Ridgewood Energy U Fund 10-K 2007 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007

or

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

For the transition period from _____ to _____

Commission File No. 000-52583

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

Delaware	20-5464059
(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)

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

There is no market for the Shares. As of February 20, 2008 there are 486.4825 Shares outstanding.

RIDGEWOOD ENERGY U FUND, LLC
2007 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	4
	ITEM 1A	RISK FACTORS	12
	ITEM 1B	UNRESOLVED STAFF COMMENTS	12
	ITEM 2	PROPERTIES	13
	ITEM 3	LEGAL PROCEEDINGS	13
	ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	13
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	13
	ITEM 6	SELECTED FINANCIAL DATA	14
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	15
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	20
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	20
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	20
	ITEM 9A	CONTROLS AND PROCEDURES	20
	ITEM 9B	OTHER INFORMATION	21
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	21
	ITEM 11	EXECUTIVE COMPENSATION	23
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS	23
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	23
	ITEM 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	24
PART IV
	ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	24

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FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) of the Ridgewood Energy U Fund, LLC (the “Fund”) and the documents that are 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”) 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, drilling 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 by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. A copy of any such filings will be provided free of charge to any shareholder upon written request to the Fund at its business address 947 Linwood Avenue, Ridgewood, New Jersey 07450, ATTN: General Counsel.

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PART I

ITEM 1. BUSINESS

Overview

Ridgewood Energy U Fund, LLC (the “Fund”) (an exploratory stage enterprise) is a Delaware limited liability company and was formed on August 28, 2006 to acquire interests primarily in oil and natural gas projects located in the U.S. waters of the Gulf of Mexico. Ridgewood Energy Corporation (“Ridgewood Energy” or the “Manager”), a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management and control of Fund operations.

The Fund initiated its private placement offering on October 1, 2006, selling whole and fractional shares of membership interests (the “Shares”) primarily at $150 thousand per share. There is no public market for these shares and one is not likely to develop. In addition, the shares are subject to severe restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The offering was terminated on January 19, 2007. The Fund raised approximately $72.4 million, and after payments totaling $11.8 million in offering fees, commissions and investment fees, the Fund had approximately $60.6 million for investments and operating expenses. As of February 19, 2008, the Fund had 930 shareholders.

Manager

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

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

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

As compensation for their management services, the Manager is entitled to an annual management fee, which is equal to 2.5% of the total shareholder capital contributions net of cumulative dry-hole expenses incurred by the Fund, payable monthly. The Manager received from the Fund for its management services a total of approximately $1.5 million, $0.3 million and $1.8 million for the year ended December 31, 2007, the period August 28, 2006 (Inception) through December 31, 2006, and the period August 28, 2006 (Inception) through December 31, 2007, respectively. In addition, the Manager is also entitled to a 15% interest in the cash distributions. There have been no cash distributions to the Manager paid through December 31, 2007.

Business Strategy

The Fund’s primary investment objective is to generate cash flow from the acquisition, exploration, production and sale of crude oil and natural gas from oil and natural gas projects. The Fund has invested and participates in exploration and production projects located in the waters of the Gulf of Mexico offshore Texas, Louisiana and Alabama on the Outer Continental Shelf (the “OCS”). These activities are governed by the Outer Continental Shelf Lands Act (the “OCSLA”) enacted in 1953 and administered by the Mineral Management Services (the “MMS”).

The Fund generally looks to invest in projects that have been proposed by larger independent oil and natural gas companies seeking to minimize their risks by selling a portion of their interest in a project. These investments may require the Fund to pay a disproportionate part of the drilling costs on the exploratory well of a project than its ownership interest would otherwise require. This is called a promote and is common in the oil and natural gas exploration industry. In addition, notwithstanding the sale of an interest to the Fund, the seller may retain a right for some period of time to payments from sales of oil and natural gas production from a well or project. This is called an overriding interest, which is also relatively common in this industry. Notwithstanding any such promote or overriding interest, the Fund has tried to invest in projects that it believes contain sufficient commercial quantities of oil or natural gas and which are near (i) existing oil or natural gas gathering and processing infrastructure and (ii) developed markets where the Fund can sell its oil or natural gas.

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The Fund tries to focus on projects that have significant reserve potential and which are projected to have the shortest time period from investment to first production. The Fund does not operate these projects, and although it has a vote, it is not in control of the schedule pursuant to which its projects are developed and completed. Moreover, when performing due diligence with respect to a project, the Fund must rely on the independent reservoir engineers who are hired and paid, in most cases, by the operator. The Fund does engage certain consultants to examine and review such reserve estimates and seismic information on its behalf.

Manager’s Investment Committee and Investment Criteria

The New Jersey office has four executives on the investment committee, three of whom have been working together at Ridgewood Energy for over twenty years. The Houston office, which opened in 2003, has five 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 three wells, two of which have been determined to be dry holes, and one that is currently drilling.

Working Interest

Off-shore Location in Gulf of Mexico

Target Depth

Total Spent Through December 31, 2007

Lease Block

Operator

Drilling Risk (b)

Status

(Feet)

(in thousands)

Walker Ridge 155

3.5

%

Anadarko

Louisiana

32,000

$

8,120

$

7,542

Drilling

South Timbalier 135/136 (a)

15.0

%

Chevron

Louisiana

N/A

N/A

$

10,295

Dry: January 2007

Eugene Island 255/256 (a)

15.0

%

Helis

Louisiana

N/A

N/A

$

1,418

Dry: May 2007

(a)	Dry-hole costs represent wells that have been drilled but do not have commercially productive oil and/or natural gas reservoirs and have been plugged and abandoned.
(b)	Drilling risk represents the estimated projected dry-hole costs, leasehold costs or sunk costs including promote for project participation per an Authorization For Expenditure (“AFE”) adjusted for current operating conditions (i.e. projected cost overruns, increased drilling rates and other items of a similar nature).

Drilling

Walker Ridge 155

In 2007 the Fund acquired a 3.5% working interest in the exploratory well Walker Ridge 155 from Kerr-McGee Oil & Gas Corporation (“Kerr McGee”), a wholly owned subsidiary of Anadarko Petroleum Corporation (“Anadarko”), the operator of the project. Drilling for Walker Ridge 155, a deep water project began in mid-August 2007.

While drilling the initial well, the Fund found traces of oil throughout much of the 4,500-foot interval as well as a thin section of high-quality oil. However, this initial well did not encounter the sedimentary formations that had been targeted. As a result, the working interest owners are evaluating additional data gathered during the drilling phase as well as new three-dimensional data to determine whether the operator should divert the well to a location more likely to encounter commercial reservoirs. The operator plans to re-use the majority of the initial well-bore in order to save time and money. Although encouraged by the data gathered thus far, which confirms the presence of oil in the geologic basin, the well has not been determined to be a successful property. Once diverted to a new location, if the well is not deemed commercial, it will be plugged and abandoned as a dry hole. Through December 31, 2007, the Fund has spent $7.5 million related to this property, for which the total estimated budget is approximately $52 million.

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Dry Holes

South Timbalier 135/136

In 2006, the Fund acquired a 15% working interest in the exploratory well South Timbalier 135/136 from Chevron U.S.A., Inc. (“Chevron”), the operator. On January 24, 2007, the Fund was informed by Chevron, that the exploratory well being drilled did not have commercially productive quantities of either oil or natural gas and was therefore deemed an unsuccessful well or dry-hole. Dry-hole costs related to South Timbalier 135/136, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007 were $2.5 million, $7.7 million and $10.3 million, respectively.

Eugene Island 255/256

In 2007, the Fund acquired a 15% working interest in the exploratory well Eugene Island 255/256 from Helis Oil & Gas Company (“Helis”), the operator. On May 25, 2007, the Fund was informed by Helis that the exploratory well being drilled did not have commercially productive quantities of either oil or natural gas and was therefore deemed an unsuccessful well or dry-hole. Dry-hole costs related to Eugene Island 255/256, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2007 and for the period August 28, 2006 (Inception) through December 31, 2007 were $1.4 million. There were no amounts incurred for the period August 28, 2006 (Inception) through December 31, 2006.

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

Royalty Relief

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 approximately $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.

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However, 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

None of the Fund’s projects are producing and therefore no definitive arrangements have been made for the sale or transportation of oil and natural gas that may be produced from the Fund’s projects. The Manager believes, however, that it is likely that oil and natural gas from the Fund’s current and future projects will have access to pipeline transportation and can be marketed in a similar fashion. Upon completion, production from future projects will 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 Operators are 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 project is operated by Anadarko.

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

Insurance

The Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover the projects, as well as general liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to the projects. In addition, the Manager’s past practice has been to obtain insurance as a package that is intended to cover most, if not all, of the funds under its management. These projects are owned by affiliates of the Fund. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature, and payment of any claims to the Fund’s affiliates, yearly insurance limits may become exhausted and be insufficient to cover a claim made by the Fund in that year.

Salvage Fund

As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or a salvage fund, which is in the nature of a sinking fund, money to help provide for the Fund’s proportionate share of the cost of dismantling production platforms and facilities, plugging and abandoning the projects, and removing the platforms, facilities and projects in respect of each of such projects after their useful life, in accordance with applicable federal and state laws and regulations. There is no assurance that the salvage fund will have sufficient assets to meet these requirements and any unfunded expenses, and the Fund may be liable for such expenses. In 2007, the Fund 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.

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Seasonality

Generally, the Fund’s business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is 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.

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

Customers

The Fund’s existing projects have not yet been developed to the point where reserves of oil and natural gas have been discovered or extracted. As a result, the Fund has not yet contracted with third parties to sell such oil and natural gas and therefore has no customers or any one customer upon which it depends for more than ten percent (10%) of the Fund’s revenues.

Energy Prices

Historically, the markets for crude oil and natural gas have been extremely volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions 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 and does not anticipate engaging in those types of transactions in the future.

Competition

Strong competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. Although the Fund does not compete for the 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.

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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. In addition, the Manager also maintains leases for other offices that are used for administrative purposes.

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 US 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.

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

          Sales and Transportation of Natural Gas/Oil

The Fund expects to sell its proportionate share of oil and natural gas to the market and to receive market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, the Fund is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission (the “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 the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, 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.

9

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

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages.

In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier, the Fund has not been required to make any such showing to the MMS, as the Operators are responsible for such compliance. However, notwithstanding the Operators’ responsibility for compliance, in the event of an oil spill, the Fund, along with the Operators and other working interest owners, could be liable under the OPA for the resulting environmental damage.

          Clean Water Act

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

          Federal Clean Air Act

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

          Other Environmental Laws

In addition to the above, the Fund’s operations may be subject to 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.

Potential Tax Benefits

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

10

          Deduction of Intangible Drilling and Development Costs

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

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

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

To the extent that drilling and development services were performed for the Fund in 2007, amounts incurred pursuant to bona fide arm’s-length drilling contracts and constituting intangible drilling and development costs were deductible by the Fund in 2007. To the extent that such services are performed in 2008, however, the Fund will only be allowed to deduct for the year 2007 amounts that are:

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

• attributable to wells spud within 90 days after December 31, 2007.

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

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

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

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

Consequently, intangible drilling and development costs meeting the above criteria were deducted by the Fund in 2007 even though a portion of such costs are attributable to services performed during 2008.

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

11

          Depletion Deductions

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

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

Percentage depletion with respect to production of oil and natural gas is available only to those qualifying for the independent producer’s exemption, and is limited to an average of 1,000 barrels per day of domestic oil production or 6,000,000 cubic feet per day of domestic natural gas production. The applicable rate of percentage depletion on production under the independent producer exemption is 15% of gross income from oil and natural gas sales.

The depletion deduction under the independent producer exemption may not exceed 65% of the taxpayer’s taxable income for the year, computed without regard to certain deductions. Any percentage depletion not allowed as a deduction due to the 65% of adjusted taxable income limitation may be carried over to subsequent years subject to the same annual limitation. For a shareholder that is a trust, the 65% limitation shall be computed without deduction for distributions to beneficiaries during the taxable year.

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

The independent producer exemption is not available to a taxpayer who refines more than 50,000 barrels of oil on any one day in a taxable year or who directly or through a related person sells oil or natural gas or any product derived therefrom (i) through a retail outlet operated by them or a related person or (ii) to any person who occupies a retail outlet which is owned and controlled by the taxpayer or a related person. In general, a related person is defined by Section 613A of the Code as a corporation, partnership, estate, or trust in which the taxpayer has a 5% or greater interest. For the purpose of applying this provision: (a) bulk sales of oil or oil and natural gas to commercial or industrial users are excluded from the definition of retail sales; (b) if the taxpayer or a related person does not export any domestic oil or natural gas production during the taxable year or the immediately preceding year, retail sales outside the U.S. are not deemed to be disqualifying sales; and (c) if the taxpayer’s combined receipts from disqualifying sales do not exceed $5.0 million for the taxable year of all retail outlets taken into account for the purpose of applying this restriction, such taxpayer will not be deemed a retailer.

          Depreciation

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

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

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

12

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

None.

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 approximately 930 shareholders of record of the Fund. To date, the Fund has not declared or paid cash dividends to the Fund shareholders. Ridgewood Energy Corporation, the Manager, may distribute dividends from available cash from operations as defined in the LLC Agreement.

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.

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 Bills, certificates of deposits) and other interest bearing cash accounts.

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

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

Distributions from Operations

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

13

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.

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.

During the period August 28, 2006 (Inception) through December 31, 2007, the Fund issued an aggregate 486.4825 Shares for gross proceeds of approximately $72.4 million. All sales of unregistered securities relied on Section 4(2) of the Securities Act and Rule 506 of Regulation D promulgated thereunder. All of the sales were made without the use of an underwriter. All purchasers of shares represented and warranted to the Fund that they were accredited investors as defined in Rule 501(a) under the Securities Act and that the Shares were being purchased for investment and not for resale.

From the amount raised, approximately $8.5 million was disbursed for commissions and legal syndication fees. Additionally, approximately $3.3 million was paid as an investment fee to Ridgewood Energy Corporation, the Manager, for the investigation and evaluation of investment property prospects. Remaining funds are expected to be used for exploration and development activities of oil and gas properties as well as the operation of the Fund.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

14

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

Overview of the Fund’s Business

The Fund (an exploratory stage enterprise) 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. The Fund began its operations by offering its Shares in a private offering on October 1, 2006. As a result of such offering, which was terminated on January 19, 2007, the Fund raised approximately $72.4 million through the sale of 486.4825 shares of LLC membership interest. After the payment of approximately $11.8 million in offering fees, commissions and investment fees to the Manager, affiliates and broker-dealers, the Fund retained approximately $60.6 million available for investment. Investment fees represent a one-time fee of 4.5% of initial capital contributions. The fee was payable for the service of investigating and evaluating investment opportunities and expensed as incurred. Since inception in August 2006, the Fund has acquired an interest in three offshore projects and has participated in the drilling of three wells. The Fund was notified by project operators that two of the projects resulted in dry holes. See also Item 1. “Business”.

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% of capital raised) for the evaluation of projects on the Fund’s behalf and 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”.

Once one of the Fund’s projects begins generating revenue, these revenues will be subject to the markets for crude oil and natural gas, which have been extremely volatile, and are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of crude oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability

Critical Accounting Estimates

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

Proved Reserves

The Fund plans to engage an independent petroleum engineer to perform a comprehensive study of the Fund’s proved, or 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 which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenue to change. For the period from August 2006 (Inception) through December 31, 2007, the Fund did not have any proved reserves. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depreciation, depletion and amortization.

15

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 its unproved property balance on an ongoing basis for possible impairment or reduction in value. Substantially all of the costs included in its unproved property balances are 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 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 represents a review of operations for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007. As the Fund’s inception was August 28, 2006, the results of operations below reflect non-comparable periods of approximately four months as compared to twelve months. In addition, as a result of the private placement offering which commenced in October 2006, there were certain one-time costs, the majority of which were incurred in 2006. The following table summarizes the Fund’s results of operations, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report.

16

(in thousands)	Year ended December 31, 2007			For the period August 28, 2006 (Inception) through December 31, 2006			For the period August 28, 2006 (Inception) through December 31, 2007
Revenue
Oil and gas revenue	$	—		$	—		$	—
Expenses
Dry-hole costs		3,964			7,749			11,713
Investment fees to affiliate		20			3,252			3,272
Management fees to affiliate		1,534			253			1,787
General and administrative expenses		453			328			781
Total expenses		5,971			11,582			17,553
Loss from operations		(5,971	)		(11,582	)		(17,553	)
Other income
Interest income		2,174			235			2,409
Net loss		(3,797	)		(11,347	)		(15,144	)
Other comprehensive income
Unrealized gain on marketable securities		16			—			16
Total comprehensive loss	$	(3,781	)	$	(11,347	)	$	(15,128	)

Year Ended December 31, 2007 Compared to the Period August 28, 2006 (Inception) through December 31, 2006 and the Period August 28, 2006 (Inception) through December 31, 2007

Operating Revenue

From inception of the Fund in August 2006 through December 31, 2007, the Fund has not recorded any operating revenue and is considered an exploratory stage enterprise.

Operating and Other Expenses

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.

	Year ended December 31, 2007		For the period August 28, 2006 (Inception) through December 31, 2006		For the period August 28, 2006 (Inception) through December 31, 2007
				(in thousands)
Lease Block
South Timbalier 135/136	$	2,546	$	7,749	$	10,295
Eugene Island 255/256		1,418		—		1,418
	$	3,964	$	7,749	$	11,713

Investment Fees. For the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007, investment fees incurred were $20 thousand, $3.3 million and $3.3 million, respectively. The Manager was paid a one-time investment fee of 4.5% of initial capital contributions. The fee was payable for the service of investigating and evaluating investment opportunities and affecting transactions and were expensed as incurred.

17

Management Fees.Management fees for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007, were $1.5 million, $0.3 million and $1.8 million, respectively. The Manager receives an annual management fee, payable monthly, which is equal to 2.5% of the total shareholder capital contributions. Commencing in January 1, 2007, the management fee, was reduced by the cumulative dry-hole expenses incurred by the Fund. These fees are to cover expenses associated with overhead incurred by the Manager for its ongoing 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 increase in the management fees from the period August 28, 2006 (Inception) through December 31, 2006 as compared to the year ended December 31, 2007 is the result of additional capital raised, and the difference between a four month period in 2006 as compared to a twelve month period for 2007.

General and Administrative Expenses.

Accounting, legal, fiduciary fees and insurance expenses represent costs specifically identifiable or allocable to the Fund. The following table summarizes general and administrative expenses.

	Year ended December 31, 2007		For the period August 28, 2006 (Inception) through December 31, 2006		For the period August 28, 2006 (Inception) through December 31, 2007
			(in thousands)
General and administrative expenses:
Accounting and legal fees	$	137	$	80	$	217
Insurance		274		242		516
Trust fees		41		—		41
Other		1		6		7
	$	453	$	328	$	781

Accounting and legal fees represent annual audit and tax preparation fees, quarterly reviews and filing fees of the Fund and have increased since 2006 due to additional SEC filing requirements once the Fund became effective in 2007. Insurance expense represents premiums related to well control insurance and directors and officers liability policy and are 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. Trust fees represent bank fees associated with the management of the Fund’s short-term and long-term investment portfolios in US Treasury securities which were opened in 2007.

Interest Income.Interest income represents interest earned on money market accounts and short-term and long-term US Treasury securities. Interest income for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007, were $2.2 million, $0.2 million and $2.4 million, respectively. The increase in interest income from the period August 28, 2006 (Inception) through December 31, 2006 as compared to the year ending December 31, 2007 is the result of an increase in capital raised, as well as a full year of interest income earned in 2007 as compared to four months in 2006.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows used in operating activities for the year ended December 31, 2007 were $0.2 million. These expenditures primarily related to payments for investment fees, management fees and general and administrative expenses of $0.4 million, $1.5 million and $0.5 million, respectively, partially offset by interest income received of $2.2 million.

Cash flows used in operating activities for the period August 28, 2006 (Inception) through December 31, 2006 were $3.2 million. These expenditures primarily related to payments for investment fees, management fees and general and administrative expenses of $2.9 million, $0.2 million and $0.3 million, respectively, offset by interest income received of $0.1 million and favorable working capital of $0.1 million.

Cash flows used in operating activities for the period August 28, 2006 (Inception) through December 31, 2007 were $3.5 million. These expenditures primarily related to payments for investment fees, management fees and general and administrative expenses of $3.3 million, $1.8 million and $0.8 million, respectively, offset by interest income received of $2.3 million and favorable working capital of $0.1 million.

18

Investing Cash Flows

Cash flows used in investing activities for the year ended December 31, 2007 were $47.0 million, which relate to expenditures for properties of $19.2 million, investment in the salvage fund of $1.0 million, investment in short-term marketable securities of $12.0 million and investment in long-term marketable securities of $14.7 million.

There was no cash flow used or provided by investing activities for the period August 28, 2006 (Inception) through December 31, 2006.

Cash flows used in investing activities for the period August 28, 2006 (Inception) through December 31, 2007 were $47.0 million, which relate to expenditures for properties of $19.2 million, investment in the salvage fund of $1.0 million, investment in short-term marketable securities of $12.0 million and investment in long-term marketable securities of $14.7 million

Financing Cash Flows

Cash flows provided by financing activities for the year ended December 31, 2007 were $2.2 million. These primarily related to cash receipts obtained from the Fund’s private offering of $3.3 million, which were offset by payments for syndication costs of $1.1 million.

Cash flows provided by financing activities for the period August 28, 2006 (Inception) through December 31, 2006 were $61.7 million. These primarily related to cash receipts obtained from the Fund’s private offering of $69.1 million, which were partially offset by payments for syndication costs of $7.4 million.

Cash flows provided by financing activities for the period from August 28, 2006 (Inception) through December 31, 2007 were $63.8 million. These primarily related to cash receipts obtained from the Fund’s private offering of $72.4 million, which were partially offset by payments for syndication costs of $8.5 million.

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, such estimated capital expenditures to be spent totaled approximately $52 million, a portion of which relates to the further development of the Fund’s Walker Ridge 155 property. In accordance with the Fund’s LLC Agreement, if Walker Ridge is determined to be a commercial success, the Manager anticipates an additional capital call to raise approximately $33.1 million to drill four more wells, which will cover these expenditures. Any remaining unspent development capital will be reallocated to one or more new unspecified projects.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its 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.

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

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

19

In addition to the capital raised by the Fund in its private placement, the Fund’s LLC Agreement indicates it may conduct another capital call to raise additional funds for the specific investment in Walker Ridge 155. The number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund experiences, if any, will not only reduce its ability to generate revenue, but also exhaust its limited supply of capital. Typically for a fund, the Manager seeks an investment portfolio that combines high and low risk exploratory projects.

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

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 2007 and December 31, 2006 and does not anticipate the use of such arrangements in the future.

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 December 31, 2006.

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 FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures 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 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.

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.

20

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 Corporation as Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund.

Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 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, 48
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

21

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

Robert E. Swanson has served as the President, Chief Executive Officer, sole director, and sole stockholder of Ridgewood Energy since its inception. Mr. Swanson is also the controlling member of Ridgewood Renewable Power, LLC (“Ridgewood Power”) and Ridgewood Capital Corporation (“Ridgewood Capital”), affiliates of Ridgewood Energy. Mr. Swanson has been President and registered principal of Ridgewood Securities Management, LLC and has served as the Chairman of the Board of Ridgewood Capital since its organization in 1998. Mr. Swanson is a member of the New York State and New Jersey State Bars, the Association of the Bar of the City of New York and the New York State Bar Association. He is a graduate of Amherst College and Fordham University Law School.

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

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

Kathleen P. McSherry has served as the 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, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, 2007, all filing requirements applicable to its officers, directors and 10% beneficial owners were met.

22

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.

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

The following table sets forth information with respect to beneficial ownership of the shares as of February 19, 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 486.4825 shares outstanding at February 19, 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	1.0000	*
Executive officers as a group (1)	1.0000	*

* Represents less than one percent.

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

In 2007 and 2006, Ridgewood Energy Corporation, the Manager, was paid a one-time investment fee of 4.5% of capital contributions. These fees were payable for services provided by the Manager of locating, investigating and evaluating investment opportunities and expensed as incurred. For the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007, investment fees were approximately $20 thousand, $3.3 million and $3.3 million, respectively. Of this amount, approximately $0.4 million were included in due to affiliates at December 31, 2006. There were no investment fees payable at December 31, 2007.

The Fund’s 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 costs. In 2007, the Manager changed its policy regarding the management fee calculation, and netted cumulative dry-hole costs against the total capital contributions, thus reducing its annual fee on a go-forward basis. Management fees of approximately $1.5 million, $0.3 million and $1.8 million were incurred and paid for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007, respectively. Of this amount approximately $1 thousand and $52 thousand were included in due to affiliates at December 31, 2007 and 2006, respectively.

The Manager was paid an offering fee approximating 3.5% of capital contributions to cover expenses incurred in the offer and sale of shares of the Fund. Such offering fee was included in syndication costs. For the period August 28, 2006 (Inception) through December 31, 2006, offering fees were approximately $2.5 million. Of this amount approximately $1 thousand and $0.3 million were included in due to affiliates at 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. As of December 31, 2007 and 2006, there was no outstanding payables or receivables related to these transactions.

Ridgewood Securities Corporation, a registered broker-dealer affiliated with the Manager, earned selling commissions and placement fees of approximately $5 thousand, $0.8 million, and $0.8 million for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007, respectively, for shares of the Fund sold, which are reflected in syndication costs of approximately $8.5 million. At December 31, 2007 and 2006, nil and $87 thousand, respectively, were included in due to affiliates.

23

There have been no distributions for the period August 28, 2006 (Inception) through December 31, 2007.

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees and services rendered by Deloitte and Touche, LLP for the year ended December 31, 2007 and for the period August 28, 2006 (Inception) through December 31, 2006.

	Year ended December 31, 2007		For the period August 28, 2006 (Inception) through December 31, 2006
	(in thousands)
Audit Fees (1)	$	125	$	40
Tax fees (2)		—		15
Total	$	125	$	55

(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.

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.

24

Exhibit No.		Description
10.1		Participation Agreement between Helis Oil & Gas Company, L.L.C. and Ridgewood Energy Corporation as Manager for Eugene Island 255/256 dated April 24, 2007 (incorporated by reference to Exhibit 10.1 to the Fund’s Quarterly Report on Form 10-Q filed with the SEC on June 22, 2007).
10.2		Participation Agreement between Kerr-McGee Oil & Gas Corporation and Ridgewood Energy Corporation as Manager for Walker Ridge 155, dated March 1, 2007 (incorporated by reference to Exhibit 10.2 to the Fund’s Quarterly Report on Form 10-Q filed with the SEC on November 7, 2007).
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.

25

INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2007 and 2006	F-3
Statements of Operations and Other Comprehensive Loss for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007	F-4
Statements of Changes in Members’ Capital for the year ended December 31, 2007, and for the period August 28, 2006 (Inception) through December 31, 2006	F-5
Statements of Cash Flows for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information — Information about Oil and Natural Gas Producing Activities - Unaudited	F-13

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying balance sheets of Ridgewood Energy U Fund LLC (an exploratory stage enterprise) (the “Fund”) as of December 31, 2007 and 2006, the related statements of operations and other comprehensive loss and cash flows for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007 and related statement of changes in members’ capital for the year ended December 31, 2007 and for the period August 28, 2006 (Inception) through December 31, 2006. These financial statements are the responsibility of the Fund’s management. Our responsibility is to express an opinion on the 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 U Fund, LLC as of December 31, 2007 and 2006, and the results of operations and cash flows for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte and Touche LLP

February 20, 2008

Parsippany, New Jersey

F-2

RIDGEWOOD ENERGY U FUND, LLC
(An exploratory stage enterprise)
BALANCE SHEETS
(in thousands, except share amounts)

	December 31,
	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	13,316		$	58,433
Short-term investments in marketable securities		12,020			—
Other current assets		118			154
Total current assets		25,454			58,587
Salvage fund		1,033			—
Long-term investments in marketable securities		14,742			—
Oil and gas properties
Unproved properties		7,542			—
Total oil and gas properties		7,542			—
Total assets	$	48,771		$	58,587
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Due to affiliate (Note 6)	$	2		$	837
Due to operator		10			7,749
Accrued expenses payable		70			732
Total current liabilities		82			9,318
Commitments and contingencies (Note 8)
Members’ capital:
Manager:
Deficit accumulated during the exploratory stage		(472	)		(162	)
Manager’s total		(472	)		(162	)
Shareholders:
Capital contributions (1,000 shares authorized;
486.4825 and 483.4529 issued and outstanding
at December 31, 2007 and 2006, respectively)		72,381			71,923
Syndication costs		(8,541	)		(8,480	)
Subscription receivable		(23	)		(2,827	)
Deficit accumulated during the exploratory stage		(14,672	)		(11,185	)
Accumulated other comprehensive income		16			—
Shareholders’ total		49,161			49,431
Total members’ capital		48,689			49,269
Total liabilities and members’ capital	$	48,771		$	58,587

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

F-3

RIDGEWOOD ENERGY U FUND, LLC
(An exploratory stage enterprise)
STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE LOSS
(in thousands, except share amounts)

	Year ended December 31, 2007			For the period August 28, 2006 (Inception) through December 31, 2006			For the period August 28, 2006 (Inception) through December 31, 2007
Revenue
Oil and gas revenue	$	—		$	—		$	—
Expenses
Dry-hole costs		3,964			7,749			11,713
Investment fees to affiliate (Note 6)		20			3,252			3,272
Management fees to affiliate (Note 6)		1,534			253			1,787
General and administrative expenses		453			328			781
Total expenses		5,971			11,582			17,553
Loss from operations		(5,971	)		(11,582	)		(17,553	)
Other income
Interest income		2,174			235			2,409
Net loss		(3,797	)		(11,347	)		(15,144	)
Other comprehensive income
Unrealized gain on marketable securities		16			—			16
Total comprehensive loss	$	(3,781	)	$	(11,347	)	$	(15,128	)
Manager Interest
Net loss	$	(310	)	$	(162	)	$	(472	)
Shareholder Interest
Net loss	$	(3,487	)	$	(11,185	)	$	(14,672	)
Net loss per share	$	(7,168	)	$	(23,135	)	$	(30,159	)

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

F-4

RIDGEWOOD ENERGY U FUND, LLC
(An exploratory stage enterprise)
STATEMENTS OF CHANGES IN MEMBERS’ CAPITAL
(in thousands, except share amounts)

	# of Shares		Manager			Shareholders			Total
Balances, August 28, 2006 (Inception)		—	$	—		$	—		$	—
Shareholder’s capital contributions		483.4529		—			71,923			71,923
Syndication costs (included offering fee of $2,529 paid to the Manager and selling commissions and placement fees of $68 and $723, respectively, paid to Ridgewood Securities Corp. - Note 6)		—		—			(8,480	)		(8,480	)
Subscription receivable		—		—			(2,827	)		(2,827	)
Net loss		—		(162	)		(11,185	)		(11,347	)
Balances, December 31, 2006		483.4529		(162	)		49,431			49,269
Shareholder’s capital contributions		3.0296		—			458			458
Syndication costs		—		—			(61	)		(61	)
Collection of subscription receivable		—		—			2,804			2,804
Net loss		—		(310	)		(3,487	)		(3,797	)
Other comprehensive income		—		—			16			16
Balances, December 31, 2007		486.4825	$	(472	)	$	49,161		$	48,689

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

F-5

RIDGEWOOD ENERGY U FUND, LLC
(An exploratory stage enterprise)
STATEMENTS OF CASH FLOWS
(in thousands)

	Year ended December 31, 2007			For the period August 28, 2006 (Inception) through December 31, 2006			For the period August 28, 2006 (Inception) through December 31, 2007
Cash flows from operating activities
Net loss	$	(3,797	)	$	(11,347	)	$	(15,144	)
Adjustments to reconcile net loss to net cash used in operating activities
Dry-hole costs		3,964			7,749			11,713
Amortization of premium on investment		3			—			3
Changes in assets and liabilities:
Decrease (increase) in other current assets		36			(154	)		(118	)
(Decrease) increase in due to affiliate		(443	)		445			1
(Decrease) increase in accrued expenses payable		(10	)		80			70
Net cash used in operating activities		(247	)		(3,227	)		(3,475	)
Cash flows from investing activities
Capital expenditures for oil and gas properties		(19,245	)		—			(19,245	)
Funding of salvage fund		(1,033	)		—			(1,033	)
Investment in held-to-maturity securities		(12,020	)		—			(12,020	)
Investment in available-for-sale securities		(14,729	)		—			(14,729	)
Net cash used in investing activities		(47,027	)		—			(47,027	)
Cash flows from financing activities
Contributions from shareholders		3,262			69,096			72,358
Syndication costs paid		(1,105	)		(7,436	)		(8,540	)
Net cash provided by financing activities		2,157			61,660			63,818
Net (decrease) increase in cash and cash equivalents		(45,117	)		58,433			13,316
Cash and cash equivalents, beginning of period		58,433			—			—
Cash and cash equivalents, end of period	$	13,316		$	58,433		$	13,316
Supplemental schedule of non-cash investing activities
Accrual for capital expenditures in oil and gas properties reclassified to dry-hole costs	$	—		$	7,749		$	—
Supplemental schedule of non-cash financing activities
Subscriptions receivable	$	23		$	2,827		$	23
Accrual for syndication costs	$	1		$	1,044		$	1

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

F-6

RIDGEWOOD ENERGY U FUND, LLC
(An exploratory stage enterprise)
NOTES TO FINANCIAL STATEMENTS

1. Organization and Purpose

The Ridgewood Energy U Fund, LLC (the “Fund”) (an exploratory stage enterprise), a Delaware limited liability company, was formed on August 28, 2006 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of October 1, 2006 by and among Ridgewood Energy Corporation (the “Manager”), and the shareholders of the Fund. Although the date of formation is August 28, 2006, the Fund did not begin operations until October 1, 2006 when it began its private offering of shares of LLC member interest (the “Shares”). The offering was terminated on January 19, 2007.

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. To date, the Fund has not earned revenue from these operations and is considered in the exploratory stage.

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

2. Summary of Significant Accounting Policies

Exploratory Stage Enterprise

Management uses various criteria to evaluate whether the Fund is an exploratory stage enterprise, including but not limited to, the success of drilling, the timing, significance, quality and flow of production and the results of reserve reports obtained from experts. On a case by case basis, once a project begins production, management performs diligent analysis at regular intervals utilizing the various criteria noted above to determine the appropriate classification of the Fund as an exploratory state entity. Based on such analysis, management has determined the Fund continues to be an exploratory stage enterprise.

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, impairments and asset retirement obligations. Actual results may differ from those estimates.

Cash and Cash Equivalents

All highly liquid investments with maturities when purchased of three months or less are considered 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 approximately $0.1 million and $58.2 million, respectively. Cash and cash equivalents of approximately $13.0 million and nil are investments in three month US Treasury Bills at December 31, 2007 and 2006, respectively.

Investments in Marketable Securities

At times the Fund may invest in United States Treasury Bills and Notes. These investments are considered short-term when their maturities are greater than three months and less than one year and long-term when their maturities are in excess of twelve months. The Fund currently has short-term investments that are classified as held-to-maturity. Held-to-maturity securities are those investments that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate fair value. At December 31, 2007, the Fund had short-term held-to-maturity investments, inclusive of salvage fund of $1.0 million, totaling $13.1 million, maturing in May and June 2008.

F-7

The Fund currently has long-term investments, which mature in December 2009, that are classified as available-for-sale. Available-for-sale securities are carried in the financial statements at fair value. The following table is a summary of long-term, available-for-sale investments at December 31, 2007:

	Cost		Gross Unrealized Gains		Fair Value
Available-for-Sale		(in thousands)
U.S. Treasury Notes	$	14,726	$	16	$	14,742

There were no available-for-sale investments, short or long-term, at December 31, 2006.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. Unrealized gains or losses for available-for-sale securities are reported in other comprehensive income until realized.

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”) who are responsible for drilling, administering and producing activities pursuant to the terms of the applicable Operating Agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures relating to the wells are advanced and billed by Operators through authorization for expenditures.

The successful efforts method of accounting for oil and 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. 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 are depleted by the unit-of-production method.

As of December 31, 2007 and 2006, approximately $10 thousand and $7.7 million, respectively, were recorded in due to operators, related to the acquisition of oil and gas property, both successful and unsuccessful, as well as recovery efforts. The December 31, 2007 balance was paid in the first quarter 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.

F-8

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 recorded. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes to the asset retirement obligations.

	For the Year Ended December 31, 2007			For the Period August 28, 2006 (Inception) through December 31, 2006
	(in thousands)
Balance - Beginning of period	$	—		$	—
Liabilities incurred		610			—
Liabilities settled		(610	)		—
Balance - End of period	$	—		$	—

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 revenue is 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 Fund has not earned revenue from inception to date.

Upon production, the volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas to which the Fund is entitled. The Fund will account for such oil and natural gas production imbalances by the entitlements method. Under the entitlements method, the Fund will recognize a receivable from other working interest owners for volumes oversold by other working interest owners, and a payable to other working interest owners for volumes oversold by the Fund. As of December 31, 2007 and 2006, there were no oil or natural gas balancing arrangements between the Fund and other working interest owners.

Impairment of Long-Lived Assets

In accordance with the provisions of Statement of Financial Accounting Standards (“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. The Fund has not begun production as of December 31, 2007 and therefore has not recorded depletion and amortization.

F-9

Income Taxes

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

Income and Expense Allocation

Profits and losses are allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for items of expense, loss, deduction and credit that are attributable to the expenditure of shareholders’ capital contributions, 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 exiting assts 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 does not expect this guidance to 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 accessing the reserves. Capitalized costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. At December 31, 2007 and 2006, the Fund had no capitalized exploratory well costs greater than one year. The following table reflects the net changes in unproved properties.

	Year ended December 31, 2007			For the period August 28, 2006 (Inception) through December 31, 2006
	(in thousands)
Balance - beginning of period	$	—		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		8,960			7,749
Capitalized exploratory well costs charged to dry-hole costs		(1,418	)		(7,749	)
Balance - end of period	$	7,542		$	—

F-10

Dry-hole costs are detailed in the table below.

	Year ended December 31, 2007		For the period August 28, 2006 (Inception) through December 31, 2006		For the period August 28, 2006 (Inception) through December 31, 2007
	(in thousands)
Lease Block
South Timbalier 135/136	$	2,546	$	7,749	$	10,295
Eugene Island 255/256		1,418		—		1,418
	$	3,964	$	7,749	$	11,713

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 distributions are 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, is 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.

There have been no distributions made by the Fund.

6. Related Parties

In 2007 and 2006, Ridgewood Energy Corporation, the Manager, was paid a one-time investment fee of 4.5% of capital contributions. These fees were payable for services provided by the Manager of locating, investigating and evaluating investment opportunities and expensed as incurred. For the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006, and for the period August 28, 2006 (Inception) through December 31, 2007, investment fees were approximately $20 thousand, $3.3 million and $3.3 million, respectively. Of this amount, approximately $0.4 million were included in due to affiliates at December 31, 2006. There were no investment fees payable at December 31, 2007.

The Fund’s 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 costs. In 2007, the Manager changed its policy regarding the management fee calculation, and netted cumulative dry-hole costs against the total capital contributions, thus reducing its annual fee on a go-forward basis. Management fees of approximately $1.5 million, $0.3 million and $1.8 million were incurred and paid for the year ended December 31, 2007, for the period August 28, 2006 (Inception) through December 31, 2006 and for the period August 28, 2006 (Inception) through December 31, 2007, respectively. Of this amount approximately $1 thousand and $52 thousand were included in due to affiliates at December 31, 2007 and 2006, respectively.

The Manager was paid an offering fee approximating 3.5% of capital contributions to cover expenses incurred in the offer and sale of shares of the Fund. Such offering fee was included in syndication costs (Note 2). For the period August 28, 2006 (Inception) through December 31, 2006, offering fees were approximately $2.5 million. Of this amount approximately $1 thousand and $0.3 million were included in due to affiliates at 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. As of December 31, 2007 and 2006, there was no outstanding payables or receivables related to these transactions.

F-11

Ridgewood Securities Corporation, a registered broker-dealer affiliated with the Manager, earned selling commissions and placement fees of approximately $5 thousand, $0.8 million, and $0.8 million for the year ended December 31, 2007, the period August 28, 2006 (Inception) through December 31, 2006 and the period August 28, 2006 (Inception) through December 31, 2007, respectively, for shares of the Fund sold, which are reflected in syndication costs (Note 2) of approximately $8.5 million. At December 31, 2007 and 2006, nil and $87 thousand, respectively, were included in due to affiliates.

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

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

7. Fair Value of Financial Instruments

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

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 vary depending on the stage of development on a property-by-property basis. As of December 31, 2007, the Fund had committed to spend an additional $0.4 million relating to the Walker Ridge 155 property. No other firm commitments have been entered, however it is expected that the Fund will invest all of its unspent capital on either Walker Ridge 155, or future projects.

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 and is allocated to the Fund. Claims made by other such programs can reduce or eliminate insurance for the Fund.

F-12

RIDGEWOOD ENERGY U FUND, LLC
SUPPLEMENTARY 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 schedule provides supplemental information on oil and natural gas exploration and producing activities of the Fund. Tables I and II provide historical cost information pertaining to capitalized costs, costs incurred in exploration, property acquisitions and development, and results of operations. As of December 31, 2007 and 2006, the Fund did not have any proved reserves to warrant additional disclosures.

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		December 31, 2006
	(in thousands)
Proved oil and gas properties	$	—	$	—
Unproved oil and gas properties		7,542		—
Total oil and gas properties	$	7,542	$	—

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

	Year ended December 31, 2007		For the period August 28, 2006 (Inception) through December 31, 2006
	(in thousands)
Exploratory drilling costs - capitalized	$	7,542	$	—
Exploratory drilling costs - expensed		3,964		7,749
	$	11,506	$	7,749

F-13

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 U FUND, LLC
Date: February 20, 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)	February 20, 2008
Robert E. Swanson
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial	February 20, 2008
	Officer (Principal Accounting Officer)
Kathleen P. McSherry
/s/ ROBERT E. SWANSON	Chief Executive Officer of Manager	February 20, 2008
Robert E. Swanson