
Eugene Island 357		1,707		-		-
Main Pass 155		77		3,876		-
Vermilion 7/8		-		179		3,890
Total Dry-hole Costs	$	6,416	$	4,055	$	3,890

Depletion and amortization. Depletion and amortization for the year ended December 31, 2006 was approximately $4.1 million, an increase of approximately $4.1 million, or 100% compared to nil for the year ended December 31, 2005. This increase is the result of production of reserve volumes in 2006 compared to no production in 2005.

There was no depletion and amortization in 2005 and 2004.

Lease operating expenses. Lease operating expenses represent the day to day cost of operating and maintaining wells and related facilities. For the year ended December 31, 2006 lease operating expenses were approximately $0.9 million, an increase of approximately $0.9 million, or 100% compared to approximately nil for the year ended December 31, 2005. This increase is the result of production activity in 2006 compared to no production in 2005.

There were no lease operating expenses in 2005 and 2004.

Management fees. Management fees for the year ended December 31, 2006 were approximately $1.9 million, a decrease of approximately $0.1 million, or 6% compared to approximately $2.0 million for the year ended December 31, 2005. Management fees are charged to cover expenses associated with overhead incurred by the Manager for its on-going management, administrative and advisory services. Such overhead expenses include but are not limited to rent, payroll and benefits for employees of the Manager, and other administrative costs. The decrease is due to the fact that effective September 2006, the Manager changed its policy regarding the annual management fee. Commencing September 1, 2006, the management fee payable is equal to 2.5% of the total Shareholder capital contributions, net of dry-hole expenses incurred by the Fund.

Management fees for the year ended December 31, 2005 were approximately $2.0 million, an increase of approximately $1.5 million, or 309% compared to approximately $0.5 million for the period August 2, 2004 (Inception) through December 31, 2004. This increase is a result of the Fund having fees for twelve months in 2005, compared to five months of fees in 2004.

Other operating expenses. Other operating expensesfor the year ended December 31, 2006 were approximately $12 thousand, primarily related to accretion expense for the West Cameron 77 and Eugene Island 364 properties, and geological costs of approximately $4 thousand.

Other operating expensesfor the year ended December 31, 2005 were approximately $310 thousand, related to geological costs and casualty loss of $200 thousand and $110 thousand respectively, for the West Cameron 77 #2 project.

Other operating expenses for the period August 2, 2004 (Inception) through December 31, 2004 were approximately $22 thousand, related to West Cameron 77 #2 project.

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The following table summarizes other operating expenses for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004.

($ Thousands)	For the year ended December 31,				For the period August 2, 2004 (Inception) through December 31,
Other operating expenses:	2006		2005		2004
Accretion expense	$	8	$	-	$	-
Geological costs		4		200		22
Casualty loss		-		110		-
Other operating expenses:	$	12	$	310	$	22

Other general and administrative expenses. Other general and administrative expenses for the year ended December 31, 2006 were approximately $605 thousand, an increase of approximately $390 thousand, or 181% compared to approximately $215 thousand for the year ended December 31, 2005. This increase is predominately the result of an increase in 2006 in both insurance costs and accounting fees.

Other general and administrative expenses for the year ended December 31, 2005 were approximately $215 thousand, an increase of approximately $158 thousand, or 277% compared to approximately $57 thousand for period August 2, 2004 (Inception) through December 31, 2004. This increase is predominately the result of an increase in 2005 in both insurance costs and accounting fees. In addition, this increase is a result of the Fund having other general and administrative expenses for twelve months in 2005 compared to five months in 2004.

The following table summarizes general and administrative expenses for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004.

($ Thousands)	For the year ended December 31,					For the period August 2, 2004 (Inception) through December 31,
Other general and administrative expenses:	2006		2005			2004
Accounting and legal fees	$	166	$	105		$	33
Insurance		409		112			25
Trust fees		30		-			-
Other		-		(2	)		(1	)
Other general and administrative expenses	$	605	$	215		$	57

Other Income. Other income is comprised of interest income on money market funds and short-term US Treasury Notes. Interest income remained consistent due to fluctuations in average cash balances and interest rates. Other income for the year ended December 31, 2006 was approximately $1.6 million, an increase of approximately $0.3 million, or 27% compared to approximately $1.3 million for the year ended December 31, 2005. This increase is the result of higher interest rates in 2006 compared to 2005.

40

Other income for the year ended December 31, 2005 was approximately $1.3 million, an increase of approximately $1.2 million, or 17% compared to approximately $0.1 million for the period August 2, 2004 (Inception) through December 31, 2004. This increase is predominately the result of higher interest rates in 2005 compared to 2004, and the Fund earning interest income for twelve months in 2005 compared to five months in 2004.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, 2006 were approximately $5.2 million, primarily related to cash receipts from oil and natural gas production of approximately $7.3 million, partially offset by cash expenditures for operating expenses.

Cash flows used in operating activities for the year ended December 31, 2005 were approximately $1.4 million, primarily related to cash expenditures for management fees paid approximating $2.0 million and operating expenses, partially offset by cash receipts from interest income.

Cash flows used in operating activities for the period August 2, 2004 (Inception) through December 31, 2004 were approximately $3.9 million, primarily related to the payment of the onetime investment fee of approximately $3.6 million and payments for management fees, partially offset by cash receipts from interest income.

Investing Cash Flows

Cash flows used in investing activities for the year ended December 31, 2006 were approximately $35.5 million, primarily related to capital expenditures for oil and gas properties and investment in marketable securities offset by the proceeds from the sale of marketable securities and insurance. Investing activities for oil and gas properties relate to the actual purchase of wells, infrastructure and other capital items unrelated to operating activities which occurs after a well has begun producing.

Cash flows used in investing activities for the year ended December 31, 2005 were approximately $17.7 million, and included approximately $4.4 million which the Fund advanced to operators for working interests and expenditures, approximately $12.3 million used for capital expenditures for oil and gas properties and approximately $1.0 million for funding of the salvage fund.

Cash flows used in investing activities for period August 2, 2004 (Inception) through December 31, 2004 were approximately $3.9 million, related to capital expenditures for oil and gas properties.

Financing Cash Flows

Cash flows used in financing activities consist of distributions to shareholders and the Manager. For the year ended December 31, 2006 distributions were approximately $5.6 million.

41

Cash flows provided by financing activities for the year ended December 31, 2005 were approximately $0.1 million, primarily related to the collection of subscription receivable of approximately $0.6 million, partially offset by syndication costs paid of approximately $0.5 million.

Cash flows provided by financing activities for the period August 2, 2004 (Inception) through December 31, 2004 were approximately $70.2 million, primarily related to contributions from shareholders offset by syndication costs paid of approximately $78.3 million and $8.1 million, respectively.

We expect to meet our cash commitments for the next twelve months from our cash and investments on hand.

Estimated Capital Expenditures

The Fund has entered into multiple operating 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, 2006, such estimated capital expenditures to be spent totaled approximately $21.2 million, all of which is expected to be paid out of unspent capital contributions within the following twelve months. Remaining unspent development capital will be reallocated to one or more new specified projects.

The table below presents exploration and development capital expenditures from inception as well as estimated budgeted amounts for future periods:

42

($ in thousands)
Estimated Capital Expenditures:
As of December 31, 2006 Projects		Spent through December 31, 2006		To be Spent Next 12 Months
West Cameron 77 #2 (i)	$	9.1		5.0
Eugene Island 364 (ii) (vii)		13.0		6.6
Eugene Island 337 (iii)		5.2		0.9
Galveston 248 (iv) (vii)		-		1.8
Ship Shoal 81(v) (vii)		-		1.4
South Marsh Island 111 (iv) (vii)		-		1.4
Vermilion 344 (vi)		0.2		1.4
West Delta 67 (iv) (vii)		-		1.3
West Delta 68 (vi)		-		1.4
	$	27.5	$	21.2

(i)	West Cameron 77 #2 began production in May 2006, unspent capital at December 31, 2006 relates to the addition of a second well.
(ii)	Eugene Island 364 began production in June 2006 and is currently shut-in due to mechanical problems, unspent capital represents estimated costs to sidetrack the well.
(iii)	Eugene Island 337 discovery in July 2006, production expected in April 2007.
(iv)	Project scheduled to begin drilling in 2nd quarter of 2007.
(v)	Project scheduled to begin drilling in 3rd quarter of 2007.
(vi)	Project successful during 1st quarter of 2007.
(vii)	Total project costs assume that the wells are commercially successful. If one of the budgeted exploratory projects are unsuccesful, budgeted development capital will be reallocated to one or more new unspecified projects.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its 2007 operations, including management fees and capital expenditures, with existing cash on-hand and income earned from its short-term investments and cash and cash equivalents. The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. Commencing in September 2006, the management fee, payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund.

With respect to the payment of management fees, until one of the Fund’s projects begins producing, all or a portion of the management fee is paid generally from the interest or dividend income generated by the Fund’s development capital that has not been spent, although the management fee can be paid out of capital contributions. Such interest and/or dividend income is more than enough to cover Fund expenses, including the management fee. Generally, it can take anywhere from 18 to 24 months to bring a project to production. Once a well is on production, the management fee and fund expenses are paid from operating income. Over time, as a well produces, the Fund may recover some or the entire management fee that may have been paid out of capital contributions.

Distributions, if any, 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.

The capital raised by the Fund in its private placement is more than likely all the capital that it will be able to obtain for investments in projects. The number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund experiences, if any, will not only reduce its ability to generate revenue, but also exhaust its limited supply of capital. Typically for a fund, the Manager seeks an investment portfolio that combines high and low risk exploratory projects.

When the Manager makes a decision for participation in a particular project, it assumes that the well will be successful and allocates enough capital to budget for the completion of that well and the additional development wells that are anticipated to be drilled. If the exploratory well is deemed a dry-hole or if it is un-economical, the capital allocated to the completion of that well and to the development of additional wells is then reallocated to a new project or used to make additional investments.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 2006 and 2005 and does not anticipate the use of such arrangements in the future.

43

Contractual Obligations

The Fund enters into 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 discuss or negotiate any such contracts. No contractual obligations exist at December 31, 2006 and 2005.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Projects drilled may not have commercially productive oil and natural gas reservoirs. In such an event, the Funds' revenue, future results of operations and financial condition would be adversely impacted.

The Fund does not have or use, any derivative instruments nor does it have any plans to enter into such derivative arrangements. The Fund will generally invest cash in high-quality credit instruments consisting primarily of money market funds, bankers’ acceptance notes and government agency securities with maturities of six months or less. The Fund does not expect any material loss from cash equivalents and therefore believes its potential interest rate exposure is not material. The Fund has no plan to conduct any international activities and therefore believes it is not subject to foreign currency risk.

The principal market risks to which the Fund is exposed that may adversely impact the Fund's results of operations and financial position are changes in oil and natural gas prices.

Low commodity prices could have an adverse affect on our future profitability and, in such an event the Fund may be required by accounting rules to writedown the carrying value of our projects. Revenue to the Fund will be sensitive to changes in price to be received for oil and natural gas production. Prevailing market prices fluctuate in response to many factors that are outside of the Fund's control such as the supply and demand for oil and natural gas. Availability of alternative fuels as well as seasonal risks such as hurricanes can also impact the supply and demand.

High oil and natural gas prices have resulted in a strong demand for and a tight supply of drilling rigs necessary to drill new projects. The increased cost in daily rig rates could have a negative impact on the return to shareholders in the Fund. The shortage of drilling rigs could delay the application of capital to such projects and thus delay revenue from operations.

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 and filed as part of this report.

44

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING FINANCIAL DISCLOSURE

As reported on a Form 8-K filed with the SEC on June 14, 2006, the Manager of the Fund dismissed Perelson Weiner, LLP as the Fund’s independent registered public accountants effective June 8, 2006.

The Fund was formed on August 2, 2004 and filed its Registration Statement on Form 10 in April 2005; thus, the period beginning August 2, 2004 and ended December 31, 2004 was the Fund's first audited reporting period. Perelson Weiner's audit report on the financial statements of the Fund for the period August 2, 2004 (Inception) through December 31, 2004 did not contain an adverse opinion or disclaimer of opinion, nor was such report qualified or modified as to uncertainty, audit scope or accounting principles.

From the date of inception of the Fund through June 8, 2006, there were no disagreements with Perelson Weiner on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Perelson Weiner, would have caused Perelson Weiner to make reference to the subject matter of the disagreements in their report on the Fund's financial statements for such period.

From the date of inception of the Fund through June 8, 2006, there were no "reportable events" as defined in Item 304(a)(1)(v) of Regulation S-K.

As reported on a Form 8-K filed with the SEC on July 13, 2006, the Manager of the Fund appointed Deloitte & Touche LLP (“D&T”) as the Fund’s independent registered public accountants effective July 12, 2006.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The Fund maintains "disclosure controls and procedures", as such term is defined under Securities and Exchange Act of 1934 (“Exchange Act”) Rule 13a-15(e), that are designed to ensure that information required to be disclosed in the Fund’s Exchange Act reports is recorded, processed, summarized and reported within the same time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to its management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, the Fund’s management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and its management necessarily was required to apply its

45

judgment in evaluating the cost-benefit relationship of possible controls and procedures. The Fund has carried out an evaluation, as of December 31, 2006, under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures. Based upon their evaluation and subject to the foregoing, such procedures were effective.

Changes in Internal Controls over Financial Reporting

In previous Exchange Act filings, the Fund has disclosed material weaknesses. Corrective actions have been implemented to address these material weaknesses. As of the period covered by this report, Management believes these material weaknesses have been remediated.

In the fourth quarter of 2006, the following material changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) have been implemented:

·   Expansion of accounting and SEC reporting staff and various resources, by hiring five personnel with GAAP and/or SEC accounting and reporting expertise;

·   Created detailed training programs, and policies and procedures surrounding the accounting for oil and natural gas projects and GAAP and SEC financial reporting controls; and

·   Enhanced tools and added appropriate resources to perform consistent, routine analytical reviews of the GAAP financial results, including key balance sheet and income statement account analyses.

Because the Fund is not an “Accelerated Filer” as defined in Rule 12b-2 of the Exchange Act, the Fund is not presently required to file Management’s annual report on internal control over financial reporting and the Attestation report of the registered public accounting firm required by Item 308(a) and (b) of Regulation S-K promulgated under the Securities Act. Under current rules, because the Fund is neither a “large accelerated filer” nor an “accelerated filer”, the Fund is not required to provide management’s report on internal control over financial reporting until the Fund files its annual report for 2007 and compliance with the auditor’s attestation report requirement is not required until the Fund files its annual report for 2008. The Fund currently expects to comply with these requirements at such time as the Fund is required to do so.

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 Manager. Ridgewood Energy was founded in 1982 and, as 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, 2006 are as follows:

Name, Age and Position with Registrant
        
Officer Since
        
        
Robert E. Swanson, 59
        
 
        
 
President and Chief Executive Officer
        
1982
        
        
W. Greg Tabor, 46
        
 
        
 
Executive Vice President and Director of Business Development
        
2004
        
        
Robert L. Gold, 47
        
 
        
 
Executive Vice President
        
1987
        
        
Kathleen P. McSherry, 41
        
 
        
 
Senior Vice President and Chief Financial Officer
        
2000
        
        
Daniel V. Gulino, 46
        
 
        

        
Senior Vice President and General Counsel
        
2003
        
        
Adrien Doherty, 54
        
 
        
 
Executive Vice President
        
2006
        
        

        
        

Set forth below is the name of and certain biographical information regarding, the executive officers of Ridgewood Energy and the Fund:

Robert E. Swanson has served as the President, Chief Executive Officer, sole director, and sole stockholder of Ridgewood Energy since its inception. Mr. Swanson is also the controlling member of Ridgewood Renewable Power, LLC (“Ridgewood Power”) and Ridgewood Capital Corporation (“Ridgewood Capital”), affiliates of Ridgewood Energy. Mr. Swanson has been President and registered principal of Ridgewood Securities Management, LLC and has served as the Chairman of the Board of Ridgewood Capital since its organization in 1998. 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.

Greg Tabor has served as the Executive Vice President and Director of Business Development for Ridgewood Energy since January 2004. Mr. Tabor was senior business development manager for El Paso Production Company from December 2001 to December 2003. From April 2000 to December 2001, Mr. Tabor was Vice President, Business Development for Madison Energy Advisors. Mr. Tabor is a graduate of the University of Houston.

47

Robert L. Gold has served as the Executive Vice President of Ridgewood Energy since 1987. Mr. Gold is also Executive Vice President of Ridgewood Power. 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. He is a graduate of Colgate University and New York University School of Law.

Kathleen P. McSherry has served as the Senior Vice President and Chief Financial Officer of Ridgewood Energy since 2000. Ms. McSherry has been employed by Ridgewood Energy since 1987, first as the Assistant Controller and then as the Controller before being promoted to Chief Financial Officer in 2000. Ms. McSherry also serves as Vice President of Systems and Administration of Ridgewood Power. Ms. McSherry holds a Bachelor of Science degree in Accounting from Kean University.

Daniel V. Gulino has served as Senior Vice President and General Counsel of Ridgewood Energy since August 2003. Mr. Gulino also serves as Senior Vice President and General Counsel of Ridgewood Power Management, Ridgewood Power, and Ridgewood Capital and has done so since 2000. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. He is a graduate of Fairleigh Dickinson University and Rutgers School of Law.

Adrien Doherty has served as Executive Vice President of Ridgewood Energy since 2006. Mr. Doherty joined Ridgewood Energy after a thirty year career in investment banking, most recently as Head of Barclay’s Capital’s oil and gas banking effort. Mr. Doherty is a graduate of Amherst College and the Wharton Graduate Division of the University of Pennsylvania.

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 of this Form 10-K. 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.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, 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, 2006, 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” for more information regarding Manager compensation and payments to affiliated entities.

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Compensation Discussion and Analysis

The executive officers of the Fund, Mr. Swanson, Mr. Tabor, Mr. Gold, Ms. McSherry, Mr. Gulino and Mr. Doherty, are employed by, and are executive officers of, the Manager, Ridgewood Energy, and provide managerial services to the Fund in accordance with the terms of the Fund’s LLC agreement. The Fund does not have any other executive officers. The Manager determines and pays the compensation of these officers. Each of the executive officers of the Fund also serves as an executive officer of each of the other funds managed by the Manager. Because the executive officers are employees of our Manager and provide managerial services to all of the funds managed by our Manager in the course of such employment, they do not receive additional compensation for providing managerial services to the Fund or to any one or more new funds established by the Manager than they would otherwise receive from the Manager if they did not serve in such capacities for the Fund or any such other funds.

The Manager is fully responsible for the payment of compensation to the executive officers. The Fund does not pay any compensation to its executive officers and does not reimburse the Manager for the compensation paid to executive officers. The Fund does, however, pay the Manager a management fee and the Manager may determine to use a portion of the proceeds from the management fee to pay compensation to executive officers of the Fund.

Report of the Manager

Because the Fund is managed by the Manager and does not have a Board of Directors or a Compensation Committee, the Manger reviewed and discussed with management the Compensation Discussion and Analysis included in the proxy statement. Based on such review and discussion, the Manager determined that the Compensation Discussion and Analysis be included in the proxy statement for filing with the Securities and Exchange Commission.

Submitted by the Manager

Robert E. Swanson, Chairman

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS

The following table sets forth information with respect to beneficial ownership of the shares as of December 31, 2006 (no person owns more than 5% of the shares) by:

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

·   all of the executive officers as a group.

49

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 December 31, 2006 and 2005. Other than the below, no officer and director owns any of the Fund's shares.

Name of beneficial owner	Number of shares	Percent
Robert E. Swanson (1), President and Chief	3.6667	*
Executive Officer
Executive Officer as a group (1)	3.6667	*

* Represents less than one percent.

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

In connection with the sale of shares in 2004, Ridgewood Securities Corporation, an affiliate of the Manager, earned a placement fee and commissions totaling approximately $0.8 million and $0.3 million, respectively, included in syndication costs. The Manager earned an investment fee for the services of investigating and evaluating projects for future investment totaling approximately $3.6 million.

The Manager was paid approximately $2.8 million to cover legal and syndication fees for the organization, distribution and offering expenses.

The Manager received a management fee, payable monthly, equal to 2.5% of total capital contributions, for general and administrative and management services supplied to the Fund. Additionally, when distributions are made, the Manager is entitled to a portion of funds distributed to shareholders. In September 2006, the Manager changed its policy regarding the 2.5% annual management fee. Effective September 1, 2006, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004 the Manager was paid management fees which totaled approximately $1.9 million, $2.0 million and $0.5 million, respectively.

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. For the year ended December 31, 2006, the Manager was paid distributions which totaled $0.8 million.For the year ended December 31, 2005 and the period August 2, 2004 (Inception) through December 31, 2004, there were no distributions paid to the Manager.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees and services rendered by Deloitte and Touche, LLP for the year ended December 31, 2006 and Perelson Weiner, LLP for the year ended December 31, 2005 and the period August 2, 2004 (Inception) through December 31, 2004.

($ Thousands)	For the year ended December 31,				For the period August 2, 2004 (Inception) through December 31,
Accounting Fees and Sevices	2006		2005		2004
Audit fees (1)	$	125	$	86	$	14
Tax fees (2)		24		19		19
	$	149	$	105	$	33

(1)	Fees for audit of finanancial statements, reviews of the related quarterly financial statements and reviews of documents filed with the SEC.
(2)	Fees related to professional services for tax compliance, tax advice and tax planning.

51

PART IV.

ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS
	(a) Index to Financial Statements:
Report of Independent Registered Public Accounting Firm		F-1
Balance Sheets as of December 31, 2006 and 2005		F-2
Statements of Operations for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004		F-3
Statements of Changes in Members' Capital for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004		F-4
Statements of Cash Flows for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004		F-5
Notes to Audited Financial Statements		F6-14

	(b) Exhibits:
Exhibits required by Section 601 of Regulation S-K.

Exhibit No.		Description
3	(i) (A)	Articles of Formation of Registrant (incorporated by reference to Exhibit 3.1 of Registrant's Registration Statement on Form 10-12 G/A filed with the Commission on September 2, 2005).
3	(i) (B)	Limited Liability Company Agreement of Registrant (incorporated by reference to Exhibit 10.1 of Registrant's Registration Statement on Form 10-12G/A filed with the Commission on September 2, 2005).
10.1		Registrant's Confidential Private Offering Memorandum (incorporated by reference to Exhibit 10.1A of Registrant's Registration Statement on form 10-12G/A filed with the Commission on September 2, 2005).
10.2		Offshore Operating Agreement between Apache Corporation and Ridgewood Energy Corporation as Manager of the Registrant (incorporated by reference to Exhibit 10.2 of Registrant's Registration Statement on Form 10-12G/A filed with the Commission on September 2, 2005).
10.3		Joint Development Agreement between BHP Billiton and Ridgewood Energy Corporation as Manager of the Registrant for West Cameron 77 (incorporated by reference to Exhibit 10.3 of Registrant's Registration Statement on Form 10-12G/A filed with the Commission on September 2, 2005).
10.4		Participation Agreement between Samson and Ridgewood Energy Corporation as Manager of the Registrant for the Main Pass project (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement on Form 10-12G/A filed with the Commission on September 2, 2005).
10.5	*	Participation Agreement between Gryphon Exploration Company (Woodside) and Ridgewood Energy Corporation as Manager of the Registrant for East Breaks 157.
10.6	*	Participation Agreement between Newfield Exploration and Ridgewood Energy Corporation as Manager of the Registrant for Eugene Island 357.
10.7	*	Participation Agreement between Devon Energy and Ridgewood Energy Corporation as Manager of the Registrant for Eugene Island 337.
10.8	*	Participation Agreement between LLOG Exploration and Ridgewood Energy Corporation as Manager of the Registrant for Galveston 248, Ship Shoal 81, South Marsh 111, Vermillion 344, West Delta 67 and West Delta 68.
14		Code of Ethics, adopted on August 2, 2004 (incorporated by reference to the Registrant’s Form 10-K filed with the SEC on March 15, 2006).
31.1	*	Certification of Robert E. Swanson, Chief Executive Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).
31.2	*	Certification of Kathleen P. McSherry, Chief Financial Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).
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 Registrant, and Kathleen P. McSherry, Chief Financial Officer of the Registrant.
*	Filed herewith

 

52

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the 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, 2006 and 2005, and the related statements of operations, changes in members’ capital, and cash flows for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004. These financial statements are the responsibility of the Fund’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy M Fund, LLC as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

April 10, 2007

Parsippany, New Jersey

F-1

RIDGEWOOD ENERGY M FUND, LLC
BALANCE SHEETS
(in thousands, except number of shares)
	December 31,
	2006			2005
Assets
Current Assets:
Cash and cash equivalents	$	7,508		$	43,454
Short-term investment in marketable securities		15,656			-
Production receivable		493			-
Insurance receivable		-			1,235
Prepaid expenses		22			25
Total current assets		23,679			44,714
Salvage fund		1,060			1,014
Oil and gas properties
Advances to operators for working interests and expenditures		-			4,366
Proved properties		22,163			7,052
Unproved properties		5,355			465
Less: accumulated depletion and amortization-proved properties		(4,100	)		-
Total oil and gas properties, net		23,418			11,883
Total assets	$	48,157		$	57,611
Liabilities and Members' Capital
Current Liabilities:
Due to operators	$	717		$	477
Accrued expenses payable		155			45
Total current liabilities		872			522
Non-current liabilities
Asset retirement obligations		225			23
Total non-current liabilities		225			23
Total liabilities		1,097			545
Commitments and contingencies (Note 8)
Members' capital:
Manager:
Distributions		(837	)		-
Accumulated deficit		105			(478	)
Manager's total		(732	)		(478	)
Shareholders:
Capital contributions (834 shares authorized; 535.6818 issued and outstanding as of December 31, 2006 and 2005)		78,887			78,887
Distributions		(4,742	)		-
Syndication costs		(8,597	)		(8,597	)
Accumulated deficit		(17,756	)		(12,746	)
Shareholders' total		47,792			57,544
Total members' capital		47,060			57,066
Total liabilities and members' capital	$	48,157		$	57,611
The accompanying notes are an integral part of these financial statements.

F-2

RIDGEWOOD ENERGY M FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
	For the years ended December 31,						For the period August 2, 2004 (Inception) through December 31,
	2006			2005			2004
Revenues
Oil and gas revenues	$	7,780		$	-		$	-
Expenses
Investment fees to affiliate (Note 6)		-			-			3,584
Dry-hole costs		6,416			4,055			3,890
Depletion and amortization		4,100			-			-
Lease operating expenses		867			-			-
Management fees to affiliate (Note 6)		1,854			1,972			482
Other operating expenses		12			310			22
Other general and administrative expenses		605			215			57
Total expenses		13,854			6,552			8,035
Loss from operations		(6,074	)		(6,552	)		(8,035	)
Other income
Interest income		1,647			1,293			70
Total other income		1,647			1,293			70
Net loss	$	(4,427	)	$	(5,259	)	$	(7,965	)
Manager - Net income (loss)	$	583		$	(359	)	$	(155	)
Shareholders - Net loss	$	(5,010	)	$	(4,900	)	$	(7,810	)
Net loss per share	$	(9,353	)	$	(9,147	)	$	(14,566	)
The accompanying notes are an integral part of these financial statements.

F-3

RIDGEWOOD ENERGY M FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except for share data)

 

For the period August 2, 2004 (Inception) through December 31, 2004
	# of Shares		Manager			Shareholders			Total
Balances, August 2, 2004 (Inception)		-	$	-		$	-		$	-
Shareholders capital contribution		536.1818		-			79,014			79,014
Subscriptions receivable		-		-			(680	)		(680	)
Syndication costs		-		-			(8,655	)		(8,655	)
Net loss		-		(155	)		(7,810	)		(7,965	)
Balances, December 31, 2004		536.1818	$	(155	)	$	61,869		$	61,714

For the year ended December 31, 2005
	# of Shares			Manager			Shareholders			Total
Balances, January 1, 2005		536.1818		$	(155	)	$	61,869		$	61,714
Return of shareholder's capital contributions		(0.5000	)		-			(127	)		(127	)
Collection of subscriptions receivable		-			-			680			680
Syndication costs recovered		-			-			58			58
Allocation of investment fees		-			36			(36	)		-
Net loss		-			(359	)		(4,900	)		(5,259	)
Balances, December 31, 2005		535.6818		$	(478	)	$	57,544		$	57,066

For the year ended December 31, 2006
	# of Shares		Manager			Shareholders			Total
Balances, January 1, 2006		535.6818	$	(478	)	$	57,544		$	57,066
Distributions		-		(837	)		(4,742	)		(5,579	)
Net income (loss)		-		583			(5,010	)		(4,427	)
Balances, December 31, 2006		535.6818	$	(732	)	$	47,792		$	47,060
The accompanying notes are an integral part of these financial statements.

F-4

RIDGEWOOD ENERGY M FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
	For the years ended December 31,						For the period August 2, 2004 (Inception) through December 31,
	2006			2005			2004
Cash flows from operating activities
Net loss	$	(4,427	)	$	(5,259	)	$	(7,965	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Interest earned on marketable securities		(656	)		-			-
Dry-hole costs		6,416			4,055			3,890
Depletion and amortization		4,100			-			-
Accretion expense		8			-			-
Changes in assets and liabilities
Increase in production receivable		(493	)		-			-
Decrease (increase) in prepaid expenses		3			10			(34	)
Increase in due to operators		114			-			-
Increase in accrued expenses payable		111			21			23
(Decrease) increase in due to affiliate		-			(199	)		199
Net cash provided by (used in) operating activities		5,176			(1,372	)		(3,887	)
Cash flows from investing activities
Payments to operators for working interests and expenditures		-			(4,366	)		-
Capital expenditures for oil and gas properties		(21,732	)		(12,307	)		(3,890	)
Proceeds from insurance receivable		1,235			-			-
Funding of salvage fund		-			(1,000	)		-
Interest income reinvested - salvage fund		(46	)		(14	)		-
Proceeds from the maturity of investment		15,346			-			-
Investment in marketable securities		(30,346	)		-			-
Net cash used in investing activities		(35,543	)		(17,687	)		(3,890	)
Cash flows from financing activities
Contributions from shareholders		-			-			78,334
Return of shareholder's capital contribution		-			(127	)		-
Collection of subscription receivable		-			680			-
Syndication costs paid		-			(560	)		(8,095	)
Distributions paid		(5,579	)		-			-
Syndication costs recovered		-			58			-
Net cash (used in) provided by financing activities		(5,579	)		51			70,239
Net (decrease) increase in cash and cash equivalents		(35,946	)		(19,008	)		62,462
Cash and cash equivalents, beginning of period		43,454			62,462			-
Cash and cash equivalents, end of period	$	7,508		$	43,454		$	62,462
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to dry hole costs	$	4,366		$	-		$	-
The accompanying notes are an integral part of these financial statements.

F-5

RIDGEWOOD ENERGY M FUND, LLC

NOTES TO AUDITED FINANCIAL STATEMENTS

1.   Organization and Purpose

The Ridgewood Energy M Fund, LLC ("Fund"), a Delaware limited liability company, was formed on August 2, 2004 and operates pursuant to a limited liability company agreement ("Agreement") dated as of September 7, 2004 by and among Ridgewood Energy Corporation ("Manager"), and the shareholders of the Fund. Although the date of formation is August 2, 2004, the Fund did not begin business activities until September 7, 2004 when it began its private offering of shares. There were no business activities prior to September 7, 2004.

The Fund was organized to acquire, drill, construct and develop oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund has devoted most of its efforts to raising capital and oil and natural gas exploration activities. The Fund began earning revenue in May 2006 from these operations and has ceased to be in the exploratory stage during the fourth quarter of 2006.

The Manager performs (or arranges for the performance of) the management, administrative and advisory 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 outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required (Notes 2, 5 and 6).

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 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 revenues and expenses during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to amounts advanced to and billed by operators, determination of proved reserves, impairment allowances and environmental liabilities. Actual results may differ from those estimates.

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 is required to advance its share of estimated cash outlay 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 transferred to unproved properties.

F-6

Oil and natural gas properties

Investments in oil and natural gas properties are operated by unaffiliated entities ("Operators") who 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 relating to the wells are advanced and billed by Operators through authorization for expenditures.

The successful efforts method of accounting for oil and natural gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and natural 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 crude oil and natural 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 (i.e. a producing well), the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. On the sale or retirement of an unproved property, gain or loss on the sale is recognized. It is not the Manager’s intention to sell any of the Fund’s property interests.

Capitalized acquisition costs of producing oil and natural gas properties after recognizing estimated salvage values are depleted by the unit-of-production method.

As of December 31, 2006 and 2005, approximately $0.7 million and $0.5 million was recorded in due to operators, respectively, related to the acquisition of oil and gas property. In 2006, the Fund paid the December 31, 2005 due to operators balance.

Revenue Recognition and Production Receivable

Oil and natural gas sales are recognized when delivery is made by the Operator to the purchaser and title is transferred (i.e. production has been delivered to a pipeline or transport vehicle). At the time of transfer a production receivable is recorded. For the years ended December 31, 2006, the Fund earned revenue approximating $7.8 million. The Fund earned no revenue in 2005 and 2004.

The volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas to which the Fund is entitled. The Fund will account for such oil and natural gas production imbalances by the entitlements method. Under the entitlements method, the Fund will recognize a receivable from other working interest owners for volumes oversold by other working interest owners. For volumes oversold by the Fund, a payable to other working interest owners will be recorded. As of December 31, 2006 and 2005, there were no material oil or natural gas balancing arrangements between the Fund and other working interest owners.

F-7

Syndication Costs

Direct costs associated with offering the Fund’s shares including professional fees; selling expenses and administrative costs relating to broker-dealer relationships, payable to the Manager, an affiliate of the Manager and outside brokers are reflected as a reduction of shareholders’ capital.

Asset Retirement Obligations

For oil and natural 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.

($ Thousands)	December 31,
Asset Retirement Obligations:	2006			2005
Balance - Beginning of period	$	23		$	-
Liabilities incurred		501			240
Liabilities settled		(307	)		(217	)
Accretion expense		8			-
Balance - End of period	$	225		$	23

Impairment of Long-Lived Assets

In accordance with the provisions of SFAS No. 144, “Accounting for the Impairment of Long-Lived Assets”, long-lived assets, such as oil and natural gas properties, are evaluated when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is made by comparing the carrying values of long-lived assets to the estimated future undiscounted cash flowsattributable to the asset. The impairment loss recognized is the excess of the carrying value over the future discounted cash flows attributable to the asset or the estimated fair value of the asset.  For the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004, the Fund had no impairments of long-lived assets.

Depletion and Amortization

Depletion and amortization of the cost of proved oil and natural gas properties are calculated using the units of production method. Proved developed reserves are used as the base for depleting the cost of successful exploratory drilling and development 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. As of December 31, 2006 and 2005, the Fund had recorded accumulated depletion and amortization of approximately $4.1 million and nil, respectively.

Income Taxes

No provision is made for income taxes in the financial statements. Because the Fund is a limited liability corporation, the income or losses are passed through and included in the tax returns of the individual shareholders.

F-8

Cash and cash equivalents

All highly liquid investments with maturities when purchased of three months or less are considered as cash and cash equivalents. At times, bank deposits may be in excess of federal insured limits. As of December 31, 2006 and December 31, 2005, respectively, bank balances exceeded federally insured limits by approximately $7.3 million and $43.3 million, respectively. The Fund maintains bank deposits with accredited financial institutions to mitigate such risk.

Salvage Fund

The Fund deposits in a separate interest-bearing account, or a salvage fund, money to provide for dismantling production platforms and facilities, plugging and abandoning the wells and removing the platforms, facilities and wells after their useful lives, in accordance with applicable federal and state laws and regulations. Interest earned on the account will become part of the salvage fund, there are no legal restrictions on the withdrawal of the salvage fund.

Short-term investments in marketable securities

At times the Fund may purchase short-term investments comprised of US Treasury Notes with maturities greater than three months and as such are considered held-to-maturity investments. Held-to-maturity securities are those investments that the Fund has the ability and intent to hold until maturity. Held-to-maturity investments are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate market value. Interest income is accrued as earned. Held to maturity investments of approximately $16.7 million including the salvage fund as of December 31, 2006 matured in February 2007. There were no held to maturity investments as of December 31, 2005.

Income and Expense Allocation

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

3.   Recent Accounting Standards

In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. An entity would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The decision about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and it is applied only to entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets

F-9

and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year provided the entity also elects to apply the provisions of SFAS No. 157, “Fair Value Measurements, (“SFAS 157”). Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings. Since the provisions of SFAS 159 are applied prospectively, any potential impact will depend on the instruments selected for fair value measurement at the time of implementation. The Fund does not believe that its financial position, results of operations or cash flows will be impacted by the adoption of SFAS No. 159.

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" ("SFAS No. 157") which applies under most other accounting pronouncements that require or permit fair value measurements.  SFAS No. 157 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 new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements.   SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007.  The Fund does not expect this guidance to have a material impact on the financial statements.  

In September 2006, the SEC Staff issued Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB No. 108”) in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the two methods used for quantifying the effects of financial statement errors were the rollover and iron curtain methods. Under the rollover method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The iron curtain method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a dual approach which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the dual approach method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. The Fund has adopted the provisions of SAB No. 108 and there was no impact to its financial position, results of operations and cash flows as a result of this pronouncement.

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. Capitalization 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. Dry-hole costs were approximately $6.4 million, $4.1 million and $3.9 million, respectively, for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004, respectively.

The following table reflects the net changes in unproved properties as of December 31, 2006 and 2005. As of December 31, 2006 and 2005, the Fund had no capitalized exploratory well costs greater than one year.

F-10

($ in thousands)	Year ended December 31,
Exploratory Drilling Costs:	2006			2005
Balance - Beginning of period	$	465		$	-
Additions to capitalized exploratory well costs pending the determination of proved reserves		5,162			7,517
Reclassification to proved properties based on the determination of proved reserves		-			(7,052	)
Capitalized exploratory well costs charged to dry-hole costs		(272	)		-
Balance - End of period	$	5,355		$	465

5.   Distributions

Distributions to shareholders are allocated in proportion to the number of shares held.

The Manager will determine whether available cash from operations, as defined in the Fund’s LLC agreement, is to be distributed. Such distribution would be allocated 85% to the shareholders and 15% to the Manager, as defined in the Fund’s LLC agreement

Available cash from dispositions, as defined in the Fund's 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.

The shareholders received distributions of approximately $4.7 million for the year ended December 31, 2006.

The Manager received distributions of approximately $0.8 million for the year ended December 31, 2006.

There were no distributions in 2005 or for the period August 2, 2004 (Inception) through December 31, 2004.

6.   Related Parties

The Manager was paid a one time investment fee of 4.5% of initial capital contributions. Fees are payable for services of investigating and evaluating investment opportunities and effecting transactions when the capital contribution is made. Investment fees of approximately $3.6 million were paid for the period August 2, 2004 (Inception) through December 31, 2004. There were no investment fees in 2006 and 2005.

The Fund’s Agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager receives an annual management fee, payable monthly, of 2.5% of total capital contributions. Management fees of approximately $1.9 million, $2.0 million and $0.5 million were incurred and paid for the years ended December 31, 2006 and 2005 and for the period August 2, 2004 (Inception) through December 31, 2004, respectively. In September 2006, the Manager changed its policy regarding the 2.5% annual management fee. Effective September 1, 2006, the annual management fee, payable monthly, will be equal to 2.5% of total shareholder capital contributions, net of cumulative dry-hole expenses incurred by the Fund.

F-11

From time to time, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. As of December 31, 2006 and 2005, nil was due to or from affiliates.  

None of the compensation to be received by 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

As of December 31, 2006 and 2005, the carrying value of cash and cash equivalents, short term investments in marketable securities, and salvage fund approximate fair value.

8.   Commitments and Contingencies

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 the Operators 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 natural 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. As of December 31, 2006and 2005, there were no known environmental issues that required the Fund to record a liability.

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 which 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 Manager’s investment programs. Claims made by other such programs can reduce or eliminate insurance for the Fund.

The Fund records receivables for insured costs when the expected insurance proceeds are probable and reasonably estimable.

9.   Information About Oil and Natural Gas Producing Activities

In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities,” this section provides supplemental information on oil and natural gas exploration and producing activities of the Fund.

The Fund is engaged solely in oil and natural gas activities, all of which are located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

F-12

Table I - Capitalized Costs Related to Oil and Gas Exploration and Producing Activities
(in thousands)
	December 31,
	2006			2005
Proved oil and gas properties	$	22,163		$	7,052
Unproved oil and gas properties		5,355			465
Advances to operators for working interests and expenditures		-			4,366
Total oil and gas properties		27,518			11,883
Accumulated depletion and amortization - proved properties		(4,100	)		-
Oil and gas properties - net capitalized costs	$	23,418		$	11,883

Table II - Costs Incurred in Exploration, Property Acquisitions and Development
(in thousands)
	For the year ended December 31,				For the period August 2, 2004 (Inception) through December 31,
	2006		2005		2004
Exploratory drilling costs - capitalized	$	20,273	$	11,883	$	-
Exploratory drilling costs - expensed		1,778		4,055		3,890
Geological costs		5		200		22
	$	22,056	$	16,138	$	3,912

Table III - Reserve Quantity Information (Unaudited)

Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer for the years ended December 31, 2006 and 2005. The Fund had no proved developed and undeveloped reserves prior to 2005. The reserve estimates for December 31, 2006 and 2005 were based on estimated future reserves as of September 30, 2006 and 2005, respectively, further adjusted for fourth quarter production. These reserves have been prepared in compliance with the Securities and Exchange Commission rules.

Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.

	United States
	For the year ended December 31,
	2006						2005
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)		Gas (MCF)
Proved undeveloped reserves:
Beginning of Year		38,890			4,351,458			-		-
Discoveries		542,991			4,524,929			38,890		4,351,458
Revisions of previous estimates (1)		44,136			94,226			-		-
Production		(28,764	)		(890,340	)		-		-
End of Year		597,253			8,080,273			38,890		4,351,458

(1) Due to the inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

F-13

Table IV - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Unaudited)

(in thousands)

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. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Fund's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.

	For the year ended December 31,
	2006			2005
Future estimated revenue	$	82,054		$	46,300
Future estimated production costs		(2,670	)		(1,202	)
Future estimated development costs		(7,217	)		(3,599	)
Future net cash flows		72,167			41,499
10% annual discount for estimated timing of cash flows		(22,509	)		(14,359	)
Standardized measure of discounted future estimated net cash flows	$	49,658		$	27,140

Table V - Changes in the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Unaudited)

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.

	For the year ended December 31,
	2006			2005 (1)
Standardized measure beginning of the year	$	27,140		$	-
Sales of oil and gas production, net of production costs		(6,913	)		-
Net changes in prices and production costs		(11,678	)		-
Extensions, discoveries, and improved recovery and techniques, less related costs		34,820			26,462
Development costs incurred during the period		1,966			-
Revision of development costs		-			-
Revision of previous reserve quantities estimate		886			-
Accretion of discount		2,878			678
Timing and other		559			-
Standard measure end of the year	$	49,658		$	27,140

(1) Our initial standardized measure of discounted future net cash flows related to proved oil and gas reserves was performed as of September 30, 2005 and was adjusted for fourth quarter 2005 production.

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 since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with revision 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 of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs 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.

F-14

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	RIDGEWOOD ENERGY M FUND, LLC
Date: April 10, 2007	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson
		Chief Executive Officer (Principal Executive Officer)

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

Signature	Capacity	Date
/s/ ROBERT E. SWANSON Robert E. Swanson	Chief Executive Officer (Principal Executive Officer)	April 10, 2007
/s/ KATHLEEN P. MCSHERRY Kathleen P. McSherry	Senior Vice President and Chief Financial Officer (Principal Accounting Officer)	April 10, 2007

53

EX-10.5

                                                                    EXHIBIT 10.5
                                 [WOODSIDE LOGO]


                           Woodside Energy (USA) Inc.

September 7, 2005


Mr. Martin V. Black                             Mr. Greg Tabor
Eni Petroleum                                   Ridgewood Energy Corporation
1201 Louisiana, Suite 3500                      11700 Old Katy Road, Suite 230
Houston, Texas 77002                            Houston, Texas 77079


Re:      Topaz Prospect Well Participation Agreement dated July 1, 2005
         East Breaks 157 No-4 (OCS-G 11412 #4)
         East Breaks Blocks 112 & 157, NG 15-1
         GOM


Gentlemen:

Enclosed please find your fully executed original Topaz Prospect Well
Participation Agreement dated July 1. 2005.

Pursuant to the terms of the Topaz Prospect Well Participation Agreement
Woodside respectfully requests that Eni Petroleum prepare and execute
Designation of Operator forms naming Woodside Energy (USA) Inc., GOM number
2407, as the operator of the East Breaks 157 No.4 (OCS-G 11412 #4).

It was a pleasure working with both of you on the Topaz contracts. Let me know
if you require anything further from Woodside.

Best Regards,


/s/ Brad L. Dowdell
Brad L. Dowdell
Director-Land
713-401-0014



                                                                 [WOODSIDE LOGO]
                                  EXHIBIT "D"
     Attached to and made part of that certain Participation Agreement among
       Eni Petroleum Exploration Co. Inc., Woodside Energy (USA) Inc. and
                                Ridgewood Energy
                    Corporation dated Effective July 1, 2005

                      Topaz AFE East Breaks 157 - Well #4
                      -----------------------------------
RIG POSITIONING DAYS:   2.5 days      SHL:      UTM X:        1,077,753.0 US ft
            D&E DAYS:  32.5 days                UTM Y:       10,100,897 0 US ft
          TOTAL DAYS:  35.0 days      PBHL:     UTM X:        1,077,753.0 US ft
                                                UTM Y:       10,100,897.0 US ft
               DEPTH:  12,000    ft MD                                    AFE #
                       12,000    ft TVD             Rig: Unknown
         WATER DEPTH:  940       ft            Rev Date:  06/23/05
Assumptions:
1. Straight hole to 12,000 ft MD/TVD
2. Wireline logs at TD.


                                                         Drill, Evaluate, T&A           Total
DESCRIPTION                          Rig Mob / Demob         Original Hole          Original Hole
- -------------------------------------------------------------------------------------------------
   Section 1 : Time Sensitive
   --------------------------
                                                                               
1 Rig Rate                                   312,500             4,062,500              4,375,000
2 Support Vessels                            228,750               633,750                862,500
3 Woodside Supervision                         7,500                97,500                105,000
4 Well Site G&G                                    0                     0                      0
5 Aviaton                                     13,750               178,750                192,500
6 Mud Logging                                      0                19,200                 19,200
7 Mud Engineering                                  0                46,313                 46,313
8 Cementing Services                           7,625               124,125                131,750
9 Communications                               2,250                29,250                 31,500
10 Solids Control                                  0                     0                      0
11 Diving / ROV                               10,000               130,000                140,000
12 Directional Drilling                            0               132,500                132,500
13 Wellhead Services                               0                     0                      0
14 Metocean                                      750                 9,750                 10,500
16 Completion and Workover Services                0                     0                      0
17 Supply Base                                 8,750               113,750                122,500
19 Rental Tools                                8,625               112,125                120,750
20 Fishing / Cutting Services                      0                50,000                 50,000
21 Rig Contractor Additional Charges           3,750                48,750                 52,500
   Contingency 20%                           120,850             1,157,653              1,278,503
- -------------------------------------------------------------------------------------------------
Total Time Sensitive                         725,100             6,945,915              7,671,015

   Section 2 : Non Time Sensitive
   ------------------------------
22 Rig Positioning                           103,000                     0                103,000
23 Site Survey                                     0                25,000                 25,000
24 HSE                                             0                     0                      0
25 Studies/ Analysis                               0               125,000                125,000
26 Wireline Logging                                0               178,000                178,000
27 Coring                                          0                     0                      0
28 Freight and Materials Handling              5,000                65,000                 70,000
29 Tubular Running Services                        0               120.000                120,000
30 Inspection and refurbishment                    0                40,000                 40,000
   Contingency 20%                            21,600               110,600                132,200
- -------------------------------------------------------------------------------------------------
Total Non Time Sensitive                     129,600               663,600                793,200

   Section 3 : Tangibles & Consumables
   -----------------------------------
31 Wellhead Equipment                              0               287,200                287,200
32 Tubulars                                        0             1,085,700              1,085,700
33 Tubular Accessories                             0                45,000                 45,000
34 Mud and Chemicals                               0               800,000                800,000
35 Cement and Additives                            0               265,000                265.000
36 Drill Bits                                      0                90,200                 90,200
37 Completion Consumables                          0                     0                      0
38 Solids Control Equipment                        0                     0                      0
39 Rig Consumables                                 0                 5,000                  5,000
40 Fuel                                       79,750               464,750                544,500
   Contingency 20% on consumables             15,950               324,990                340,940
- -------------------------------------------------------------------------------------------------
Total Tangibles & Consumables                 95,700             3,367,840              3,463,540

   Section 4 : Administration
   --------------------------
41 Overhead                                    4,752                54,949                 59,701
42 Training                                        0                     0                      0
43 Travel                                          0                12,544                 12,544
- -------------------------------------------------------------------------------------------------
   Total Administration                        4,752                67,493                 72,245

                                AFE Total  $ 955,152     $      11,044,848             12,000,000

                                Well Ownership                 %WI                  TOTAL COST
                                Woodside Energy - USA Inc.   37.5000                $4,500,000
                                ENI Petrolium                25.0000                $3,000,000
                                Ridgewood Energy             37.5000                $4,500,000
                                Total                       100.0000               $12,000,000


PREPARED BY:  ___________________________  ___________________________
              DRILLING ENGINEER            DATE
APPROVED BY:  ___________________________  ___________________________
              OPERATIONS MANAGER           DATE
              ___________________________  ___________________________
              PRESIDENT                    DATE
APPROVED BY:  ___________________________  ___________________________
              JOINT OPERATED PARTNER       DATE




                             PARTICIPATION AGREEMENT

THIS PARTICIPATION AGREEMENT is entered into effective this 1st day of July,
2005. by and between, WOODSIDE ENERGY (USA) INC., a corporation organized and
existing under the laws of the State of Delaware, U.S.A. (hereinafter referred
to as "Woodside"), RIDGEWOOD ENERGY CORPORATION, a corporation organized and
existing under the laws of the State of Delaware, U.S.A (hereinafter referred to
as "Ridgewood) and ENI PETROLEUM EXPLORATION CO. INC., a corporation organized
and existing under the laws of the State of Delaware, U.S.A., (hereinafter
referred to as "Eni").

For and in consideration of the mutual covenants set forth herein and other good
and valuable consideration, Woodside, Ridgewood and ENI hereby agree as follows:


                                   ARTICLE I.
                                   DEFINITIONS

As used in this agreement, the following terms shall have the meanings set forth
below:

1.1  "Accounting Procedure" means the rules, provisions and conditions set forth
     in Exhibit "C" to the Offshore Operating Agreement.

1.2  "Affiliate" means a company or partnership or other legal entity which
     controls, or is controlled by, or which is controlled by an entity which
     controls, a Party. Control means the ownership directly or indirectly of
     more than fifty percent (50%) of the voting rights in a company,
     partnership or legal entity.

1.3  "Agreed Interest Rate" means the rate set forth in Article 3.B. of the
     Accounting Procedure.

1.4  "Agreement" means this Agreement, together with the Exhibits attached to
     this Agreement, and any extension, renewal or amendment hereof agreed to in
     writing by the Parties.

1.5  "AFE" means the Authorization for Expenditure submitted by Woodside in the
     gross amount of $ 12,000,000.00 to cover the estimated costs to drill the
     Test Well, which is attached as Exhibit "D".

1.6  "Casing Point" means that point in time when the Test Well has reached the
     Objective Depth (as hereinafer defined) from the surface location and at
     the bottom hole location as originally proposed arid after all open hole
     logs, cores and other tests included in the AFE for such well, or as the
     Parties may otherwise mutually agree, have been conducted.

1.7  "East Breaks 112 Unit Participating Areas" means each of (i) the
     Participating Areas in the East Breaks 112 Unit, being 900 acres located in
     East Breaks Block 112, but limited to the sand reservoir outline as
     depicted on Exhibit B, and further limited to the stratigraphic equivalent
     of the interval shown on Exhibit B-1 as depicted on the electric log of the
     East Breaks 112 No.3 Well as the "E" Sand Reservoir and (ii) the


                                       1


     Participating Area in East Breaks Block 157, being 2250 acres located in
     East Breaks 157, but limited to the sand reservoir outline(s) as depicted
     on Exhibit B, and further limited to (a) the stratigraphic equivalent of
     the interval shown on Exhibit B-1 as depicted on the electric log of the
     East Breaks 157 No. 2 Well as the "A" Sand Reservoir and (b) the
     stratigraphic equivalent of the interval shown on Exhibit B-1 as depicted
     on the electric log of the East Breaks 157 No. 1 Well as the "B" and "C"
     Sand Reservoirs, as each of the Participating Areas may after the Effective
     Date be enlarged.

1.8  "Excluded Area" means that area within East Breaks Blocks 112 and 157 that
     is comprised of the East Breaks 112 Unit Participating Areas, as limited in
     Article 1.7 above, as such exists at the Effective Date and as the same may
     be expanded after the Effective Date of this Agreement.

1.9  "Leases" means the federal oil and gas leases as identified in Exhibit "A."

1.10 "MMS" means the Minerals Management Service or any successor organization
     thereto having authority to issue and regulate federal oil and gas lease
     activity in the Outer Continental Shelf.

1.11 "Offshore Operating Agreement" means the instrument attached as Exhibit
     "C."

1.12 "Party" or "Parties" means any of the entities named in the first paragraph
     to this Agreement and any respective permitted successors or assigns.

1.13 "Operator" means Woodside for the drilling and plugging or temporary
     abandonment of the Test Well and Eni for the tie back operations and
     subsequent completion and development drilling.

1.14 "Subject Interests" means an undivided twenty-five percent (25%) operating
     rights interest to be earned by each of Woodside and Ridgewood and assigned
     by Eni to each of Woodside and Ridgewood in and to the Leases less and
     except the Excluded Area.

1.15 "Topaz" is the name of the geological prospect to be evaluated by the Test
     Well that is drilled pursuant to this Agreement.

1.16 "Well Participating Area" means the area for which the Subject Interests
     will apply and is to include all of East Breaks Blocks 112 and 157, less
     and except the Excluded Area,


                                   ARTICLE II.
                                      TERM

2.1  This Agreement shall continue in force and effect and be binding upon the
     Parties for a period commencing upon the effective date and expiring July
     1st, 2006. This Agreement shall also be amended and renewed by mutual
     agreement of the parties.


                                       2


                                  ARTICLE III.
                                DRILLING PROGRAM

3.1  Eni represents, without warranty of title, except by, through and under
     Eni, that it is the owner of one hundred percent (100%) record title
     interest in the Leases, and that the Subject Interests (as defined in 1.14)
     to be earned by Woodside and Ridgewood pursuant to this Agreement shall be
     free and clear of all liens, claims and encumbrances. The Leases, as to all
     depths, described on Exhibit "A" comprise all of and are subject to the
     East Breaks 112 Unit (Unit No. 754391005).

3.2  Subject to rig availability and acquisition of all required permits and
     approvals, by Eni as operator of the East Breaks 112 Unit, on or before the
     1st day of December, 2005, Woodside, as designated Operator, will commence
     and thereafter diligently conduct operations to drill or cause to be
     drilled, an exploratory test well on East Breaks Block 157 at a surface and
     bottom hole location of X =1,077,753 feet and Y = 10,100,897 feet UTM to a
     minimum total depth of 12,000 feet MD / TVD ("Objective Depth") or such
     greater depth as may be mutually agreed by the Parties to evaluate Eni's
     Topaz prospect (hereinafter referred to as "Test Well"). Woodside and
     Ridgewood will each pay thirty-seven and five-tenths percent (37.5%), being
     a combined seventy-five percent (75%) of the estimated dry hole cost to
     drill the Test Well to Casing Point or through the plugging or temporary
     abandonment to earn an undivided twenty-five percent (25%) each, being a
     combined fifty percent (50%) operating rights (as described in 3.3) in the
     Leases. The costs to drill the Test Well (or its substitute), on which
     Woodside and Ridgewood bear a disproportionate share is limited to the
     actual drilling cost to reach Casing Point, or through plugging and
     abandoning if a dry hole, or $ 13.2 million dollars, whichever is less
     ("Cap Amount") based on 110% of Woodside's AFE which is defined in Article
     1.5 and attached as Exhibit "D". Thereafter, Woodside and Ridgewood will
     each pay their prorata twenty-five percent (25%) working interest shares of
     any well costs in excess of the Cap Amount and all other costs incurred
     from and after the Effective Date (including P&A cost) in accordance with
     the terms of the Offshore Operating Agreement attached as Exhibit "C".

3.3  Upon satisfaction by Woodside and Ridgewood of their obligations to drill
     the Test Well to Casing Point or spend up to 110 % of the AFE and subject
     to the further provisions of this Article III, Eni shall assign to Woodside
     and Ridgewood each an undivided twenty five percent (25%) operating rights
     interest in and to the Leases less and except the Excluded Area. The
     Subject Interests being assigned to Woodside and Ridgewood shall be subject
     only to their proportionate share of the Lessor's royalty and no other
     burdens. The assignment of Operating Rights, if approved by the MMS, shall
     be made without warranty of title except by, through and under Eni and will
     be on a mutually acceptable form.

     3.3.1 The Assignment shall become validated upon the following:

          A.   Woodside and Ridgewood receiving approval from the MMS of the
               separate transfer and assignment of operating rights by Eni to
               Woodside and Ridgewood of the Subject Interests in accordance
               with all laws, rules and regulations applicable thereto and


                                        3


          B.   Any assignment of Subject Interests or portion thereof that is
               not approved by the MMS will be handled in a manner that is
               mutually acceptable to the Parties to effect the transfer of the
               Subject Interests.

     Upon fulfillment of the foregoing conditions, the Assignments shall be
     effective retroactive to the Effective Date.

     3.3.2  Concurrently with Woodside and Ridgewood's execution of this
            Agreement Eni shall execute and deliver to Woodside the necessary
            "Designation of Operator" forms (MMS Form 1123) designating Woodside
            as the Operator of the Test Well subject to this Agreement, along
            with any other documents required to allow a Party to serve as
            Operator under the Offshore Operating Agreement or applicable
            regulations.

     3.3.3  The Assignments shall convey only the Subject Interests and ENI
            shall not assign, either its Geoscience Data or its Intellectual
            Property, as hereinafter defined.

          A.   Geoscience Data: All of Eni's ownership interest in any
               geological, geochemical or geophysical data, interpretations,
               maps, reports, geohazard surveys, or other information or
               derivatives of this information related to the Leases (the
               "Data");

          B.   Intellectual Property: All of Eni's ownership interest in any
               inventions, patents, copyrights, trademarks and other
               intellectual property related to the Leases.

          The provision of this Article 3.3.3 shall extend beyond the term of
          this Agreement.

     3.3.4 Woodside and Ridgewood agree to reimburse Eni for their proportionate
          share of all Leasehold maintenance costs, i.e. rentals and minimum
          royalties accruing under the terms of the Leases beginning as of the
          Effective Date of this Agreement for the next ensuing year and
          continuing, as to each such lease, for so long as the Lease remains
          subject to this Agreement.

3.4  If prior to reaching the Objective Depth for the Test Well, a decision is
     made in accordance with the terms of the Offshore Operating Agreement to
     abandon the well due to the existence of Gulf Coast Conditions as defined
     in the Offshore Operating Agreement, then any well (i) proposed in
     accordance with the Offshore Operating Agreement to test the same prospect
     as planned in the Test Well, and (ii) commenced within one hundred and
     twenty (120) days of the abandonment of the Test Well, shall be considered
     to be a substitute well for the Test Well. Each Party shall have the option
     (not obligation) to continue participation as per the Offshore Operating
     Agreement. All the provisions of this Agreement shall apply to such well
     with the same force and effect as to the abandoned well, provided, Woodside
     and Ridgewood's cost bearing share shall be reduced from seventy-five
     percent (75%), being 37.5% each to fifty percent (50%), being (50%), being
     25% percent each when the combined total costs of the Test Well and
     substitute well equal $13.2 million.


                                        4


3.5  Upon reaching Casing Point, each Party shall have the election as to their
     respective working interests (Eni 50%, Woodside 25%, Ridgewood 25% ) of
     either:

     (1)  conducting further operations in the Test Well, i.e. deepening,
          side-tracking, or completing the Test Well, in accordance with the
          priority for such operations set forth in the Offshore Operating
          Agreement, to be shared in the proportions of Eni 50%, Woodside 25%.
          Ridgewood 25%, or

     (2)  plugging and abandoning or temporarily abandoning of the Test Well to
          be shared in the proportion of Eni 25%, Woodside 37.50% and Ridgewood
          37.50% subject to the cap of Section 3.4.

     The notice and elections shall be made in accordance with the terms and
     conditions of Article 10.8 of the Offshore Operating Agreement attached as
     Exhibit "C".

3.6  A material default to drill the Test Well by Woodside and/or Ridgewood in
     performing the obligations as provided under this Article shall constitute
     a breach of this Agreement. A material default shall not give rise to Eni's
     right to terminate the contract unless the defaulting Party (ies) fails to
     cure such default within thirty (30) days of receipt from Eni of written
     notice stating the specifics of the default, or the defaulting Party's
     failure to commence the cure of such default and thereafter to prosecute
     such operations with due diligence to completion if the default cannot be
     cured within such time period.

3.7  In no event, shall any Party hereto be responsible to any other Party for
     consequential or punitive damages (including but not limited to loss of
     profit, business interruption and lost business opportunity).

3.8  The Leases and the Test Well drilled hereunder. shall be operated in
     accordance with the Offshore Operating Agreement which is attached hereto
     as Exhibit "C" and incorporated herein by reference. If any conflict exists
     between this Agreement and the Offshore Operating Agreement, this Agreement
     shall control. Eni shall remain the designated Operator of the Leases and
     Woodside shall, with Eni's assistance, attempt immediately to obtain all
     necessary governmental approvals and permits to drill the Test Well.


                                   ARTICLE IV.
                                   ASSIGNMENTS

4.1  No Party to this Agreement may assign all or any part of its interest in
     this Agreement without the prior written consent of the other Parties
     hereto, except that any Party may assign all or any part of its interest to
     an Affiliate upon giving prior notice to the other Parties and agreeing to
     remain liable for all of its obligations arising under this Agreement. Such
     granting of consent to a financially responsible party qualifying to hold
     leases with the MMS, shall not be unreasonably withheld. Notwithstanding
     the foregoing, Woodside shall have the right to assign to Explore Louisiana
     LLC all or part of its (Woodside's) interests in (i) this Well


                                        5


     Participation Agreement, (ii) the Offshore Operating Agreement, and (iii)
     the earned Subject Interests (whether those interest be Operating Rights
     Interests or other mutually acceptable interests).


                                   ARTICLE V.
                             RELATIONSHIP OF PARTIES

5.1  The rights, duties, obligations and liabilities of the Parties under this
     Agreement shall be individual, but limited initially to the percentage each
     party is to pay for the drilling of the Test Well and thereafter to its
     respective and proportionate share of the Subject Interests earned and
     either assigned or assignable to it, and not joint and several. It is not
     the intention of the Parties to create, nor shall this Agreement be deemed
     or construed to create a mining or other partnership, joint venture,
     association or trust. This Agreement shall not be deemed or construed to
     authorize any Party to act as an agent, servant or employee for any other
     Party for any purpose whatsoever and in their relations with each other
     under this Agreement, the Parties shall not be considered fiduciaries.


                                   ARTICLE VI.
                                 CONFIDENTIALITY

6.1  All data and information acquired, interpreted, developed or disclosed
     pursuant to this Agreement shall be held confidential by all Parties in
     accordance with the confidentiality provisions of the Offshore Operating
     Agreement, Exhibit C. All other confidentiality provisions and/or
     agreements between the Parties being that certain Confidentiality Agreement
     between Eni and Woodside dated March. 22, 2005 and that certain
     Confidentiality Agreement between Eni and Ridgewood dated May 2, 2005,
     covering Subject Interests shall terminate and be superceded by the
     confidentiality provision of Exhibit "C".


                                  ARTICLE VII.
                                     NOTICES

7.1  All notices authorized or required between the Parties shall be addressed
     and effective when delivered to such persons as designated below. Each
     Party shall have the right to change its address at any time and/or
     designate that copies of all such notices be directed to another person at
     another address, by giving notice thereof to the other Parties:


                             Eni Petroleum Exploration Co Inc.
                             1201 Louisiana
                             Suite 3500
                             Houston, Texas 77002
                             Attn: Charles C. Barnes
                             Phone: 713.393.6107
                             Fax:   713.393.6208


                                        6


                             Woodside Energy (USA) Inc.
                             Sage Plaza, 5151 San Felipe,
                             Suite 1200
                             Attn: Leon Hirsch
                             Houston, Texas 77056
                             Phone: 713.413,0021
                             Fax:   713.963.8868

                             Ridgewood Energy Corporation
                             11700 Old Katy Road, Suite 280
                             Houston, Texas 77079
                             Attn: Greg Tabor
                             Phone: 281.293.8449
                             Fax:   281.293.7705



                                  ARTICLE VIII.
                                 APPLICABLE LAW

8.1  This Agreement shall be governed by, construed, interpreted and enforced in
     accordance with the substantive laws of the State of Texas, to the
     exclusion of any conflicts of law rules that would refer the matter to the
     laws of another jurisdiction. Venue for any litigation arising from this
     Agreement shall be in Harris County, Texas.



                                   ARTICLE IX.
                            AREA OF MUTUAL INTEREST

9.1  In the event any party acquires an interest in an oil and gas lease
     covering the Offshore Blocks described on Exhibit "A" (hereinafer referred
     to as "AMI Blocks"), or acquires any right to acquire an interest in an oil
     and gas lease covering the AMI Blocks or any portion thereof ("Acquiring
     Party") within the term of this Agreement, then the other Parties shall
     each have the right, but not the obligation, to acquire from the Acquiring
     Party it's non promoted share (Eni 50%, Woodside 25% and Ridgewood 25%) of
     the interest and/or right acquired. The other Parties shall each be
     notified in writing by the Acquiring Party within fifteen (15) days of such
     acquisition and shall have thirty (30) days after receipt of such notice to
     advise Acquiring Party whether or not it elects to acquire it's share of
     the interest and/or right acquired. In the event that a Party fails to give
     such responsive notice within the aforesaid thirty (30) day period, such
     failure shall be conclusively deemed to be an election not to acquire a
     share of the interest or rights acquired by Acquiring Party. Said notice is
     to include the actual acquisition costs if any, and other consideration
     offered (which shall include the monetary equivalent in U.S. Dollars based
     upon reasonable market value of any consideration other than cash) if any,
     and any obligations relative to the acquisition. If a Party elects to
     exercise its right under this Agreement, the consideration owed by the


                                       7


     Party shall equal it's share of the actual costs and/or obligations paid
     and/or assumed for the acquired interest.


                                   ARTICLE X.
                               GENERAL PROVISIONS

10.1 Subject to the limitations on transfer contained in Article V., this
     Agreement shall inure to the benefit of and be binding upon the successors
     and assigns of the Parties.


10.2 No waiver by a Party of any one or more breaches or defaults by another
     party in the performance of this Agreement shall operate or be construed as
     a waiver of any future breach(s) or default(s) by the same Party, whether
     of a like or of a different character. Except as expressly provided in this
     Agreement no Party shall be deemed to have waived, released or modified any
     of its rights under this Agreement unless such Party has expressly stated,
     in writing, that it does waive, release or modify such right.

10.3 If and for so long as any provision of this agreement shall be deemed to be
     judged invalid for any reason whatsoever, such invalidity shall not affect
     the validity or operation of any other provision of this Agreement except
     only so far as shall be necessary to give effect to the construction of
     such invalidity, and any such invalid provision shall be deemed severed
     from this Agreement without affecting the validity of the Agreement.

10.4 There shall be no modification of this Agreement except by written consent
     of all Parties.

10.5 Reference to the singular includes a reference to the plural and vice
     versa.

10.6 The topical headings used in this Agreement are for convenience only and
     shall not be construed as having any substantive significance or as
     indicating that all of the provisions of this Agreement relating to any
     topic are to be found in any Article.

10.7 This Agreement is the entire agreement of the Parties with respect to the
     subject matter contained herein and supersedes all prior understandings and
     negotiations of the Parties.

IN WITNESS of their agreement each Party has caused its duly authorized
representative to sign this instrument on the date indicated below such
representative's signature. This Agreement may be executed in one or more
counterpart copies and shall be effective as of the Effective Date first above
written.


                                        8


ENI PETROLEUM EXPLORATION CO. INC.          RIDGEWOOD ENERGY CORPORATION


By:   /s/ Charles C. Barnes                 By: /s/ W. Greg Tabor

Name: Charles C. Barnes                     Name: W. Greg Tabor

Title: Attorney-in-Fact                     Title: Executive VP

Date:  8-30-05                              Date:   9-2-05


WOODSIDE ENERGY (USA) INC.



By:  /s/ David M. McCubbin

Name: David M. McCubbin

Title: President

Date:  9/7/05







                                        9




                                   Exhibit "A"
    Attached to and made a part of that certain Participation Agreement among
       Eni Petroleum Exploration Co. Inc., Woodside Energy (USA) Inc. and
            Ridgewood Energy Corporation dated effective July 1, 2005


I.   Description of Leases
     ---------------------

     a.   Oil and Gas Lease bearing Serial No. OCS-G 08195, effective November
          1, 1985 between the United States of America, as Lessor, and Agip
          Petroleum Co.. Inc. and Union Texas Petroleum Corporation, as Lessees,
          covering approximately 4847.75 acres, being all of Block 112, East
          Breaks, as shown on OCS Official Protraction Diagram NG 15-1.

                                                                  Net Revenue
          Current Owners                    Working Interest        Interest
          --------------                    ----------------        --------

          Eni Petroleum Exploration Co. Inc.     100.00%            83.3333%

     b.   Oil and Gas Lease bearing Serial No. OCS-G 11412, effective October 1,
          1989 between the United States of America, as Lessor, and Agip
          Petroleum Co. Inc. and Union Texas Petroleum Corporation, as Lessees,
          covering approximately 5760.00 acres, being all of Block 157, East
          Breaks, as shown on OCS Official Protraction Diagram NG 15-1.

                                                                  Net Revenue
          Current Owners                    Working Interest        Interest
          --------------                    ----------------        --------

          Eni Petroleum Exploration Co. Inc.     100.00%            83.3333%

II.  Depth Limitations within the Leases described in I. above derived from
     Participating Areas attributable to the East Breaks 112 Unit, OCS Unit No.
     754391005.

     a.   OCS-G 01895 East Breaks Block 112:
          -----------------------------------
          This Participation Agreement is limited to those rights in East Breaks
          Block 112 that are located within the Well Participating Area as
          defined herein under Article 1.16. Within said Well Participating Area
          the depths excluded from this Participation Agreement consist of the
          stratigraphic equivalent of the intervals depicted on the electric log
          of the East Breaks 112 No. 3 Well as the "E" Sand Reservoir as further
          depicted on Exhibit "B" and defined in Exhibit "B-1".

     b.   OCS-G 11.412, East Breaks Block 157:
          ------------------------------------
          This Participation Agreement is limited to those rights in East Breaks
          Block 157 that are located within the Well Participating Area as
          defined herein under Article 1.16. Within said Well Participating Area
          the depths excluded from this Participation Agreement consist of 1)
          the stratigraphic equivalent of the interval depicted on the electric
          log of the East Breaks 157 No. 2 Well as the "A" Sand Reservoir as
          further depicted on Exhibit "B" and defined in Exhibit "B-l", and 2)
          the stratigraphic equivalent of the intervals depicted on the electric
          log of the East Breaks 157 No. 1 Well as the "B" and "C" Sand
          Reservoir as further depicted on Exhibit "B" and defined in Exhibit
          "B-1". The "B" and "C" reservoirs will require an expansion of the


                                       10




          Unit Participating Area for the East Breaks 157 Lease (Proposed
          Revised Unit Outline) resulting in the exclusion of the additional
          outline area covering the acreage(s) as depicted on Exhibit "B" and
          further on Exhibit "B-1" to be added as the Proposed Revised Unit
          Outline.

The Excluded Area and Reservoirs Associated with the East Breaks 112 Unit are
further depicted on the map and the Schedule of Depth reservations attached
hereto as Exhibits "B" and "B-1".


III. AREA OF MUTUAL INTEREST (AMI) BLOCKS REFERRED TO IN ARTICLE IX. OF THE
     PARTICIPATION AGREEMENT ARE AS FOLLOWS:
     ---------------------------------------



AREA/BLOCK                LEASE NO.          OWNER             EXPIRATION
- -------------------------------------------------------------------------------
East Breaks 113           OCS-G 22278        Unocal            09/30/2005
- --------------------------------------------------------------------------------
East Breaks 114           OPEN                  -                   -
- --------------------------------------------------------------------------------






                                       11


                                   Exhibit "B"
     Attached to and made part of that certain Participation Agreement among
       Eni Petroleum Exploration Co. Inc., Woodside Energy (USA) Inc. and
           Ridgewood Energy Corporation dated Effective July 1, 2005


                           EAST BREAKS BLOCK 112 UNIT
                       PARTICIPATING AREAS AND APPLICABLE
                             RESERVOIR OUTLINES FOR
                      PARTIAL BLOCKS EAST BREAKS 112 & 157


                                 [MAP OMITTED]






                                  EXHIBIT "B-1"
    Attached to and made a part of that certain Participation Agreement among
       Eni Petroleum Exploration Co. Inc., Woodside Energy (USA) Inc. and
           Ridgewood Energy Corporation dated Effective July 1, 2005



EAST BREAKS 112 UNIT DEPTH EXCLUSIONS:



E sand Reservoir in Agip EB 112 #3:     Top     7321'MD 6122'TVD    -6050' SS
                                        Base    7379'MD 6168'TVD    -6096' SS




A sand Reservoir in Agip EB 157 #2:     Top     4916'MD & TVD       -4843' SS
                                        Base    5045'MD & TVD       -4972' SS




B sand Reservoir in Agip EB 157 #1:     Top     5520'MD & TVD       -5436' SS
                                        Base    5696'MD & TVD       -5612' SS




C sand Reservoir in Agip EB 157 #1      Top     6187'MD & TVD       -6103' SS
                                        Base    6398'MD & TVD       -6304' SS

EX-10.6

                                                                    EXHIBIT 10.6

                             PARTICIPATION AGREEMENT
                           EUGENE ISLAND 357 PROSPECT
                               OFFSHORE, LOUISIANA

     This Participation Agreement ("Agreement") is made and entered into
effective as of the 1st day of July, 2005 by and between Walter Oil & Gas
Corporation ("Walter"), and Ridgewood Energy Corporation ("Ridgewood").

                                    RECITALS

     WHEREAS, Walter has identified a prospect on Eugene Island block 357 and
has acquired Oil & Gas Lease OCS-G 23884 dated June 1, 2002 covering block 357
from the United States of America; and,

     WHEREAS, Walter plans to drill or participate in the drilling of an initial
test well on Eugene Island block 357, OCS-G 23884; and,

     WHEREAS, Walter has offered to Ridgewood the opportunity to participate in
the drilling of the initial test well and to acquire a 25% working interest in
block 357, OCS-G23884, less and except the NE/4 of the lease from the surface to
11,500' subsea (hereafter "Lease"), and Ridgewood has accepted Walter's offer
all in accordance with the terms set forth herein.

     NOW, THEREFORE, in consideration of the mutual covenants and agreement
herein contained, the parties hereto agree as follows:


                                    SECTION I
                                    ---------
                                  Initial Costs

1.01 Within ten (10) days of Ridgewood's execution of this Agreement, Ridgewood
     agrees to pay Walter $141,203.00 (which represents Ridgewood's 25% share of
     the Lease bonus, rental and shallow hazard survey costs incurred by
     Walter).

                                   SECTION II
                                   ----------
                                Initial Test Well

2.01 Walter plans to participate in the drilling of an initial test well on the
     Lease. The initial test well will be drilled from a surface location of
     approximately 5,625' FSL and 6,610' FEL of the Lease and drilled to a depth
     of 15,800' TVD (hereinafter "Initial Test Well"). As consideration for the
     opportunity to earn a twenty-five percent (25%) working interest in the
     Lease, Ridgewood shall bear Thirty-Three and One-Third percent (33.33%) of
     the costs to drill the Initial Test Well to casing point and through
     plugging and abandonment, if the Initial Test Well is not saved for
     production. This disproportionate cost sharing obligation shall be referred
     to as the "Promote." The Promote will be applicable to the dry hole costs
     of the Initial Test Well and will be limited to 110% of the Initial Test
     Well's estimated dry hole cost as noted in the attached AFE. The Promote
     will also apply to any substitute well or sidetrack of the Initial Test
     Well until Walter has received 110% of the original AFE dry hole costs.
     Concurrent with Ridgewood's execution of this Agreement, Ridgewood will be
     deemed to have approved the attached AFE and well plan.




2.02 Subject only to rig availability and the ability to obtain the required
     governmental permits, Walter and Ridgewood agree that if the Initial Test
     Well is not spudded on or before December 1, 2005 ("Commencement Date"),
     and such date has not been extended by Ridgewood, then this Agreement shall
     ipso facto terminate. Within 10 days of such termination, Walter shall
     reimburse Ridgewood for any payments it received in accordance with
     Paragraph 1.01 of this Agreement and Ridgewood shall submit assignments to
     Walter re-conveying Ridgewood's 25% working interest in the Lease
     previously received from Walter, which assignment shall be free and clear
     of any liens, charges, or lease burdens, overriding royalty interest, or
     any other encumbrance created by Ridgewood. For clarification purposes
     only, there shall be no other penalty(ies) assessable to either party
     hereto for failure of the Initial Test Well to be spudded on or before the
     Commencement Date.

2.03 It is understood and agreed that Newfield Exploration Company ("Newfield")
     will have a 50% working interest in the Lease and Initial Test Well and
     will be the designated operator.


                                   SECTION III
                                   -----------
                       Assignment and Assumption of Rights

3.01 Within ten (10) days from receipt of Ridgewood's payment described in 1.01
     above, Walter shall assign to Ridgewood Twenty Five percent (25%) operating
     rights interest in the Lease. The interest assigned to Ridgewood in the
     Lease shall be subject to the existing royalty burden and a 2.25% of 8/8ths
     overriding royalty interest ("ORRI") to be reserved by Walter, all
     proportionately reduced to Ridgewood's assigned interest. Walter represents
     to Ridgewood that total Lease burdens created by, through and under Walter
     as of the effective date of this Agreement, including lessor's royalty, are
     no greater than 18.917% (of 8/8ths). The form of Assignment is attached
     hereto as Exhibit "A."

                                   SECTION IV
                                   ----------
                               Operating Agreement

4.01 Contemporaneous with the execution of this Agreement, the parties hereto
     agree to execute a mutually agreeable operating agreement ("JOA"), naming
     Newfield operator of the Lease. Both parties hereto acknowledge that the
     JOA is a three-party agreement also requiring Newfield's signature. All
     operations on the Initial Test Well and any and all subsequent operations
     on the Lease shall be conducted in accordance with the terms and provisions
     of the JOA. If there are any conflicts between this Agreement and the JOA,
     the terms and provisions of this Agreement shall prevail and govern.

                                    SECTION V
                                    ---------
                                     Notices

5.01 All notices, requests or demands to be given under this Agreement shall be
     in writing and governed and directed to the representatives as specified
     below:

     Ridgewood Energy Corporation           Walter Oil & Gas Corporation
     11700 Old Katy Rd., Suite 280          1100 Louisiana Street, Suite 200
     Houston, Texas 77079                   Houston, TX 77002
     Attn: Mr. W. Greg Tabor                Attn: Mr. Ron Wilson
     Phone: 281-293-8449                    Phone: 713-659-1221
     Fax:   281-293-7705                    Fax:   713-756-1177




                                   SECTION VI
                                   ----------
                      GOVERNING LAW AND BREACH OF CONTRACT

6.01 This Agreement shall be governed by the laws of the State of Texas except
     where the Maritime Laws of the United States of America are applicable. In
     the event that any dispute results in formal legal action, venue shall be
     appropriate in the federal or state courts of Harris County, Texas.

6.02 In the event of a breach of this Agreement by any party hereto, the non
     breaching party shall be entitled to all remedies available at law or
     equity, including but not limited to, specific performance, monetary
     damages and injunctive relief.


                                   SECTION VII
                                   -----------
                                  MISCELLANEOUS


7.01 Walter shall provide Ridgewood with full and complete access to Walter's
     files, records and data, so that Ridgewood may perform its due diligence
     review of Walter's acquisition, ownership and obligations associated with
     the Lease. Additionally, Walter shall provide Ridgewood with access to its
     technical data associated with the Lease, including seismic, maps, well
     data and geological data, subject however, to all confidentiality and data
     licensing restrictions.

7.02 A term, provision, covenant, representation, warranty, or condition of this
     Agreement may be waived only by written instrument executed by the party
     waiving compliance. The failure or delay of any party in the enforcement or
     exercise of the rights granted under this Agreement shall not constitute a
     waiver of said rights nor shall it be considered as a basis for estoppel.

7.03 This Agreement, together with all of its exhibits, is intended by the
     parties to be a complete and final statement of the agreement of the
     parties with respect to the subject matter hereof, and supersedes any prior
     oral or written statements or agreements between the parties hereto.

7.04 The terms and provisions hereof shall be binding upon and inure to the
     benefit of Walter and Ridgewood, and their respective heirs, legal
     representatives, successors and assigns, and shall be covenants running
     with the Lease.




     IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
executed as of the date first set forth above.


WITNESSES
                                         WALTER OIL & GAS CORPORATION

/s/
- ------------------------------           /s/ Ron A. Wilson
                                         ------------------------------
/s/ Melissa Coronado                         Ron A. Wilson
- ------------------------------               Vice President
Melissa Coronado



                                         RIDGEWOOD ENERGY CORPORATION

/s/ Ken Webb
- ------------------------------           /s/ W. Greg Taber
Ken Webb                                 ------------------------------
                                             W. Greg Taber
/s/ Randy Bennett                            Executive Vice President
- ------------------------------
Randy Bennett













                                   EXHIBIT "A"

       Attached to and made a part of that certain Participation Agreement
      dated July 1, 2005 between Walter Oil & Gas Corporation and Ridgewood
                               Energy Corporation.



ASSIGNMENT OF OPERATING RIGHTS TO OIL AND GAS LEASE

                                                               OCS-G 23884
UNITED STATES OF AMERICA    ss.

OUTER CONTINENTAL SHELF     ss.

OFFSHORE LOUISIANA          ss.



     For and in consideration of the sum of One Hundred Dollars ($100.00) and
other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged, Walter Oil & Gas Corporation, a Texas Corporation, whose
mailing address is 1100 Louisiana, Suite 200, Houston, Texas 77002 (hereinafter
called "Assignor"), does SELL, TRANSFER, ASSIGN, SET OVER AND CONVEY unto
Ridgewood Energy Corporation, a_________________________________ Company, whose
mailing address is 11700 Old Katy Rd., Suite 280, Houston, TX 77079,
(hereinafter called "Assignee"), a 25.0000% operating rights interest in and to
the following federal oil and gas Lease ("Lease"):

     Oil and Gas Lease No. OCS-G 23884 dated June 1, 2002 from the United States
     of America, as Lessor, to Walter Oil & Gas Corporation, as Lessee,
     covering Eugene Island Area, Block 357, OCS Leasing Map, Louisiana Map No.
     4A, containing 4999.88 acres;

     LESS AND EXCEPT the Northeast Quarter (NE/4) of the Lease from the surface
     down to 11,500' subsea (hereinafter referred to as ("Assigned Interest").


Subject to the matters set forth herein, this Assignment is made without
warranty of title, express, implied or statutory, even for return of any
consideration paid therefor; provided only that Assignor warrants that it has
not heretofore granted or conveyed to any other party any interest in or any
lien or encumbrance on the interest being assigned hereunder in the Lease except
as described herein.




WITH RESPECT TO ANY PERSONALTY OR CHATTELS CONVEYED HEREBY, ASSIGNOR HEREBY
NEGATES AND DISCLAIMS THE IMPLIED WARRANTY OF MERCHANTABILITY AND THE IMPLIED
WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE AND ANY IMPLIED WARRANTY OF
CONFORMITY TO MODELS OR SAMPLES OF MODELS. ASSIGNEE AND ASSIGNOR AGREE THAT, TO
THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF
CERTAIN WARRANTIES CONTAINED IN THIS INSTRUMENT ARE "CONSPICUOUS" DISCLAIMERS.


     TO HAVE AND TO HOLD the Assigned Interests hereby conveyed, together with
all and singular rights and appurtenances thereto in anyway belonging unto
Assignee, its successors and assigns.

     This Assignment is made by Assignor and accepted by Assignee subject to the
following:

1}   the terms, provisions and conditions of the Lease and any limitation on or
     contained in the Lease;

2)   That certain Participation Agreement dated July 1, 2005 by and between
     Assignor and Assignee and covering the Assigned Interest;

3)   That certain Offshore Operating Agreement dated July 1, 2005 by and between
     Newfield Exploration Company, as Operator, and Assignor and Assignee, as
     Non-Operators, and covering the Assigned Interest;

4)   Assignor reserves unto itself, and retains an overriding royalty interest
     equal to 2.25% of eight-eights (8/8ths) in and to all hydrocarbons that are
     produced, saved, and sold from the Lease. Said overriding royalty shall be
     free of all costs of any kind whatsoever including but not limited to costs
     associated with exploration, development, production or operating, but
     shall bear its proportionate share of severance and production taxes unless
     provided otherwise in the Lease. Said overriding royalty shall be
     calculated and paid or delivered to Assignee in the same manner as provided
     in the Lease affected thereby for the calculation and payment or delivery
     of royalties therein reserved to the Lessor.

     a) It is understood that the overriding royalty interest reserved
     hereinabove is an 8/8ths number and that Assignee shall bear its
     proportionate share of such overriding royalty interest based on the
     Assigned Interest herein.

4)   The terms and conditions of this Assignment shall extend to and be binding
     upon the successors and assigns of the parties.




     IN WITNESS WHEREOF, this Assignment of Operating Rights Interest is
executed and effective this ____ day of _________, 2005.




WITNESSES:                                        ASSIGNOR:

                                         Walter Oil & Gas Corporation


______________________________
______________________________
                                         By:______________________________
                                             Ron A. Wilson
                                             Vice President




WITNESSES:                                        ASSIGNEE:

                                         Ridgewood Energy Corporation


______________________________
______________________________
                                         By:______________________________
                                             W. Greg Tabor
                                             Executive Vice President

STATE OF TEXAS

COUNTY OF HARRIS

     On this _____ day of _________, 2005 before me appeared W. Greg Tabor, to
me personally known, who, being by me duly sworn, did say that he is the
Executive Vice President of Ridgewood Energy Corporation, and that the foregoing
instrument was signed on behalf of said company, and said W. Greg Tabor
acknowledged said instrument to be the free act and deed of said corporation.


                                             ______________________________
                                                      NOTARY PUBLIC

My Commission Expires __________________.




STATE OF TEXAS

COUNTY OF HARRIS

     On this _____ day of ________, 2005 before me appeared Ron A. Wilson, to me
personally known, who, being by me duly sworn, did say that he is the Vice
President of Walter Oil & Gas Corporation, and that the foregoing instrument was
signed on behalf of said partnership, and said Ron A. Wilson acknowledged said
instrument to be the free act and deed of said corporation.


                                             ______________________________
                                                      NOTARY PUBLIC

My Commission Expires __________________.

EX-10.7

                                                                    EXHIBIT 10.7

[DEVON LOGO]
- --------------------------------------------------------------------------------
                                                   Devon Energy Corporation
                                                   Devon Energy Tower
                                                   1200 Smith Street, Suite 3300
                                                   Houston, Texas 77002

Christopher N. Claeys
Senior Staf Land Representative
Direct Line:   (713) 286-5862
Fax:           (713) 286-5737
Email: chris.claeys@dvn.com

May 3, 2006                                       VIA FACSIMILE & CERTIFIED MAIL
                                                  ------------------------------

Ridgewood Energy Corporation
Attention: Randy Bennett
11700 Old Katy Road, Suite 280
Houston, Texas 77079

Re:     Participation Agreement dated September 15, 2005
        Mercury Prospect (OCS-G 3332 A-10 Well)
        Eugene Island Area,  South  Addition,  Block 337 (OCS-G 3332)
        Offshore, Louisiana

Gentlemen;

By letter dated October 13, 2005, and subsequent communications between
representatives of Ridgewood Energy Corporation ("Ridgewood") and Devon Energy
Production Company, L.P. ("Devon"), Ridgewood has been made aware and kept
apprised of the status and progress of Devon's efforts to recover from the major
scheduling disruptions caused by Hurricane Rita in September 2005 with respect
to the activities necessary to cause the drilling of the Eugene Island Area,
South Addition, Block 337 OCS-G 3332 A-10 well. This letter is written to update
Ridgewood on recent developments affecting the drilling schedule and costs, and
to seek Ridgewood's agreement to continue its participation in the drilling of
the OCS-G 3332 A-10 well covering the Mercury prospect.

As you know, the rig Devon intends to utilize for this drilling operation, the
Rowan Alaska, is currently on location at our mutual "Barber" prospect well in
Eugene Island Block 334. At present, Devon's drilling schedule plans call for
moving the Rowan Alaska to the Mercury location after drilling and completion
operations at the Barber and "Chopin" prospects Eugene Island 334 "D" platform
("El 334 "D") location are finalized. The repairs to the Eugene Island 337 "A"
platform ("El 337 "A") are progressing, and are anticipated to be completed in
time to proceed with the drilling of the Mercury prospect immediately after
conclusion of operations at El 334 "D". Devon's current schedule for El 337 "A"
repairs indicate that commencement of operations for the OCS-G 3332 A-10 well
should occur in the late July 2006 to early August 2006 timeframe, subject to
any additional delays, including but not limited to, weather, rig and equipment
availability, the well operations being conducted at the El 334 "D" location,
and repairs to El 337 "A".

By letter dated April 24, 2006 Devon advised Ridgewood that Devon deemed the
captioned Participation Agreement (the "Agreement") to have expired due to the
parties failure to mutually agree upon the terms of Ridgewood's continued
participation in the OCS-G 3332 A-10 well. Upon further conversation with
Ridgewood, and acknowledging both parties' continued desire to pursue drilling
the OCS-G 332 A-10 well, Devon hereby retracts and rescinds its April 24, 2006
letter. Ridgewood and Devon further agree and affirm that the Agreement has been
and is still in effect, having been extended and preserved by force majeure
events, specifically, post-hurricane delays caused by platform and equipment
damages, and the lack of available rigs, crews, materials and equipment to
conduct repairs and drilling operations, and each party reaffirms its respective
obligations as set forth in the Agreement.




However, due to the changes in costs and scheduling subsequent to the execution
of the Agreement, Devon would prefer that the parties arrive at an agreed upon
continuance of our mutual contractual obligations. To this end, Devon is
enclosing for Ridgewood's information a copy of the recently updated Authority
for Expenditure (AFE) generated for the drilling and evaluation of the OCS-G
3332 A-10 well. As can be seen, the overall costs for this project have
escalated. The total estimated dry hole costs are now approximately
$21,221,300.00. Additionally, Devon wishes to advise Ridgewood that the drilling
contract for the Rowan Alaska will escalate from its current $160,000.00 per day
rate as reflected in the attached AFE, to $165,000.00 per day, effective
September 1, 2006 through December 1, 2006. After December 1, 2006 the Rowan
Alaska drilling contract is subject to further escalation at then current market
rates. The attached AFE represents the best estimate of the dry hole costs that
Ridgewood can reasonably expect to bear in the event Ridgewood elects to
continue to participate in the Mercury prospect. Therefore, Devon proposes that
Ridgewood and Devon agree upon the following:

     1.   The parties agree to honor the intent of the Agreement with respect to
          the promote limit, being an amount equal to 120% of the originally
          estimated OCS-G 3332 A-10 well dry hole costs of $11,957,000.00 per
          the AFE attached as Exhibit "B" to the Agreement, and agree to limit
          Ridgewood's promoted interest expenditures to 44% of $14,348,400.00
          (120% x $11,957,000.00 = $14,348,400.00) or a net $6,313,296.00 to
          Ridgewood, or upon reaching Contract Depth as defined in the
          Agreement, whichever event shall occur first.

     2.   Ridgewood agrees to bear its unpromoted 33% share of the total OCS-G
          3332 A-10 well costs above a gross cost of $14,348,400.00. Ridgewood
          also agrees to bear its proportionate share of any increase in the day
          rate for the Rowan Alaska that will occur on September 1, 2006 and
          December 1, 2006, should operations on the OCS-G 3332 A-10 well be in
          progress on and after said dates.

     3.   Except as herein amended, the Agreement shall remain in full force and
          effect as presently written.

While the revised estimated costs to drill the OCS-G 3332 A-10 well represent a
change to the overall project economics, Devon still views the prospect as a
viable drilling opportunity and recommends proceeding with the drilling of the
OCS-G 3332 A-10 well after mutually agreeing to extend the Contract Spud Date,
as defined in the Agreement, to on or before October 1, 2006. Devon recognizes
that Ridgewood may or may not agree with its assessment. Therefore, should
Ridgewood elect to not continue its participation in the Mercury prospect, Devon
recommends that the parties mutually agree to terminate the Agreement with no
further liability to either party, other than the continuing obligations
contained in Article 26 Confidential Data, of the Agreement.

Please indicate as to whether or not Ridgewood desires to continue to
participate in the Mercury prospect and agrees to extend the Agreement by
executing in the space provided for the appropriate option and returning one
original of this letter before 4:00 PM on Monday, May 8, 2006. Should Ridgewood
not respond to this letter by May 8, 2006, Devon shall deem that Ridgewood no
longer desires to participate in the Mercury prospect, and that Ridgewood agrees
that the Agreement has terminated and is of no further force or effect except
for the continuing obligations of Article 26.

Should you have any questions or wish to discuss this letter, please contact
Chris Claeys at (713) 286 5862.

Very truly yours,

Devon Energy Production Company, L.P.

/s/ Christopher N. Claeys
Christopher N. Claeys


Enclosure (FYI Only copy of revised DVN AFE No. 119917)




Option No. 1
- ------------

Ridgewood Energy Corporation hereby agrees to the following:

     1)   The Agreement is in full force and effect between the parties hereto;
     2)   To bear its promoted interest share of the OCS-G 3332 A-10 well costs
          to a limit of 120% of $11,957,000.00 (being $14,348,400.00), or a net
          $6,313,296.00 to Ridgewood of the estimated dry hole costs for such
          well unless Contract Depth is achieved prior to a gross well cost of
          $14,348,400.00 has been expended, and thereafter bear 33% of total
          well costs.
     3)   The Contract Spud Date referenced in Article 2 of the Agreement is
          hereby amended from December 31, 2005 to on or about October 1, 2006.
     4)   Except as amended herein, the Agreement remains in full force and
          effect as presently written.

Agreed to and accepted this 4th day of May, 2006.

Ridgewood Energy Corporation



By: /s/ Randy Bennett
Name:   Randy Bennett
Title:  Land Manager



Option No. 2
- ------------

Ridgewood Energy Corporation hereby declares that it has no further desire to
participate in the Mercury prospect well (OCS-G 3332 A-10) and hereby mutually
agrees to terminate the Agreement with no further liability to either party
hereto, provided, however, that Article 26 of the Agreement shall continue in
effect. Ridgewood further agrees that it has no further claim, option, right or
obligation to participate in the drilling of, production from, revenues
generated by, or costs and expenses incurred for such well, whether said well is
drilled by Devon or any other party, either now or in the future.

Agreed to and accepted this _____ day of May, 2006.

Ridgewood Energy Corporation



By:   ___________________________
Name: ___________________________
Title:___________________________

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Robert E. Swanson, certify that:

1.   I have reviewed this annual report on Form 10-K of The Ridgewood Energy M Fund, LLC;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	April 10, 2007
/s/	ROBERT E. SWANSON
Name:	Robert E. Swanson
Title:	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kathleen P. McSherry, certify that:

1.I have reviewed this annual report on Form 10-K of The Ridgewood Energy M Fund, LLC;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	April 10, 2007
/s/	KATHLEEN P. MCSHERRY
Name:	Kathleen P. McSherry
Title:	Senior Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

EX-32

Exhibit 32

CERTIFICATIONS OF CEO AND CFO PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Annual Report on Form 10-K of The Ridgewood Energy M Fund, LLC (the “Fund”) for the fiscal year ended December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof, (the “Report”), each of the undersigned officers of the Fund hereby certifies, pursuant to 18 U.S.C. (section) 1350, as adopted pursuant to (section) 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Fund.

Dated:	April 10, 2007			RIDGEWOOD ENERGY M FUND, LLC
		By:	/s/	ROBERT E. SWANSON
			Name:	Robert E. Swanson
			Title:	President and Chief Executive Officer
				(Principal Executive Officer)
Dated:	April 10, 2007
		By:	/s/	KATHLEEN P. MCSHERRY
			Name:	Kathleen P. McSherry
			Title:	Senior Vice President and Chief Financial Officer
				(Principal Financial and Accounting Officer)

A signed original of this written statement or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to Ridgewood Energy M Fund, LLC and will be retained by Ridgewood Energy M Fund, LLC and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this report or as a separate disclosure document.