Ridgewood Energy Q Fund (RDWQS) 10-K 2007 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2007

or

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

For the transition period from _____ to _____

Commission File No. 000-51927

RIDGEWOOD ENERGY Q FUND, LLC
(Exact name of registrant as specified in its charter)

Delaware	84-1689138
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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.
Yeso Nox

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yeso Nox

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. Yesx Noo

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.x

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

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	x
(Do not check if a smaller reporting company)

Indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Nox

There is no market for the shares. At March 27, 2008 there are 830.5577 shares outstanding.

RIDGEWOOD ENERGY Q FUND
2007 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	9
	ITEM 1B	UNRESOLVED STAFF COMMENTS	9
	ITEM 2	PROPERTIES	9
	ITEM 3	LEGAL PROCEEDINGS	9
	ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	9
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	9
	ITEM 6	SELECTED FINANCIAL DATA	11
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	16
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	16
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	16
	ITEM 9A	CONTROLS AND PROCEDURES	16
	ITEM 9B	OTHER INFORMATION	17
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	17
	ITEM 11	EXECUTIVE COMPENSATION	18
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS	19
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	19
	ITEM 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	19
PART IV
	ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	20

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy Q Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections, statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. Examples of such events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

AVAILABLE INFORMATION

The Fund’s shares of LLC membership interest (the “Shares”) are registered 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 United States Securities and Exchange Commission (the “SEC”) on Form 10-K, quarterly reports on Form 10-Q and, from time to time, current reports on Form 8-K. Moreover, Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) 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.

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 filed with 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. Information may be obtained 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.

1

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company formed on August 16, 2005 to acquire interests primarily in oil and natural gas projects located in the U.S. waters of the Gulf of Mexico. Ridgewood Energy Corporation, 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 initiated its private placement offering on September 6, 2005, selling whole and fractional shares of membership interest 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 agreement (the “LLC agreement”) and applicable federal and state securities laws. The offering was terminated on December 30, 2005. As of March 27, 2008, the Fund had 1,335 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.

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 SEC, commission fees, taxes, outside legal, accounting and consulting fees, litigation expenses and other expenses, if any, properly payable by us. The Fund is required to reimburse the Manager for all such Fund expenses paid by them.

As compensation for their management services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole expenses incurred by the Fund. The Fund paid the Manager for its management services fees totaling $2.6 million and $3.1 million for the years ended December 31, 2007 and 2006, respectively. Additionally, the Manager receives a 15% interest in the cash distributions made by the Fund. The Manager was paid $2.0 million and $0.9 million in distributions in 2007 and 2006, respectively.

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 properties. 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 Mineral Management Services (“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 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.

2

The Fund tries to focus on projects that have significant reserve potential that are projected to have the shortest time period from its investment to first production. The Fund does not operate these projects, and although it has a vote, it is not in control of the schedule pursuant to which its projects are developed and completed. 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 for the Fund to examine and review such reserve estimates and seismic information on its behalf.

Manager’s Investment Committee and Investment Criteria

The New Jersey office has five executives on the investment committee, three of whom have been working together at Ridgewood Energy for over twenty years. The Houston office, which opened in 2003, has four executives on the investment committee who provide operational, scientific and technical oil and 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 gas exploration; (ii) targeting projects that have or are expected to have partners that also have significant resources and experience in oil and 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 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.

Properties

The Fund owns working interests and has participated in the drilling of four wells, one that was determined to be a dry-hole, one that is currently drilling or scheduled to drill, and two that have been determined to have proved reserves.

Lease Block	Working Interest			Operator		Off-shore Location in Gulf of Mexico		Target Depth (Feet)			Drilling Risk (in thousands)		Total Spent through 12/31/2007 (in thousands)
											(a)
Currently Drilling
Main Pass 30 Well #3		45.00	%		Chevron		Louisiana		12,500		$	12,600	$	10,839
Proved Property
Main Pass 30 Well #1		45.00	%		Chevron		Louisiana		12,500			N/A	$	18,127
Main Pass 30 Well #2		45.00	%		Chevron		Louisiana		12,500			N/A	$	12,324
Facilities		45.00	%		Chevron		Louisiana			N/A		N/A	$	4,031
Dry Holes (b)
Main Pass 221/222		35.00	%		Chevron		Louisiana		19,700			N/A	$	18,702

(a)	Drilling risk represents the prospective estimated dry-hole costs, leasehold costs or sunk costs including promote for project participation per authorization for expenditure adjusted for current operating conditions (i.e. projected costs overruns, increased drilling rates, etc).
(b)	Dry-hole costs represent wells that have been drilled but do not have commercially productive oil and/or natural gas reservoirs.

Main Pass 30

The Fund acquired a 45% working interest from the operator, Chevron U.S.A., Inc. (“Chevron”). When fully developed, this project is expected to have a total of five wells.

Wells #1 and #2

The first well in the Main Pass 30 project, (“Main Pass 30 well #1) was put in production in June 2006 and is utilizing an existing Chevron production platform and pipeline. In return for the use of this infrastructure, the Fund pays 15 cents per one thousand cubic feet (“MCF”) as a processing fee for production. During 2007, Main Pass 30 well #1 experienced lower volumes than expected, particularly of oil production, due to a minor mechanical issue. The volumes will continue to be lower than prior year until all five wells are developed. At that point, the reserves and the production volumes will be re-evaluated to determine whether the Operator should perform additional work to accelerate production. The total cost of this well was $18.1 million.

3

The second well in the Main Pass 30 project (“Main Pass 30 well #2”) began drilling in May 2007 and was determined to be a commercial discovery during the second quarter of 2007. Production commenced on this property in late-July 2007. The total cost of this well was $12.3 million.

Well #3

The third well in the Main Pass 30 project (“Main Pass 30 well #3”) began drilling in October 2007. The budget for this property is estimated at $15.3 million. The Fund expected drilling results for this project in December 2007, however, during drilling, Chevron encountered a mechanical problem, or underground “blowout”, caused by a small pocket of gas. As a result, Chevron released the rig and suspended drilling while it modified its drilling plan to sidetrack the well. Drilling is currently expected to resume in July 2008. The Fund and Chevron are evaluating their options related to the economic prospects of the Main Pass 30 project. The Fund has obtained estimates indicating its costs related to the sidetrack would be $12.7 million. The Fund carries control of well insurance, which will cover the anticipated cost of the sidetrack. The Fund has incurred $10.8 million of capital expenditures related to Main Pass 30 well #3. In the event the Fund elects not to proceed with the sidetrack, the Fund may not file an insurance claim, or, the claim may be greatly reduced. At this time, the amount of this reduced claim has not been estimated. It is expected that the Fund and project partners will make a decision regarding the status of this project and claim during the second quarter 2008.

Facilities

During 2007, the Fund completed its pipeline upgrade, which will be used by Main Pass 30 well #2, #3, #4 and #5. The total cost of the facilities upgrade was $4.0 million.

Dry Hole

Main Pass 221/222

The Fund acquired a 35% working interest from the Operator, Chevron. The well began drilling on November 3, 2005 and reached its total depth on January 24, 2006. The well was perforated on April 9, 2006 and flowed at non-commercial rates. On April 10, 2006 the decision was made to plug and abandon the well. Dry-hole costs including plug and abandonment expenses incurred by the Fund for the years ended December 31, 2007 and 2006 were $0.4 million and $10.5 million, respectively.

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. See further discussion under the heading “Regulation”.

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.

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 for shallow-water projects, and a 12.5% royalty to the MMS for deepwater projects. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is 83.33% for shallow-water projects and 87.5% for deepwater projects 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.

4

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 $10.19 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. With respect to the Fund’s other projects that are currently drilling, the Fund will determine once completed if the project will be able to claim relief under the Royalty Relief Rule.

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

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

Oil and Natural Gas Agreements

The Fund has entered into a short-term month to month agreement with a third-party marketer, who is currently marketing and selling the Fund’s proportionate share of oil and natural gas to the public market. The Fund is receiving market prices for such oil and natural gas. The Manager believes that it is likely that oil and natural gas from the Fund’s future projects will have access to pipeline transportation and can be marketed in a similar fashion. Upon completion, production from future projects may use existing capacity on existing pipelines. As mentioned above under the heading “Manager’s Investment Committee and Investment Criteria”, as part of the Manager’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 “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 Chevron.

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.

5

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 $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 gas that would result in more of the Fund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is 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.

The Fund’s drilling, production and transportation operations are subject to seasonal risks, such as hurricanes, that may affect the Fund’s 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 had past experiences that indicate the typical interruption in operations resulting from a hurricane that does not result in significant damage may be approximately three to seven days. The Manager has experienced the range of possible interruptions in operations due to hurricanes from as little as no damage and no interruptions to significant damage and extended interruptions. However, it is 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 revenue.

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 that 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.

6

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 lease acquisition 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 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, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled and the plugging and abandoning of projects are also subject to regulations.

          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, 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 the Fund’s operations and interests.

7

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

          Sales and Transportation of Natural Gas/Oil

The Fund sells the Fund’s proportionate share of oil and natural gas to the market and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, 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 the Fund’s 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 it shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that is caused by the Fund’s projects.

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

          The Oil Pollution Act. The Oil Pollution Act of 1990, as amended (“OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez 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 that poses a substantial threat of a discharge could be liable for certain specified damages resulting from a discharge of oil, including clean-up and remediation, loss of subsistence use of natural resources, real or personal property damages, as well as certain public and private damages. A responsible party includes a lessee of an offshore facility.

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages. In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier, the Fund has not been required to make any such showing to the MMS 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.

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

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

8

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

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

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

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

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.

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

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

None.

PART II

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

Market Price of Shares, Distributions and Related Shareholder Matters

There is currently no established public trading market for the Shares. As of the date of this filing, there were 1,335 holders shareholders of record of the Fund.

During the years ended December 31, 2007 and 2006, the Fund has paid distributions totaling $13.2 million and $6.2 million, respectively.

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 shareholders,

• 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 shareholders.

9

Available cash determines what amounts in cash the Fund will be able to distribute in cash to shareholders. 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 and other amounts received out of the ordinary course of business), but excluding dispositions of temporary investments of the Fund.

          “Available Cash from Temporary Investments” is cash from short-term investments (i.e. U.S. Treasury securities, 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 shareholders 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.

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.

10

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.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

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

Overview of the Fund’s Business

The Fund is an independent oil and natural gas producer. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders through participation in oil and natural gas exploration and development projects in the Gulf of Mexico. Since inception in August 2005, the Fund has acquired an interest in two offshore projects in the Main Pass area of the Gulf of Mexico. Chevron is the partner and operator of both projects. The Main Pass 221 well was determined to be a dry-hole in April 2006 and the costs related to this property were expensed in the accompanying statements of operations. The Main Pass 30 project has the potential for five wells. The first and second wells began producing in June 2006 and July 2007, respectively. The third well began drilling in October 2007, and in December 2007 was suspended due to a drilling problem. See also Item 1. “Business” for a additional discussion of this property.

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 was paid a one time investment fee (4.5%) for the evaluation of projects on the Fund’s behalf and is paid an annual management fee (2.5% of capital contributions, net of cumulative dry-hole costs), payable monthly, for ongoing administrative and advisory duties as well as reimbursement of expenses. The Manager also participates in distributions. See also Item 1. “Business”.

Critical Accounting Estimates

The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with U.S. generally accepted accounting principles, or GAAP. In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of 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. 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. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of the Fund’s significant accounting policies.

Accounting for Exploration and Development Costs

Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and 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 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.

11

Proved Reserves

Annually, the Fund engages an independent petroleum engineer, Ryder Scott Company L.P., to perform a comprehensive study of the Fund’s producing properties and dependent upon timing of discoveries, certain successful properties, to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving 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 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 the Fund’s unproved 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 unproved property balance will be evaluated within 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 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 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 for the years ended December 31, 2007 and 2006 should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Schedules” contained in this Annual Report.

12

	Year ended December 31,
	2007			2006
Revenue
Oil and gas revenue	$	13,159		$	10,479
Expenses
Depletion and amortization		8,912			4,229
Dry-hole costs		366			10,530
Management fees to affiliate		2,616			3,076
Lease operating expense		828			299
Other operating expenses		119			2
General and administrative expenses		936			570
Total expenses		13,777			18,706
Loss from operations		(618	)		(8,227	)
Other income
Interest income		3,055			3,417
Net income (loss)	$	2,437		$	(4,810	)

Year Ended December 31, 2007 compared to Year Ended December 31, 2006

Oil and Gas Revenue. The Fund currently has two wells producing, Main Pass 30 well #1 and well #2, which came onto production in June 2006 and July 2007, respectively. Oil and gas revenue for the year ended December 31, 2007 was $13.2 million, a $2.7 million increase from the year ended December 31, 2006.

The Main Pass 30 wells produced approximately 29 thousand barrels of oil during the year ended December 31, 2007. During the year ended December 31, 2006, oil production was approximately 32 thousand barrels. Oil prices averaged approximately $77 during the year ended December 31, 2007 compared to $64 per barrel during the year ended December 31, 2006.

Natural gas production for the year ended December 31, 2007 was approximately 1.5 million mcf compared to 1.3 million mcf, for the year ended December 31, 2006. During the year ended December 31, 2007, natural gas prices averaged approximately $7.30 per mcf compared to $6.62 per mcf during the year ended December 31, 2006.

The volume variances for both oil and natural gas are attributable to the onset of production of Main Pass 30 well #2, partially offset by the decrease in Main Pass 30 well #1 production due to a minor mechanical issue, which will not be remediated until all five wells are developed. See further discussion in Item 1. - Business.

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. For the years ended December 31, 2007 and 2006 the Fund recorded depletion and amortization of $8.9 million and $4.2 million, respectively. The increase of $4.7 million was the result of the onset of production for a second well in the Main Pass 30 project and additional infrastructure necessary to support increased production from wells 2-5.

Dry-hole Costs. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. The following table summarizes dry-hole costs inclusive of plug and abandonment costs for the years ended December 31, 2007 and 2006:

	Year ended December 31,
	2007		2006
	(in thousands)
Main Pass 221	$	366	$	10,530

13

Management Fee. For the years ended December 31, 2007 and 2006, the Fund incurred management fees totaling $2.6 million and $3.1 million, respectively. Management fees are charged by the Manager to cover expenses associated with overhead and 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 of $0.5 million in 2007 was attributable to a policy change by the Manager, reducing the calculation of the fee for the amount of cumulative dry-hole expenses incurred by the Fund.

Lease Operating Expenses.Lease operating expenses represent the day-to-day cost of operating and maintaining wells and related facilities. For the years ended December 31, 2007 and 2006, lease operating expenses were $0.8 million and $0.3 million, respectively. This increase is predominately the result of the onset of production of Main Pass 30 well #2, which commenced production in July 2007 as well as a full year of operation of the Main Pass 30 well #1, which began producing in June 2006.

Other Operating Expense. Other operating expenses for the year ended December 31, 2007 were $0.1 million related to geological costs incurred for Main Pass 30 and accretion expense. Other operating expenses were $2 thousand for the year ended December 31, 2006 related to accretion expense for Main Pass 30.

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

	Year ended December 31,
	2007		2006
	(in thousands)
Insurance	$	652	$	298
Accounting and legal fees		200		158
Trust fees and other		84		114
	$	936	$	570

Insurance expense represents premiums related to well control insurance, which increases as drilling activity increases, and directors and officers liability policy, which is allocated by the Manager to the Fund based on capital raised by the Fund to total capital raised by all oil and natural gas funds managed by the Manager. Accounting and legal fees represent annual audit and tax preparation fees, quarterly reviews and filing fees of the Fund. Trust fees represent bank fees associated with the management of the Fund’s short-term investment portfolio in US Treasury securities and have decreased in 2007 due to a reduction in investment activity as the Fund’s cash is spent on oil and gas properties.

Interest Income. Interest income is earned on money market accounts and US Treasury securities. For the years ended December 31, 2007 and 2006, interest income totaled $3.1 million and $3.4 million, respectively. During the year ended December 31, 2007, interest income decreased as a result of a reduction in cash and investment balances available partially offset by an increase in average interest rates.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, 2007 were $10.1 million, primarily related to cash receipts for oil and natural gas production of $13.0 million and interest income received of $1.7 million. Partially offsetting these cash inflows were management fees of $2.6 million, lease and other operating expenses of $0.9 million, general and administrative expenses of $0.9 million, and unfavorable working capital of $0.1 million.

Cash flows provided by operating activities for the year ended December 31, 2006 were $6.0 million, primarily related to cash receipts for oil and natural gas production of $9.1 million and $2.4 million for interest income received. Offsetting these cash inflows were $3.1 million of payments for management fees, $1.6 million for investment fees and $0.6 million and $0.3 million of general and administrative and lease operating expenses, respectively. Investment fees of $1.6 million paid to the Manager were accrued at December 31, 2005.

14

Investing Cash Flows

Cash flows used in investing activities for the year ended December 31, 2007 were $37.5 million. The Fund made $55.2 million in investments in marketable securities, inclusive of salvage fund, and received proceeds of $37.1 million related to the maturity of such securities. The Fund made capital expenditures totaling $19.5 million.

Cash flows used in investing activities for the year ended December 31, 2006 were $35.9 million. The Fund made $53.0 million in investments in marketable securities and received proceeds of $35.8 million related to the maturity of such securities. The Fund made capital expenditures totaling $17.6 million and contributions of $1.0 million towards its salvage fund.

Financing Cash Flows

Cash flows used in financing activities for the year ended December 31, 2007 were $13.2 million, related to distributions to shareholders and the Manager.

Cash flows used in financing activities for the year ended December 31, 2006 were $7.3 million, primarily related to distributions of $6.2 million and $4.1 million for payment of syndication costs, partially offset by $3.0 million of cash receipts from shareholders for subscriptions receivable.

Estimated Capital Expenditures

The Fund has entered into multiple offshore 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, 2007, the Fund has commitments related to authorizations for expenditures totaling $0.2 million for properties. If the properties were to be successful, the Fund would make additional expenditures totaling $31.2 million related to the completion of these properties.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its 2008 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. The annual fee, payable monthly, is equal to 2.5% of total capital contributed by shareholders, net of cumulative dry-hole costs incurred.

With respect to the payment of management fees, prior to the production of the Fund’s projects, 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 expected to be sufficient 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 all of the management fee that may have been paid out of capital contributions.

Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and Fund operations.

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. 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 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, 2007 and 2006 and does not anticipate the use of such arrangements in the future.

15

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, 2007 and 2006 other than those discussed in “Estimated Capital Expenditures” above.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 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 December 21, 2004 and filed its Registration Statement on Form 10 in April 2006; thus, the year ended December 31, 2005 was the Fund’s first audited reporting period. Perelson Weiner’s audit report on the financial statements of the Fund for the period December 21, 2004 (inception) through December 31, 2005 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

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures pursuant to the Exchange Act Rule 13a-15(e) as of December 31, 2007. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

Management’s Report on Internal Control over Financial Reporting

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

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

16

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2007. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) inInternal Control — Integrated Framework.

Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2007, the Fund’s internal control over financial reporting is effective.

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

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as Manager. The Manager has very broad authority, including the authority to appoint executive officers of the Fund. Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 2007 are as follows:

Name, Age and Position with Registrant	Officer Since
Robert E. Swanson, 60
President and Chief Executive Officer	1982
W. Greg Tabor, 47
Executive Vice President and
Director of Business Development	2004
Robert L. Gold, 49
Executive Vice President	1987
Kathleen P. McSherry, 42
Executive Vice President and
Chief Financial Officer	2000
Daniel V. Gulino, 47
Senior Vice President and General Counsel	2003
Adrien Doherty, 55
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 Power and Ridgewood Capital, affiliates of Ridgewood Energy. Mr. Swanson has been President and registered principal of Ridgewood Securities 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.

17

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.

Robert L. Gold has served as the Executive Vice President of Ridgewood Energy since 1987. 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 Executive 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.

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.

Code of Ethics

The Manager of the Fund has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager of the Fund grants any waiver, including any implicit waiver, from a provision of the code to any the Manager’s executive officers, the Fund will disclose the nature of such amendment or waiver on our website or in a current report on Form 8-K. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 947 Linwood Avenue, Ridgewood, New Jersey 07450, ATTN: General Counsel.

Board of Directors and Board Committees

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

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, 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, 2007, 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.

18

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 March 27, 2008 (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.

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 830.5577 Shares outstanding at March 27, 2008. 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 Executive Officer	3.0000	*
Executive officers as a group (1)	3.0000	*

* Represents less than one percent.

(1) Includes shares owned by the spouse of Mr. Swanson or one of his trusts.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The Manager is paid an annual management fee, payable monthly, equal to 2.5% of total capital contributions, net of cumulative dry-hole costs incurred, 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. For the years ended December 31, 2007 and 2006 the Fund paid the Manager management fees totaling $2.6 million and $3.1 million, respectively. For the years ended December 31, 2007 and 2006 the Manager received distributions from the Fund of $2.0 million and $0.9 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.

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. At December 31, 2007 and 2006, there were no such amounts payable or receivable.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees and services rendered by Deloitte & Touche LLP for the years ended December 31, 2007 and 2006:

	Year ended December 31,
	2007		2006
	(in thousands)
Audit Fees (1)	$	125	$	125
Tax fees (2)		—		34
Total	$	125	$	159

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

19

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) (1) Financial Statements

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

(a) (2) Financial Statement Schedules

None.

Exhibits
23.1	Consent of Ryder Scott Company, L.P.
31.1	Certification of Robert E. Swanson, Chief Executive Officer, pursuant to Securities Exchange Act Rule 13a-14(a).
31.2	Certification of Kathleen P. McSherry, Chief Financial Officer, 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 Company and Kathleen P. McSherry, Chief Financial Officer of the Company.

20

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2007 and 2006	F-3
Statements of Operations for the years ended December 31, 2007 and 2006	F-4
Statements of Changes in Members’ Capital for the years ended December 31, 2007 and 2006	F-5
Statements of Cash Flows for the years ended December 31, 2007 and 2006	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information – Information about Oil and Natural Gas Producing Activities – Unaudited	F-12

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Manager of Ridgewood Energy Q Fund, LLC:

We have audited the accompanying balance sheets of Ridgewood Energy Q Fund LLC (the “Fund”) as of December 31, 2007 and 2006, the related statements of operations, changes in members’ capital and cash flows for the years ended December 31, 2007 and 2006. 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 Q Fund, LLC as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years ended December 31, 2007 and 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

March 27, 2008

Parsippany, New Jersey

F-2

RIDGEWOOD ENERGY Q FUND, LLC
BALANCE SHEETS
(in thousands, except share data)

	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	8,427		$	49,055
Short-term investment in marketable securities		37,711			18,197
Production receivable		1,556			1,369
Other current assets		102			245
Total current assets		47,796			68,866
Salvage fund		1,091			1,042
Oil and gas properties:
Unproved properties		10,839			450
Proved properties		34,657			18,506
Less: accumulated depletion and amortization		(13,141	)		(4,229	)
Total oil and gas properties		32,355			14,727
Total assets	$	81,242		$	84,635
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Due to operators	$	7,433		$	83
Accrued expenses payable		69			109
Total current liabilities		7,502			192
Asset retirement obligations		184			79
Total liabilities		7,686			271
Commitments and contingencies (Note 8)
Members’ capital:
Manager:
Distributions		(2,912	)		(925	)
Retained earnings		1,968			703
Manager’s total		(944	)		(222	)
Shareholders:
Capital contributions (1,335 shares authorized; 830.5577 issued and outstanding)		123,037			123,037
Syndication costs		(14,070	)		(14,070	)
Distributions		(16,500	)		(5,242	)
Accumulated deficit		(17,967	)		(19,139	)
Shareholders’ total		74,500			84,586
Total members’ capital		73,556			84,364
Total liabilities and members’ capital	$	81,242		$	84,635

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

F-3

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

	Year ended December 31,
	2007			2006
Revenue
Oil and gas revenue	$	13,159		$	10,479
Expenses
Depletion and amortization		8,912			4,229
Dry-hole costs		366			10,530
Management fees to affiliate (Note 6)		2,616			3,076
Lease operating expense		828			299
Other operating expenses		119			2
General and administrative expenses		936			570
Total expenses		13,777			18,706
Loss from operations		(618	)		(8,227	)
Other income
Interest income		3,055			3,417
Net income (loss)	$	2,437		$	(4,810	)
Manager Interest
Net income	$	1,265		$	883
Shareholder Interest
Net income (loss)	$	1,172		$	(5,693	)
Net income (loss) per share	$	1,411		$	(6,854	)

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

F-4

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

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2005		830.5577	$	(180	)	$	92,557		$	92,377
Collection of subscription receivable		—		—			2,964			2,964
Distributions		—		(925	)		(5,242	)		(6,167	)
Net income (loss)		—		883			(5,693	)		(4,810	)
Balances, December 31, 2006		830.5577		(222	)		84,586			84,364
Distributions		—		(1,987	)		(11,258	)		(13,245	)
Net income		—		1,265			1,172			2,437
Balances, December 31, 2007		830.5577	$	(944	)	$	74,500		$	73,556

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

F-5

RIDGEWOOD ENERGY Q FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)

	Year ended December 31,
	2007			2006
Cash flows from operating activities
Net income (loss)	$	2,437		$	(4,810	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion and amortization		8,912			4,229
Dry-hole costs		366			10,530
Accretion expense		6			2
Interest earned on marketable securities		(1,517	)		(970	)
Changes in assets and liabilities:
Increase in production receivable		(187	)		(1,369	)
Decrease in other current assets		143			—
Decrease in due to affiliate		—			(1,570	)
Increase in due to operator		28			57
Decrease in accrued expenses payable		(40	)		(103	)
Net cash provided by operating activities		10,148			5,996
Cash flows from investing activities
Capital expenditures for oil and gas properties		(19,485	)		(17,596	)
Salvage fund investments		(49	)		(1,042	)
Proceeds from the sale of marketable securities		37,134			35,773
Investment in marketable securities		(55,131	)		(53,000	)
Net cash used in investing activities		(37,531	)		(35,865	)
Cash flows from financing activities
Collection of subscriptions receivable		—			2,964
Distributions		(13,245	)		(6,167	)
Syndication costs paid		—			(4,113	)
Net cash used in financing activities		(13,245	)		(7,316	)
Net decrease in cash and cash equivalents		(40,628	)		(37,185	)
Cash and cash equivalents, beginning of period		49,055			86,240
Cash and cash equivalents, end of period	$	8,427		$	49,055
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to dry-hole costs and proved properties	$	—		$	11,787

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

F-6

RIDGEWOOD ENERGY Q FUND, LLC
NOTES TO FINANCIAL STATEMENTS

1. Organization and Purpose

The Ridgewood Energy Q Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 16, 2005 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of September 6, 2005 by and among Ridgewood Energy Corporation (the “Manager”), and the shareholders of the Fund. Although the date of formation is August 16, 2005, the Fund did not begin business activities until September 6, 2005 when it began its private offering of shares of LLC membership interest (the “Shares”). There were no business activities prior to September 6, 2005.

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 Manager performs (or arranges for the performance of) the management and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 6 and 8.

2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 and asset retirement obligations. Actual results may differ from those estimates.

Cash and Cash Equivalents

All highly liquid investments with maturities when purchased of three months or less are considered as cash and cash equivalents. At times, bank deposits may be in excess of federal insured limits. At December 31, 2007 and 2006, bank balances inclusive of the salvage fund exceeded federally insured limits by $5.2 million and $30.9 million, respectively. The Fund maintains bank deposits with accredited financial institutions to mitigate such risk. Cash and cash equivalents of $3.0 million and $18.0 million were invested in three month US Treasury Notes at December 31, 2007 and 2006, respectively.

Investments in Marketable Securities

At times the Fund may purchase short-term investments comprised of US Treasury Bills and Notes with maturities greater than three months that are considered held-to-maturity investments. Held-to-maturity securities are those investments that the Fund has the ability and intent to hold to maturity. Held-to-maturity investments are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate fair value. Interest income is accrued as earned. At December 31, 2007, the Fund had held-to-maturity investments, inclusive of the salvage fund, totaling $38.8 million that matured in January 2008.

Salvage Fund

Pursuant to the Fund’s LLC Agreement, 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 withdrawals from the salvage fund.

Oil and Natural Gas Properties

Investments in oil and natural gas properties are operated by unaffiliated entities (the “Operators”) that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable Operating Agreements with working interest owners.

F-7

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 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 natural 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, 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, taking into consideration the amount of any recorded impairment if the property had been assessed for impairment. The Manager does not currently intend 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, 2007 amounts recorded in due to operators totaling $7.3 million, related to capital expenditures for oil and gas property. These liabilities were paid in the first quarter of 2008.

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.

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.

	2007		2006
	(in thousands)
Balance - January 1,	$	79	$	—
Liabilities incurred		99		192
Liabilities settled		—		(115	)
Accretion expense		6		2
Balance - December 31,	$	184	$	79

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

Syndication Costs

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

Revenue Recognition and Production Receivable

Oil and natural gas sales are recognized and a production receivable is recorded 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).

The volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas the Fund is entitled to. 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, and a payable to other working interest owners for volumes oversold by the Fund. At December 31, 2007 and 2006, there were no material oil or natural gas balancing arrangements between the Fund and other working interest owners.

F-8

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 flows attributable 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. No impairments have been recorded in the Fund since inception.

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.

Income Taxes

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

Income and Expense Allocation

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

3. Recent Accounting Standards

In February 2007, the Financial Accounting Standards Board (the “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 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. The adoption of SFAS No. 159 will not have a material impact on its financials. The Fund did not elect to measure existing assets and liabilities at fair value on the date of adoption.

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 had originally been effective for financial statements issued for fiscal years beginning after November 15, 2007, however the FASB has agreed on a one year deferral for all nonfinancial assets and liabilities. The Fund believes this guidance will not have a material impact on the financial statements.

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.

The following table reflects the net changes in unproved properties for the years ended December 31, 2007 and 2006. As of December 31, 2007 and 2006, the Fund had no capitalized exploratory well costs greater than one year.

F-9

	2007			2006
	(in thousands)
Balance -January 1,	$	450		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		20,080			18,956
Reclassifications to proved properties based on the determination of proved reserves		(9,691	)		(18,506	)
Capitalized exploratory well costs charged to dry hole costs		—			—
Balance - December 31,	$	10,839		$	450

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 are detailed in the table below.

		Year ended December 31,
	2007		2006
	(in thousands)
Main Pass 221	$	366	$	10,530

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 will 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.

During the years ended December 31, 2007 and 2006, the Fund made distributions of $11.3 million and $5.2 million, respectively to shareholders and $2.0 million and $0.9 million, respectively to the Manager.

6. Related Parties

The LLC 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, net of cumulative dry-hole expenses. Management fees of $2.6 million and $3.1 million were incurred and paid for the years ended December 31, 2007 and 2006, respectively.

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. There were no such amounts payable or receivable at December 31, 2007 or 2006.

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

At December 31, 2007 and 2006, the carrying value of cash and cash equivalents, short-term investments in marketable securities, salvage fund, production receivable and accrued expenses approximate fair value.

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8. Commitments and Contingencies

Capital Commitments

The Fund has entered into multiple offshore 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, 2007, the Fund had commitments related to authorizations for expenditures totaling $0.2 million for properties. If the properties were to be successful, the Fund would make additional expenditures totaling $31.2 million related to the completion of these properties.

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. At December 31, 2007 and 2006, 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 that Fund.

Main Pass 30 Well #3

The third well in the Main Pass 30 project (“Main Pass 30 well #3”) began drilling in October 2007. The budget for this property is estimated at $15.3 million. The Fund expected drilling results for this project in December 2007, however, during drilling, the project operator, Chevron U.S.A. Inc., (“Chevron”) encountered a mechanical problem, or underground “blowout”, caused by a small pocket of gas. As a result, Chevron released the rig and suspended drilling while it modified its drilling plan to sidetrack the well. Drilling is currently expected to resume in July 2008. The Fund and Chevron are evaluating their options related to the economic prospects of the Main Pass 30 project. The Fund has obtained estimates indicating its costs related to the sidetrack would be $12.7 million. The Fund carries control of well insurance, which will cover the anticipated cost of the sidetrack. The Fund has incurred $10.8 million of capital expenditures related to Main Pass 30 well #3. In the event the Fund elects not to proceed with the sidetrack, the Fund may not file an insurance claim, or, the claim may be greatly reduced. At this time, the amount of this reduced claim has not been estimated. It is expected that the Fund and project partners will make a decision regarding the status of this project and claim during the second quarter 2008.

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Supplemental Financial Information – Information about Oil and Natural Gas Producing Activities - Unaudited

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 Louisiana in the Gulf of Mexico.

Table I - Capitalized Costs Related to Oil and Gas Producing Activities

	December 31,
	2007			2006
	(in thousands)
Unproved oil and gas properties	$	10,839		$	450
Proved oil and gas properties		34,657			18,506
Total oil and gas properties		45,496			18,956
Accumulated depletion and amortization		(13,141	)		(4,229	)
Oil and gas properties, net	$	32,355		$	14,727

Table II - Costs Incurred in Exploration, Property Acquisitions and Development

	Year ended December 31,
	2007		2006
	(in thousands)
Exploratory drilling costs - capitalized	$	26,540	$	8,171
Exploratory drilling costs - expensed		366		9,528
Geological costs		113		—
	$	27,019	$	17,699

Table III - Reserve Quantity Information

Oil and natural gas reserves of the Fund have been estimated by Ryder Scott Company, L.P. for the years ended December 31, 2007 and 2006. The reserve estimates for December 31, 2007 and 2006 were based on estimated future reserves as of December 31, 2007 and September 30, 2006, respectively provided by Ryder Scott Company, L.P. These reserve disclosures 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. There are no proved undeveloped reserves at December 31, 2007 and 2006.

	December 31, 2007 United States Oil (BBLS) Gas (MCF)					December 31, 2006 United States Oil (BBLS) Gas (MCF)
Proved developed reserves:
Beginning of year		44,899		2,719,677			—		—
Discoveries		36,473		1,903,333			76,241		4,008,335
Revisions of previous estimates (1)		(12,243	)	(311,696	)		—		—
Production		(28,778	)	(1,496,314	)		(31,342	)	(1,288,658	)
End of year		40,351		2,815,000			44,899		2,719,677

(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.

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

Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. 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.

	December 31,
	2007			2006
	(inthousands)
Future estimated revenues	$	23,966		$	18,071
Future estimated production costs		(1,724	)		(414	)
Future estimated development costs		(3,150	)		—
Future net cash flows		19,092			17,657
10% annual discount for estimated timing of cash flows		(1,867	)		(1,976	)
Standardized measure of discounted future estimated net cash flows	$	17,225		$	15,681

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

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

	Year ended December 31,
	2007			2006
	(in thousands)
Standardized measure beginning of the year	$	15,681		$	—
Sales of oil and gas production, net of production costs		(12,331	)		(10,180	)
Net changes in prices and production costs		4,356			—
Extensions, discoveries, and improved recovery and techniques, less related costs		14,617			25,077
Revisions of previous reserve quantities estimate		(2,505	)		—
Accretion of discount		1,193			784
Timing and other		(3,786	)		—
Standardized measure end of the year	$	17,225		$	15,681

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

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SIGNATURES

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

	RIDGEWOOD ENERGY Q FUND, LLC
Date: March 27, 2008	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson
		Chief Executive Officer
		(Principal Executive Officer)

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

	Signature	Capacity	Date
/s/	ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)	March 27, 2008
Robert E. Swanson
/s/	KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer	March 27, 2008
		(Principal Accounting Officer)
Kathleen P. McSherry
/s/	ROBERT E. SWANSON	Chief Executive Officer of the Manager	March 27, 2008
Robert E. Swanson