Ridgewood Energy O Fund 10K 2008 Annual report

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

FORM 10-K

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

For the fiscal year ended December 31, 2008
or
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-51924

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


Delaware	76-0774429
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

947 Linwood Avenue, Ridgewood, NJ 07450
(Address of principal executive offices) (Zip code)

(800) 942-5550
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:

Shares of LLC Membership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x 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). Yeso Nox

There is no market for the shares of LLC Membership Interest in the Fund. As of March 12, 2009 there are 870.6486 shares outstanding.

RIDGEWOOD ENERGY O FUND, LLC
2008 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS


			PAGE


PART I
	ITEM 1	BUSINESS	3
	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 STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	13
	ITEM 6	SELECTED FINANCIAL DATA	13
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	19
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	19
	ITEM 9A	CONTROLS AND PROCEDURES	20
	ITEM 9B	OTHER INFORMATION	20
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	21
	ITEM 11	EXECUTIVE COMPENSATION	22
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	22
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	23
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	23
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	23

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy O Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections, statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are forward-looking statements 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. These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will likely result,” and similar expressions. 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, except as required by law.

WHERE YOU CAN GET MORE INFORMATION

The Fund files annual, quarterly and current reports and certain other information with the Securities and Exchange Commission (“SEC”). Persons may read and copy any materials the Fund files with the SEC at the SEC’s public reference room at 100 F Street, NE, Washington D.C. 20549 on official business days during the hours of 10 a.m. to 3 p.m. Eastern Time. Information may be obtained from the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on December 21, 2004 to acquire interests primarily in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on February 16, 2005, selling whole and fractional shares of LLC membership interest (“Shares”), primarily at $150 thousand per whole Share. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on June 30, 2005. The Fund raised $129.0 million and after payment of $20.6 million in offering fees, commissions and investment fees, the Fund had $108.4 million for investments and operating expenses. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” for additional discussion.

Manager

Ridgewood Energy Corporation (the “Manager”) or (“Ridgewood Energy”) was founded in 1982 by Robert E. Swanson. The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investment, the Manager locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made. This includes review of existing title documents, reserve information, and other technical specifications regarding a project, and review and preparation of participation agreements and other agreements relating to an investment.

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

The Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing and printing periodic reports for shareholders and the SEC, commission fees, taxes, outside legal, accounting and consulting fees, litigation expenses and other expenses. The Fund is required to reimburse the Manager for all such expenses paid on its behalf.

As compensation for their services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for the years ended December 31, 2008 and 2007 were $2.1 million and $2.3 million, respectively. Additionally, the Manager is entitled to receive a 15% interest in cash distributions made by the Fund. For the years ended December 31, 2008 and 2007, the Manager was paid distributions totaling $1.1 million and $73 thousand, respectively.

Business Strategy

The Fund’s primary investment objective is to generate cash for distribution to the Fund’s shareholders through the acquisition of “working interests” in the exploration, production and sale of oil and natural gas. Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion, subject to available cash from operations, reserve requirements and Fund operations. A “working interest” is a percentage of ownership in an oil and natural gas lease granting its owner the right to explore, drill and produce oil and natural gas from projects on that lease block. The Fund 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. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well. After royalties are paid, the working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of working interest owned.

By virtue of its acquisition of working interests in various leases, the Fund invests and participates in exploration and production of oil and natural gas projects in leases located in the waters of the Gulf of Mexico on the Outer Continental Shelf (“OCS”). These activities are governed by the Outer Continental Shelf Lands Act (“OCSLA”) enacted in 1953 and administered by the Mineral Management Services (“MMS”). The Fund generally looks to invest in working interests that have been proposed by larger independent oil and natural gas companies seeking to minimize their risks by selling a portion of their interest in the working interest. These investments may require the Fund to pay a disproportionate part of the drilling costs on the exploratory well of a project than its working interest would otherwise require. This is called a promote, which is common in the oil and natural gas exploration industry. In addition, notwithstanding the sale of an interest to the Fund, the seller may retain a right for some period of time to payments from sales of oil and natural gas production from a well or project. This is called an overriding interest, which is also common in this industry. Notwithstanding any such promote or overriding interest, the Fund invests 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.

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

Once the Manager determines that a particular project (i.e., working interest in a lease block) is an appropriate investment for the Fund, the Manager enters into a participation agreement and a joint operating agreement with the other working interest owners in a lease. Pursuant to the participation agreements and operating agreements, proposals and decisions are made based on percentage ownership approvals.

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

Manager’s Investment Committee and Investment Criteria

The Manager maintains an investment committee, consisting of six members, which provides operational, scientific and technical oil and gas expertise to the Fund. Five members of the investment committee are based out of the Manager’s Ridgewood, New Jersey office and one member of the investment committee is based out of the Manager’s Houston, Texas office. In considering projects, the investment committee and other members of the investment team evaluate each 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 (i) targeting projects that have or are expected to have operators with significant resources and experience in oil and natural gas exploration; (ii) targeting projects that have or are expected to have partners that also have significant resources and experience in oil and natural gas exploration; (iii) technical quality of the project including its geology, seismic profile, locational trends, and whether the project has potential for multiple prospects; (iv) oil or natural gas reserve potential; (v) whether and the extent to which the operator participates as a working interest owner in the project; (vi) economic factors, such as potential revenues from the project, the rate of return, and estimated time to first production; (vii) risk factors associated with exploration; (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 nineteen wells, thirteen have been determined to be dry holes, five have been determined to be successful and one is currently drilling.


Lease Block	Working Interest		Operator		Off-shore Location in Gulf of Mexico		Target Depth	Drilling Risk (b)		Total Spent Through December 31, 2008

							(feet)	(in thousands)

Currently Drilling
Aspen Project	2.00	%		Newfield		Louisiana	22,000	$	3,900	$	—

Successful Projects
Cobalt Project	4.00	%		Newfield		Louisiana	17,000		N/A	$	1,001
Liberty Project	5.00	%		LLOG		Louisiana	15,500		N/A	$	2,859
South Pelto 9	16.67	%		McMoRan		Louisiana	17,700		N/A	$	4,927
Eugene Island 346/347 Well #1	5.00	%		McMoRan		Louisiana	12,900		N/A	$	3,573
Eugene Island 346/347 Well #2	5.00	%		McMoRan		Louisiana	7,800		N/A	$	763

Dry Holes (Date determined dry) (a)
South Timbalier 287 (January 2009)	4.00	%		Apache		Louisiana	23,400		N/A	$	3,858
Bison Project (January 2009)	3.00	%		LLOG		Texas	10,500		N/A	$	215
Eos Project (November 2008)	3.00	%		Mariner		Louisiana	17,400		N/A	$	2,472
Ruby Project (August 2008)	10.00	%		PetroQuest		Louisiana	16,000		N/A	$	1,924
High Island 38 (June 2008)	12.50	%		W&T Offshore		Texas	15,800		N/A	$	6,715
Eugene Island 346/347 Well #3 (June 2008)	5.00	%		McMoRan		Louisiana	5,400		N/A	$	279
Walker Ridge 155 (June 2008)	1.00	%		Anadarko		Louisiana	32,000		N/A	$	2,234
South Marsh Island 213 (April 2008)	5.50	%		El Paso		Louisiana	16,500		N/A	$	1,688
West Cameron 296 (November 2007)	16.67	%		Newfield		Louisiana	13,500		N/A	$	2,568
West Delta 95 (February 2007)	28.05	%		Apache		Louisiana	17,900		N/A	$	16,128
West Cameron 78/95 (July 2006)	30.00	%		El Paso		Louisiana	14,500		N/A	$	4,339
Eugene Island 334 (May 2006)	33.33	%		Devon		Louisiana	17,000		N/A	$	9,136
Eugene Island 357 (March 2006)	18.00	%		Newfield		Louisiana	15,500		N/A	$	4,379


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

(b)	Drilling risk represents the prospective estimated dry-hole, leasehold and sunk costs, as applicable.

Currently Drilling

Aspen Project
In July 2008, the Fund acquired a 2.0% working interest in the Aspen Project, an exploratory well, from Newfield Exploration Company (“Newfield”), the operator. The Aspen Project began drilling in February 2009 and results are expected during the second quarter of 2009. The total estimated budget for this project is $18.0 million. At December 31, 2008, the Fund had not incurred costs related to this well.

Successful Projects

Cobalt Project
In August 2008, the Fund acquired a 4.0% working interest in the Cobalt Project, an exploratory well, from Newfield, the operator. The Cobalt Project was determined to be a commercial success in January 2009 and completion efforts are ongoing. The well is expected to commence production in May 2009. Through December 31, 2008, the Fund has spent $1.0 million related to this property, for which the total estimated budget is $1.9 million.

Liberty Project
In April 2008, the Fund acquired a 5.0% working interest in the Liberty Project, an exploratory well, from LLOG Exploration Offshore, Inc. (“LLOG”), the operator. This project began drilling in May 2008 and was determined to be successful on July 4, 2008. Completion efforts are ongoing and production is expected in the first quarter 2010. Through December 31, 2008, the Fund has spent $2.9 million on this well, for which the total estimated budget is $4.3 million.

South Pelto 9
In July 2006, the Fund acquired a 16.67% working interest from Newfield, the operator. South Pelto 9 was determined to be successful in late-2006 and production commenced in September 2007. In August 2007, Newfield sold its interest in this property to McMoRan Exploration Co. (“McMoRan”). At that time, McMoRan assumed Newfield’s responsibilities as the operator of this property. The South Pelto 9 well did not produce for approximately two months due to hurricane activity during late-August 2008 and September 2008. Production resumed for South Pelto 9 in mid-October 2008. The Fund has spent $4.9 million related to this property.

Eugene Island 346/347
Well #1
In March 2007, the Fund acquired a 5.0% working interest in the exploratory well Eugene Island 346/347, from Newfield, the operator. In June 2007, the well was determined to be successful. In August 2007, Newfield sold its interest in this property to McMoRan Exploration Co. (“McMoRan”). At that time, McMoRan assumed Newfield’s responsibilities as the operator of this property. The well was completed and production commenced in June 2008. The Fund has spent $3.6 million related to this property.

Well #2
As a result of the drilling success of the first exploratory well for Eugene Island 346/347, the second and third wells commenced drilling in May 2008. In late-May 2008, Eugene Island 346/347 well #2 was determined to be commercially successful and production commenced in July 2008. The Fund has spent $0.8 million related to this property.

None of the Fund’s wells, including Eugene Island 346/347 wells #1 and #2, were materially damaged as a result of third quarter 2008 hurricane activity in the Gulf of Mexico. However, the pipeline utilized to transport these wells’ oil and natural gas production has suffered severe damage thereby shutting down production for these wells. As a result, these wells have been shut-in until the pipeline repairs are completed by its owner. There is no cost to the Fund related to these repair activities, however, these wells will not produce oil and natural gas or earn revenue during this repair period. The Eugene Island properties are currently expected to resume production during the second quarter 2009.

Dry Holes

South Timbalier 287
In November 2007, the Fund acquired a 4.0% working interest in the exploratory well South Timbalier 287, from Apache Corporation (“Apache”), the operator. This project began drilling in March 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $3.9 million. Additional dry-hole costs of $0.3 million were incurred during the first quarter 2009.

Bison Project
In November 2008, the Fund acquired a 3.0% working interest in the Bison Project, an exploratory well, from LLOG, the operator. The project, which is located in the Galveston region of the Gulf of Mexico, began drilling in December 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009. For the year ended December 31, 2008, dry-hole costs related to this well were $0.2 million. Additional dry-hole costs of $0.1 million, inclusive of plug and abandonment expenses, were incurred during the first quarter 2009.

Eos Project
In August 2008, the Fund acquired a 3.0% interest in the Eos Project, an exploratory well, from Mariner Energy (“Mariner”), the operator. The project, which is located in the Garden Banks region of the Gulf of Mexico, began drilling in August 2008 and was determined to be an unsuccessful well, or dry hole, in November 2008. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $2.5 million.

Ruby Project
In May 2008, the Fund acquired a 10.0% working interest in the Ruby Project, an exploratory well, from PetroQuest Energy, L.L.C. (“PetroQuest”), the operator. The project, which is located in the Eugene Island region of the Gulf of Mexico, began drilling in June 2008 and was determined to be an unsuccessful well, or dry hole, in August 2008. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $1.9 million.

High Island 38
In the fourth quarter 2007, the Fund acquired a 12.5% working interest in the High Island 38 project, from W&T Offshore, Inc. (“W&T Offshore”), the operator. In June 2008, the well was determined to be unsuccessful, or a dry hole, and has been plugged and abandoned. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $6.7 million.

Eugene Island 346/347
Well #3
In June 2008, the Fund was informed by McMoRan that Eugene Island 346/347 well #3 did not have commercially productive quantities of either oil or natural gas and had been determined to be an unsuccessful well, or dry hole. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $0.3 million.

Walker Ridge 155
In 2007, the Fund acquired a 1.0% working interest in the exploratory project Walker Ridge 155 from Kerr-McGee Oil & Gas Corporation, a wholly owned subsidiary of Anadarko Petroleum Corporation (“Anadarko”), the operator. Drilling for Walker Ridge 155, a deepwater well began in August 2007. In June 2008, the Fund was informed by Anadarko that based upon its evaluation of the three-dimensional data surrounding the Walker Ridge 155 lease block, they elected not to continue drilling this well. The well has been determined to be unsuccessful, or a dry hole, and has been plugged and abandoned. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $2.2 million.

South Marsh Island 213
In February 2008, the Fund acquired a 5.5% working interest in the exploratory well South Marsh Island 213 from El Paso E&P Company, L.P. (“El Paso”), the operator. This project began drilling in March 2008. In April 2008 the Fund was informed by El Paso that the well being drilled on the South Marsh Island 213 lease block did not have commercially productive quantities of either gas or oil and had been determined to be an unsuccessful well, or dry hole. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $1.7 million.

West Cameron 296
In the third quarter 2007, the Fund acquired a 16.67% working interest in the exploratory well West Cameron 296 from Newfield, the operator. The property began drilling in September 2007. On November 5, 2007, the Fund was informed by Newfield that the exploratory well being drilled on the West Cameron 296 lease block did not have commercially productive quantities of either gas or oil and had been determined to be an unsuccessful well or dry hole. Dry-hole costs related to this well, including plug and abandonment expenses, were $2.6 million.

West Delta 95
The Fund acquired a 28.0% working interest in West Delta 95 from Apache and BP America Production Co. (“BP”). BP was the operator of West Delta 95 until July 26, 2006, at which time Apache took over the project as operator. The property began drilling in May 2005 and in August 2005, before reaching its target depth, the project was evacuated in preparation for Hurricane Katrina. As a result of Hurricane Katrina, the well sustained damage. Recovery operations totaling $12.9 million were completed and drilling resumed in January 2007. The Fund filed a claim with its insurance carrier and received $11.2 million of insurance proceeds. During 2007, the Fund recorded a casualty loss of $1.7 million as a result of changes in estimates to, and the ultimate settlement of, the insurance claim. In February 2007, the well was determined to not have commercially productive quantities of either natural gas or oil and therefore was deemed to be a dry-hole. Dry-hole costs related to this well, including plug and abandonment expenses, were $16.1 million.

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” in this Item 1. “Business”.

As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the length of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a degree, the planned activities of exploration and production to be conducted by the lessee.

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 and 800 meters and 10 years for depths in excess of 800 meters. During this primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

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 natural gas lease under the OCSLA pay a 16.67% or 18.75% royalty to the MMS for shallow-water projects, dependent upon lease date, and a 12.5% royalty to the MMS for deepwater projects. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 83.33% of the total revenue for shallow-water projects and 87.5% of the total revenue for deepwater projects, and, such net revenue amount may be further reduced by any other royalty burdens that apply to a lease block. However, as described below, the MMS has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects.

Mineral Management Services Deep Gas Royalty Incentive

On January 26, 2004, the MMS promulgated a rule providing incentives for companies to increase deep oil and natural gas production in the Gulf of Mexico (the “Royalty Relief Rule”). Under the Royalty Relief Rule, lessees will be eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief would be available for wells drilled and perforated deeper than 18,000 feet subsea. It should be noted that the Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the continental shelf nor does it apply if the price of natural gas exceeds $10.37 Million British Thermal Units (“mmbtu”) adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters.

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

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

Oil and Natural Gas Agreements

The Fund has entered into a short-term, month-to-month agreement with a third party marketer who is currently marketing and selling the Fund’s proportionate share of oil and natural gas to the public market. The Fund is receiving market prices for oil and natural gas. All of the Fund’s current projects are near existing transportation infrastructure and pipelines. The Manager believes that it is likely that oil and natural gas from the Fund’s future projects will have access to pipeline transportation and can be marketed in a similar fashion.

Operator

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund’s ongoing projects are operated by LLOG, McMoRan, and Newfield.

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

Insurance

The Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its 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. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims to the Fund’s affiliates, yearly insurance limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.

Salvage Fund

As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or a salvage fund, which is in the nature of a sinking fund, cash to help provide for the Fund’s proportionate share of the cost of dismantling and removing production platforms and facilities and plugging and abandoning the projects, in accordance with applicable federal and state laws and regulations. There is no assurance that the salvage fund will have sufficient assets to meet these requirements and any unfunded expenses, and the Fund may be liable for such expenses. The Fund has deposited $1.0 million from capital contributions into a salvage fund, which, along with interest earned on this account, the Fund estimates to be sufficient to meet the Fund’s potential requirements. If the Manager determines the salvage fund will not be sufficient to cover the Fund’s proportionate share of expense, the Fund may transfer amounts from operating income to fund the deficit. Any portion of a salvage fund that remains after the Fund pays its share of the actual salvage costs will be distributed to the shareholders. There are no legal restrictions on the withdrawal or use of the salvage fund.

Seasonality

Generally, the Fund’s business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is 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 Gulf of Mexico as June 1st through November 30th. 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 and price of repair equipment. As a result, these factors may affect the supply and, consequently, the price of oil and natural gas. 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 effect of hurricanes on operations can range from no damage and little or no interruptions in operations to significant damage with extended interruptions in operations. As such, it is impossible to predict what impact, if any, a hurricane may have on the Fund’s projects. During September 2008, hurricane activity in the Gulf of Mexico did not cause material damage to any of the Fund’s properties, however; the Fund has experienced production interruptions relative to its South Pelto 9 and Eugene Island 346/347 #1 and #2 wells.

Customers

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

Energy Prices

Historically, the markets for crude oil and natural gas have been extremely volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of crude oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability. The Fund has not engaged in any price risk management programs or hedges to date.

Competition

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

In many instances, the Fund competes for projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position that they could outbid the Fund for a project. However, because these companies are so large and have such significant resources, they tend to focus more on projects that are larger, have greater reserve potential, and cost significantly more to explore and develop. 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 typically competes. Many of these larger companies have participated in the auctions for lease blocks directly from the U.S. Government. In such cases, these companies obtain from the U.S. Government 100% of the leasehold of a particular lease block in the Gulf of Mexico. In order to obtain even more resources to invest in other larger and more expensive projects, they diversify current holdings, including projects they own in the shallow waters of the Gulf of Mexico, by selling off percentage interests in these lease blocks. As a result, very good projects in the shallow waters of the Gulf of Mexico become available. The Fund, therefore, has opportunities to acquire interests in these smaller, yet economically attractive projects.

Employees

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

Offices

The Manager’s principal executive offices are located at 947 Linwood Avenue, Ridgewood, NJ 07450, and its phone number is 800-942-5550. The Manager also leases additional office space at 11700 Old Katy Road, Houston, TX 77079. 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 U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. Offshore operations are subject to numerous regulatory requirements, including stringent engineering and construction specifications related to offshore production facilities and pipelines and safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

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

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

Sales and Transportation of Oil and Natural Gas

The Fund sells its proportionate share of oil and natural gas to the market and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for it to make such sales, the Fund is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The rates, terms and conditions are regulated by FERC pursuant to a variety of statutes including the OSCLA, the Natural Gas Policy Act and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different than the impact upon other oil or natural gas producers and marketers.

Environmental Matters and Regulation

The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water and the protection of aquatic species and habitats. However, although it shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that is caused by the Fund’s projects.

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

The Oil Pollution Act. The Oil Pollution Act of 1990, as amended (“OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to and increases penalties for spills. The OPA establishes a new liability regime for oil pollution incidents in the aquatic environment. Essentially, the OPA provides that a responsible party for a vessel or facility from which oil is discharged or that poses a substantial threat of a discharge could be liable for certain specified damages resulting from a discharge of oil, including clean-up and remediation, loss of subsistence use of natural resources, real or personal property damages, as well as certain public and private damages. A responsible party includes a lessee of an offshore facility.

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

Clean Water Act. Generally, the Clean Water Act imposes liability for the unauthorized discharge of pollutants including petroleum products into the surface and coastal U.S. waters except in strict conformance with discharge permits issued by the federal (or state if applicable) agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. The Fund’s operators are responsible for compliance with the Clean Water Act although the Fund may be liable for any failure of the 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 of 1976, as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as theComprehensive Environmental Response, Compensation and Liability Actwhich 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, including federal, state and local laws will have a material adverse impact on its financial condition and/or operations.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

On August 16, 2006, the Manager of the Fund filed a lawsuit against the former independent registered public accounting firm for the Fund, Perelson Weiner, LLP (“Perelson”), in New Jersey Superior Court, captioned Ridgewood Energy Corporation v. Perelson Weiner, LLP, Docket No. L-6092-06. The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Fund by Perelson. Thereafter, Perelson filed a counterclaim against the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. Discovery is ongoing and no trial date has been set.

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

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

None.

PART II

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

There is currently no established public trading market for the Shares. As of the date of this filing, there were 1,619 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Fund determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. There is, however, no requirement to distribute available cash and as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 2008 and 2007, the Fund paid distributions totaling $7.4 million $0.5 million, respectively.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

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

Overview of the Fund’s Business

The Fund was organized to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders through participation in oil and natural gas exploration and development projects in the Gulf of Mexico. Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and the Fund’s operations.

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

Revenues are subject to the 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.

Subsequent Events

South Timbalier 287
In November 2007, the Fund acquired a 4.0% working interest in the exploratory well South Timbalier 287, from Apache Corporation (“Apache”), the operator. This project began drilling in March 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009. For the year ended December 31, 2008, dry-hole costs related to this well were $3.9 million. Additional dry-hole costs of $0.3 million, including plug and abandonment expenses, were incurred during the first quarter 2009.

Bison Project
In November 2008, the Fund acquired a 3.0% working interest in the Bison Project, an exploratory well, from LLOG, the operator. The Bison Project, located in the Galveston region of the Gulf of Mexico, began drilling in December 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009. For the year ended December 31, 2008, dry-hole costs related to this well, were $0.2 million. Additional dry-hole costs of $0.1 million, including plug and abandonment expenses, were incurred during the first quarter 2009.

Critical Accounting Estimates

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

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

The costs of exploratory and developmental wells are capitalized pending determination of whether proved reserves have been found. Drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense as dry-hole costs. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel; active negotiations for sales contracts with customers; negotiations with governments, operators and contractors; and firm plans for additional drilling and other factors.

Unproved Property
Unproved property is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination. These costs are initially excluded from the depletion base until the outcome of the project has been determined, or generally until it is known whether proved reserves will or will not be assigned to the property. The Fund assesses all items in its unproved property balance on an ongoing basis for possible impairment or reduction in value.

Proved Reserves
Annually, the Fund engages an independent petroleum engineer, Ryder Scott Company, L.P., to perform a comprehensive study of the Fund’s producing properties and dependent upon timing of discoveries, certain successful properties, to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenue to change. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depreciation, depletion and amortization.

Asset Retirement Obligations
For oil and 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 present value of asset retirement obligations once reasonably estimable. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of its proved properties. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.

Impairment of Long-Lived Assets
The Fund reviews long-lived assets, including oil and natural gas properties, 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 and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by undiscounted future net cash flow estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

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

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, 2008 and 2007 and should be read in conjunction with the Fund’s financial statements and the notes thereto within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.


	Year ended December 31,
	2008			2007

	(in thousands)
Revenue
Oil and gas revenue	$	11,229		$	1,883

Expenses
Depletion and amortization		3,537			701
Dry-hole costs		18,879			3,808
Management fees to affiliate		2,062			2,300
Casualty loss		—			3,193
Operating expenses		360			107
General and administrative expenses		766			603

Total expenses		25,604			10,712

Loss from operations		(14,375	)		(8,829	)
Other income
Interest income		932			2,627

Net loss	$	(13,443	)	$	(6,202	)

Year ended December 31, 2008 compared to Year ended December 31, 2007

Overview. During the year ended December 31, 2008, the Fund had three producing wells, South Pelto 9, Eugene Island 346/347 well #1 and well #2, which came onto production in September 2007, June 2008 and July 2008, respectively, thereby impacting the Fund’s revenue, depletion, amortization and lease operating expenses. Prior to September 2007, the Fund had no producing properties and was classified as an exploratory stage enterprise.

As previously discussed in the Item 1. “Business”, hurricane activity in the third quarter of 2008 did not cause material damage to any of the Fund’s wells or facilities, however, damage to certain pipelines, coastal refineries and gas processing plants have caused its wells to be shut-in for several weeks or months. Accordingly, revenue and depletion and amortization were affected in 2008 during these periods.

Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, 2008 was $11.2 million, a $9.3 million increase from the year ended December 31, 2007. The increase is attributable to an increase in production and sales volumes totaling $7.0 million and an increase in the average prices totaling $2.4 million.

The Fund’s wells produced 32 thousand barrels of oil during the year ended December 31, 2008 compared to 8 thousand barrels of oil during the year ended December 31, 2007. The Fund’s oil prices averaged approximately $100 per barrel during the year ended December 31, 2008 compared to approximately $85 per barrel during the year ended December 31, 2007.

Gas production during the year ended December 31, 2008 was 691 thousand mcf compared to 137 thousand mcf, during the year ended December 31, 2007. During the year ended December 31, 2008, the Fund’s gas prices, inclusive of processing revenue, averaged $11.57 per mcf compared to $8.84 per mcf during the year ended December 31, 2007.

The increase in production and sales volumes for the year ended December 31, 2008 was attributable to the onset of production for Eugene Island 346/347 well #1 and well #2 and a full year of production for South Pelto 9.

Depletion and Amortization. For the years ended December 31, 2008 and 2007, depletion and amortization was $3.5 million and $0.7 million, respectively. The increase in depletion and amortization resulted from the onset of production for Eugene Island 346/347 well #1 and well #2 and a full year of production for South Pelto 9.

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. During the years ended December 31, 2008 and 2007, certain wells received credits from their respective operators upon review and audit of the wells’ costs. The following table summarizes dry-hole costs, inclusive of plug and abandonment costs and credits:


	Year ended December 31,
Lease Block	2008			2007

	(in thousands)
High Island 38	$	6,715		$	—
South Timbalier 287		3,858			—
Eos Project		2,472			—
Walker Ridge 155		2,234			—
Ruby Project		1,924			—
South Marsh Island 213		1,688			—
Bison Project		215			—
Eugene Island 346/347 well #3		279			—
West Cameron 296		(112	)		2,680
West Delta 95		(380	)		1,342
Other wells		(14	)		(214	)

	$	18,879		$	3,808

Management Fees to Affiliate. For the years ended December 31, 2008 and 2007, the Fund incurred management fees of $2.1 million and $2.3 million, respectively, representing 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. See additional discussion in Item 1. “Business”.

Casualty Loss. For the year ended December 31, 2007, the Fund recorded a casualty loss of $3.2 million as a result of the settlement of its two insurance claims for West Delta 95 and West Cameron 78/95 wells. West Delta 95 recorded a casualty loss of $1.7 million for the year ended December 31, 2007 as a result of damages sustained from Hurricane Katrina. West Cameron 78/95 recorded a casualty loss of $1.5 million for the year ended December 31, 2007 as a result of damages sustained during drilling.

Operating Expenses. Operating expenses include the costs of operating and maintaining wells and related facilities, geological costs and accretion expense as detailed in the table below.


	Year ended December 31,
	2008		2007

	(in thousands)
Lease operating expense	$	245	$	61
Geological costs		107		44
Accretion expense		8		2

	$	360	$	107

Lease operating expense for the year ended December 31, 2008 related to South Pelto 9 and the onset of production of Eugene Island 346/347 well #1 and well #2. For the year ended December 31, 2007 lease operating expenses related to the onset of production of South Pelto 9. Geological costs for the year ended December 31, 2008 related primarily to the Liberty, Ruby, Eos and Cobalt projects. Geological costs for the year December 31, 2007 primarily related to South Pelto 9. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.

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


	Year ended December 31,
	2008		2007

	(in thousands)
Insurance expense	$	444	$	304
Accounting fees		233		198
Trust fees		89		101

	$	766	$	603

Insurance expense represents premiums related to producing well and well control insurance, which varies dependent upon the number of wells producing and/or drilling and director’s and officers’ liability insurance. Accounting fees represent annual audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund. Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

Interest Income.Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities. For the year ended December 31, 2008, interest income was $0.9 million, a $1.7 million decrease from the year ended December 31, 2007. The decrease was attributable to a reduction in average outstanding balances earning interest due to ongoing capital expenditures coupled with lower interest rates earned.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the year ended December 31, 2008 were $7.3 million, principally attributable to revenue receipts of $11.3 million and interest income received of $0.4 million. These amounts were partially offset by management fees of $2.1 million, MMS royalty prepayments totaling $0.5 million, payments to affiliates of $0.7 million for amounts outstanding at December 31, 2007, general and administrative expenses of $0.8 million and operating expenses of $0.4 million.

Cash flows used in operating activities for the year ended December 31, 2007 were $0.4 million, attributable to management fees of $2.3 million, general and administrative and other expenses of $0.7 million. Partially offsetting these payments were revenue receipts of $1.3 million, interest income received of $1.1 million and favorable working capital of $0.2 million.

Investing Cash Flows
Cash flows provided by investing activities for the year ended December 31, 2008 were $2.4 million related to proceeds from the maturity of U.S. Treasury securities totaling $69.1 million, partially offset by capital expenditures for oil and gas properties totaling $18.6 million and investments in U.S. Treasury securities of $48.0 million. Additionally, the Fund increased its salvage fund investments by $29 thousand, which consisted of the interest earned on this account.

Cash flows used in investing activities for the year ended December 31, 2007 were $17.7 million related to capital expenditures for oil and gas properties of $17.9 million and investments in U.S. Treasury securities of $65.3 million, partially offset by proceeds from the maturity of U.S. Treasury securities of $51.6 million as well as insurance proceeds of $13.9 million related to the West Delta 95 and West Cameron 78/95 claims. Additionally, the Fund increased its salvage fund investments by $50 thousand, which consisted of the interest earned on this account.

Financing Cash Flows
Cash flows used in financing activities were $7.4 million for the year ended December 31, 2008 related to the payment of Manager and shareholder distributions.

Cash flows used in financing activities were $0.5 million for the year ended December 31, 2007 related to the payment of Manager and shareholder distributions.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis. As of December 31, 2008, the Fund had committed to spend an additional $20.7 million related to its investment properties.

When the Manager makes a decision to participate 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 and infrastructure anticipated. If an 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.

Capital expenditures for investment properties are funded with the capital raised by the Fund in its private placement, which is more than likely, all the capital it will be able to obtain. The number of projects in which the Fund can invest will naturally be limited, and each unsuccessful project the Fund experiences will reduce its ability to generate revenue and exhaust its capital. Typically, the Manager seeks an investment portfolio that combines high and low risk exploratory projects.

Liquidity Needs

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

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, all or a portion of the management fee is paid from operating income and interest income, although the management fee can be paid out of capital contributions; however, this is not the Fund’s intent.

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

Suspension of MMS Royalty Relief

Under MMS rules, the Fund is eligible for annual royalty relief provided that the average New York Mercantile Exchange (“NYMEX”) sales price for shallow water, deep gas (“Average NYMEX Price”) does not exceed price thresholds established by the MMS, which were published during the first quarter of 2009. Rising prices early in 2008 created uncertainty as to whether or not the South Pelto 9 would be eligible for the royalty relief and accordingly, the Fund previously disclosed this contingency. Ultimately, however, the NYMEX sales price did not exceed the price thresholds established by the MMS and the Fund had no obligation to pay royalties for those properties which qualify for royalty relief.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 2008 and 2007 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 negotiate any such contracts. No contractual obligations exist at December 31, 2008 and 2007 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

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, 2008. 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, 2008. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) inInternal Control — Integrated Framework. Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2008, 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, 2008 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 2008 are as follows:


Name, Age and Position with Registrant		Officer of Ridgewood Energy Corporation Since

Robert E. Swanson, 61
President and Chief Executive Officer		1982

W. Greg Tabor, 48
Executive Vice President and
Director of Business Development		2004

Robert L. Gold, 50
Executive Vice President		1987

Kathleen P. McSherry, 43
Executive Vice President and
Chief Financial Officer		2000

Daniel V. Gulino, 48
Senior Vice President and General Counsel		2003

Adrien Doherty, 56
Executive Vice President		2006

The officers in the above table have also been officers of the Fund since December 21, 2004, the date of inception of the Fund, with the exception of Mr. Doherty, who became an officer of the Fund in 2006. The officers are employed by and paid exclusively by the Manager. Set forth below are the names of, and certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

Robert E. Swansonhas 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 and Ridgewood Capital Corporation, 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.

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

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

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

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

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

Board of Directors and Board Committees

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

Code of Ethics

The Manager of the Fund has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager of the Fund grants any waiver, including any implicit waiver, from a provision of the code to any of 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.

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, 2008, all filing requirements applicable to its officers, directors and 10% beneficial owners were met.

ITEM 11. EXECUTIVE COMPENSATION

The executive officers of the Fund do not receive compensation from the Fund. The Manager, or its affiliates, compensates the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” for more information regarding Manager compensation and payments to affiliated entities.

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

The following table sets forth information with respect to beneficial ownership of the shares as of March 12, 2009 (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 870.6486 Shares outstanding at March 12, 2009. Other than as indicated below, no officer of the Manager or the Fund owns any of the Fund’s Shares.


Name of beneficial owner	Number of shares	Percent

Robert E. Swanson, President and Chief Executive Officer (1)	2.6667	*
Executive officers as a group (1)	2.6667	*

* Represents less than one percent.

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

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

The LLC Agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for the years ended December 31, 2008 and 2007 were $2.1 million and $2.3 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund. For the years ended December 31, 2008 and 2007, the Manager was paid distributions totaling $1.1 million and $73 thousand, respectively.

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. At December 31, 2008 there were no such amounts outstanding. At December 31, 2007, the Fund owed affiliates $0.7 million related to insurance proceeds and revenue allocations.

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

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

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, 2008 and 2007.


	Year ended December 31,
	2008		2007

	(in thousands)
Audit fees (1)	$	130	$	125

(1) Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1) Financial Statements

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

(a) (2) Financial Statement Schedules

None.

(a) (3)


EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING


3.1	Articles of Formation of Ridgewood Energy O Fund, LLC dated December 21, 2004.	Incorporated by reference to the Fund’s Form 10 filed on April 21, 2006.

3.2	Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy O Fund, LLC dated February 16, 2005.	Incorporated by reference to the Fund’s Form 10 filed on April 21, 2006.

10.1	Participation Agreement between El Paso E&P Company, L.P. and Ridgewood Energy Corporation as Manager and LLOG Exploration Offshore, Inc. for South Marsh Island Block 213.	Incorporated by reference to the Fund’s Form 10-Q filed on May 6, 2008.

10.2	Participation Agreement between LLOG Exploration Offshore, Inc. and Ridgewood Energy Corporation as Manager for Liberty Project.	Incorporated by reference to the Fund’s Form 10-Q filed on August 1, 2008.

10.3	Participation Agreement between PetroQuest Energy, L.L.C. and Ridgewood Energy Corporation as Manager for Ruby Project.	Incorporated by reference to the Fund’s Form 10-Q filed on August 1, 2008.

10.4	Participation Agreement between LLOG Exploration Offshore, Inc., Mariner Energy, Inc., Stone Energy Corporation and Ridgewood Energy Corporation as Manager for Eos Project.	Incorporated by reference to the Fund’s Form 10-Q filed on November 10, 2008.

10.5	Participation Agreement between Newfield Exploration Company and Ridgewood Energy Corporation as Manager for Cobalt Project.	Filed herewith.

10.6	Participation Agreement between LLOG Offshore, Inc. and Ridgewood Energy Corporation as Manager for Bison Project.	Filed herewith.

10.7	Participation Agreement between Newfield Exploration Company and Ridgewood Energy Corporation as Manager for Aspen Project.	Filed herewith.

23.1	Consent of Ryder Scott Company, L.P.	Filed herewith.

31.1	Certification of Robert E. Swanson, Chief Executive Officer, pursuant to Securities Exchange Act Rule 13a-14(a).	Filed herewith.

31.2	Certification of Kathleen P. McSherry, Chief Financial Officer, pursuant to Securities Exchange Act Rule 13a-14(a).	Filed herewith.

32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Chief Financial Officer of the Fund.	Filed herewith.

INDEX TO FINANCIAL STATEMENTS


		PAGE

Report of Independent Registered Public Accounting Firm		F-2
Balance Sheets as of December 31, 2008 and 2007		F-3
Statements of Operations for the years ended December 31, 2008 and 2007		F-4
Statements of Changes in Members’ Capital for the years ended December 31, 2008 and 2007		F-5
Statements of Cash Flows for the years ended December 31, 2008 and 2007		F-6
Notes to Financial Statements		F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited		F-13

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying balance sheets of Ridgewood Energy O Fund, LLC (the “Fund”) as of December 31, 2008 and 2007, and the related statements of operations, changes in members’ capital, and cash flows for the years ended December 31, 2008 and 2007. These financial statements are the responsibility of the Fund’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy O Fund, LLC as of December 31, 2008 and 2007, and the results of its operations and its cash flows for the years ended December 31, 2008 and 2007, in conformity with accounting principles generally accepted in the United States of America.


/s/ Deloitte & Touche LLP


Parsippany, New Jersey
March 12, 2009

F-2

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


	December 31,
	2008			2007

ASSETS
Current assets:
Cash and cash equivalents	$	16,818		$	14,546
Short-term investments in marketable securities		20,100			40,602
Production receivable		530			598
Prepaid royalties		517			—
Other current assets		186			372

Total current assets		38,151			56,118

Salvage fund		1,139			1,110

Oil and gas properties:
Advances to operators for working interests and expenditures		128			1,866
Unproved properties		984			5,961
Proved properties		12,525			5,603
Less: accumulated depletion and amortization		(4,238	)		(701	)

Total oil and gas properties		9,399			12,729


Total assets	$	48,689		$	69,957

LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Due to operators	$	1,965		$	2,070
Accrued expenses payable		97			126
Due to affiliates (Note 6)		—			652

Total current liabilities		2,062			2,848

Asset retirement obligations		415			39

Total liabilities		2,477			2,887

Commitments and contingencies (Note 8)
Members’ capital:
Manager:
Distributions		(1,185	)		(73	)
Accumulated deficit		(428	)		(1,447	)

Manager’s total		(1,613	)		(1,520	)

Shareholders:
Capital contributions (935 shares authorized; 870.6486 issued and outstanding)		128,990			128,990
Syndication costs		(14,742	)		(14,742	)
Distributions		(6,717	)		(414	)
Accumulated deficit		(59,706	)		(45,244	)

Shareholders’ total		47,825			68,590


Total members’ capital		46,212			67,070


Total liabilities and members’ capital	$	48,689		$	69,957

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

F-3

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


	Year ended December 31,
	2008			2007

Revenue
Oil and gas revenue	$	11,229		$	1,883

Expenses
Depletion and amortization		3,537			701
Dry-hole costs		18,879			3,808
Management fees to affiliate (Note 6)		2,062			2,300
Casualty loss		—			3,193
Operating expenses		360			107
General and administrative expenses		766			603

Total expenses		25,604			10,712

Loss from operations		(14,375	)		(8,829	)
Other income
Interest income		932			2,627

Net loss	$	(13,443	)	$	(6,202	)


*Manager Interest*
Net income (loss)	$	1,019		$	(199	)

*Shareholder Interest*
Net loss	$	(14,462	)	$	(6,003	)
Net loss per share	$	(16,611	)	$	(6,895	)

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

F-4

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


	# of Shares		Manager			Shareholders			Total


Balances, December 31, 2006		870.6486	$	(1,248	)	$	75,007		$	73,759

Distributions				(73	)		(414	)		(487	)
Net loss		—		(199	)		(6,003	)		(6,202	)


Balances, December 31, 2007		870.6486		(1,520	)		68,590			67,070


Distributions				(1,112	)		(6,303	)		(7,415	)
Net income (loss)		—		1,019			(14,462	)		(13,443	)


Balances, December 31, 2008		870.6486	$	(1,613	)	$	47,825		$	46,212

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

F-5

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


	Year ended December 31,
	2008			2007


Cash flows from operating activities
Net loss	$	(13,443	)	$	(6,202	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depletion and amortization		3,537			701
Dry-hole costs		18,879			3,808
Casualty loss		—			3,193
Accretion expense		8			2
Interest earned on marketable securities		(605	)		(1,712	)
Changes in assets and liabilities:
Decrease (increase) in production receivable		68			(598	)
Increase in prepaid royalties		(517	)		—
Decrease in other current assets		7			142
Increase in due to operators		5			43
(Decrease) increase in accrued expenses payable		(29	)		29
(Decrease) increase in due to affiliates		(652	)		177

Net cash provided by (used in) operating activities		7,258			(417	)


Cash flows from investing activities
Payments to operators for working interests and expenditures		(128	)		(1,866	)
Capital expenditures for oil and gas properties		(18,521	)		(16,025	)
Proceeds from insurance recovery		—			13,908
Interest reinvested in salvage fund		(29	)		(50	)
Proceeds from the sale of marketable securities		69,107			51,613
Investment in marketable securities		(48,000	)		(65,318	)

Net cash provided by (used in) investing activities		2,429			(17,738	)


Cash flows from financing activities
Distributions		(7,415	)		(487	)

Net cash used in financing activities		(7,415	)		(487	)


Net increase (decrease) in cash and cash equivalents		2,272			(18,642	)
Cash and cash equivalents, beginning of period		14,546			33,188

Cash and cash equivalents, end of period	$	16,818		$	14,546


Supplemental schedule of non-cash investing activities

Advances used for capital expenditures in oil and gas properties reclassified to dry-hole costs	$	1,866		$	—

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

F-6

RIDGEWOOD ENERGY O FUND, LLC
NOTES TO FINANCIAL STATEMENTS

1. Organization and Purpose

The Ridgewood Energy O Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on December 21, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated February 16, 2005 by and among Ridgewood Energy Corporation (the “Manager”), and the shareholders of the Fund. The Fund was organized to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. During 2007, the Fund began earning revenue and was determined by the Manager to no longer be an exploratory stage enterprise.

The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 6 and 8.

2. Summary of Significant Accounting Policies

Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.

Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less are considered as cash and cash equivalents. At times, bank deposits may be in excess of federally insured limits. At December 31, 2008 bank balances exceeded federally insured limits by $6.5 million. At December 31, 2008, $5.7 million of the Fund’s uninsured balances were invested in money market accounts that invest solely in U.S. Treasury bills and notes. Effective October 2008 through December 31, 2009, federally insured limits have been increased from $0.1 million to $0.25 million for interest bearing deposits. Additionally, non-interest bearing deposits are fully insured during this period.

Investments in Marketable Securities
At times the Fund may invest in U.S. Treasury bills and notes. These investments are considered short-term when their maturities are greater than three months and one year or less, and long-term when their maturities are in excess of one year. At December 31, 2008, the Fund had short-term, held-to-maturity investments totaling $20.1 million, which mature in the first and second quarter of 2009. At December 31, 2007 the Fund had short-term, held-to-maturity investments totaling $40.6 million. Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.

Salvage Fund
The Fund deposits in a separate interest-bearing account, or a salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations. At December 31, 2008, the Fund had held-to-maturity investments within its salvage fund totaling $1.1 million, which mature in February 2012.

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

F-7

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

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

Upon the sale or retirement of a proved property, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized. The Manager does not currently intend to sell any of the Fund’s property interests.

Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.

As of December 31, 2008 and 2007 amounts recorded in due to operators totaling $1.9 million and $2.0 million, respectively, related to capital expenditures for oil and gas properties.

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

Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, 2008 and 2007.


	2008		2007

	(in thousands)
Balance - January 1,	$	39	$	37
Liabilities incurred		268		—
Liabilities settled		—		—
Accretion expense		8		2
Revisions to previous estimates		100		—

Balance - December 31,	$	415	$	39

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

Syndication Costs
Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.

Revenue Recognition and Imbalances
Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable.

F-8

The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the under produced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.

Impairment of Long-Lived Assets
In accordance with the provisions of the Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment of Long-Lived Assets”, long-lived assets, such as oil and 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. During the years ended December 31, 2008 and 2007, no impairments were recorded. Fair value determinations require considerable judgment and are sensitive to changes in the factors described above, thus impairments could occur in future periods.

Depletion and Amortization
Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs. The sum of proved developed and proved undeveloped reserves is used as the base for depleting, or amortizing, leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs. The Fund began production during the third quarter 2007.

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

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

3. Recent Accounting Standards

In December 2008, the Securities and Exchange Commission (“SEC”) announced final approval of new requirements for reporting oil and gas reserves. The new requirements provide for consideration of new technologies in evaluating reserves, allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations. The new rule is expected to be effective for fiscal years ending on or after December 31, 2009. The Fund had not yet evaluated the effects of these new requirements on its financial statements and disclosures.

In May 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” (“SFAS No.162”), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with GAAP. SFAS No. 162 will be effective sixty days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411. The Fund does not expect the adoption of SFAS No. 162 will have a material impact on its financial condition or results of operation.

In February 2007, 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 (i) is applied instrument by instrument, with a few exceptions; (ii) is irrevocable; and (iii) is applied only to entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 will not have a material impact on its financials. The Fund did not elect to measure existing assets and liabilities at fair value on the date of adoption.

F-9

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 non-financial assets and liabilities. On January 1, 2008, the Fund adopted SFAS No. 157 for financial assets and liabilities.

4. Unproved Properties - Capitalized Exploratory Well Costs

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves.

The following table reflects the net changes in unproved properties for the years ended December 31, 2008 and 2007. At December 31, 2008, the Fund had no capitalized exploratory well costs greater than one year.


	2008			2007

	(in thousands)
Balance - January 1,	$	5,961		$	—

Additions to capitalized exploratory well costs pending the determination of proved reserves		5,635			7,647
Reclassifications to proved properties based on the determination of proved reserves		(6,843	)		(1,686	)
Capitalized exploratory well costs charged to dry-hole costs		(3,769	)		—


Balance - December 31,	$	984		$	5,961

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. During the years ended December 31, 2008 and 2007, the Fund received credits on certain wells from their respective operators upon review and audit of the wells’ costs. Dry-hole costs, inclusive of credits, are detailed in the table below.


	Year ended December 31,
Lease Block	2008			2007

	(in thousands)
High Island 38	$	6,715		$	—
South Timbalier 287		3,858			—
Eos Project		2,472			—
Walker Ridge 155		2,234			—
Ruby Project		1,924			—
South Marsh Island 213		1,688			—
Bison Project		215			—
Eugene Island 346/347 well #3		279			—
West Cameron 296		(112	)		2,680
West Delta 95		(380	)		1,342
Other wells		(14	)		(214	)

	$	18,879		$	3,808

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5.Distributions

Distributions to shareholders are allocated in proportion to the number of shares held. Certain shares have early investment incentive and advance distribution rights, as defined in the Fund’s LLC Agreement, which range from approximately $5 thousand to $10 thousand per share.

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 required by the Fund’s LLC Agreement.

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

The Fund began making distributions to eligible early investors in December 2007 and to all investors in October 2008. During the year ended December 31, 2008, Manager and shareholders distributions totaled $1.1 million and $6.3 million, respectively. During the year ended December 31, 2007, Manager and shareholders distributions totaled $0.1 million and $0.4 million, respectively.

6. Related Parties

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

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

7. Fair Value of Financial Instruments

At December 31, 2008 and 2007, the carrying value of cash and cash equivalents, short-term investments in marketable securities, salvage fund, production receivable and accrued expenses approximated fair value.

8. Commitments and Contingencies

Capital Commitments
The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2008, the Fund had committed to spend an additional $20.7 million related to its investment properties.

Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and 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, 2008 and 2007, there were no known environmental contingencies that required the Fund to record a liability.

F-11

Insurance Coverage
The Fund is subject to all risks inherent in the exploration for and development of oil and gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds can reduce or eliminate insurance for the Fund.

West Delta 95
In 2005, the Fund acquired a 28.05% working interest in West Delta 95. In August 2005, before reaching its target depth, the project was evacuated in preparation for Hurricane Katrina. As a result of Hurricane Katrina, the well sustained damage. On April 15, 2006, recovery operations began, but were suspended in July 2006 as a result of the onset of hurricane season. Recovery operations totaling $12.9 million were completed and drilling resumed in January 2007. The Fund filed a claim with its insurance carrier for these recovery amounts and, in 2007, received $11.2 million as settlement of the claim. During 2007, the Fund recorded a casualty loss of $1.7 million as a result of changes in estimates to, and the ultimate settlement of, the insurance claim. In February 2007, the well was determined to not have commercially productive quantities of either natural gas or oil and therefore was deemed to be a dry-hole.

West Cameron 78/95
In 2006, the Fund acquired a 30% working interest in West Cameron 78/95. The well began drilling on April 21, 2006. Drilling went according to plan until the drill string became stuck. The smaller drill pipe was recovered and the well was sidetracked, or re-drilled. Drilling continued until the well was determined to be a dry-hole. In July 2006 the decision was made to plug and abandon the well. During 2006, the Fund recorded a casualty loss of $0.2 million related to the insurance deductible for this claim. During 2007, the Fund recorded an additional casualty loss of $1.5 million as a result of changes in estimates to, and the ultimate settlement of, the insurance claim. The Fund received proceeds of $2.3 million for the settlement of this claim during the fourth quarter of 2007.

Suspension of MMS Royalty Relief
Under Mineral Management Services (“MMS”) rules, the Fund is eligible for annual royalty relief provided that the average New York Mercantile Exchange (“NYMEX”) sales price for shallow water, deep gas (“Average NYMEX Price”) does not exceed price thresholds established by the MMS, which were published during the first quarter of 2009. Rising prices early in 2008 created uncertainty as to whether or not South Pelto 9 would be eligible for the royalty relief and accordingly, the Fund previously disclosed this contingency. Ultimately, however, the NYMEX sales price did not exceed the price thresholds established by the MMS and the Fund had no obligation to pay royalties for those properties which qualify for royalty relief.

9. Subsequent Events

South Timbalier 287
In November 2007, the Fund acquired a 4.0% working interest in the exploratory well South Timbalier 287, from Apache Corporation, the operator. This project began drilling in March 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009. For the year ended December 31, 2008, dry-hole costs related to this well, including plug and abandonment expenses, were $3.9 million. Additional dry-hole costs of $0.3 million, including of plug and abandonment expenses, were incurred during the first quarter 2009.

Bison Project
In November 2008, the Fund acquired a 3.0% working interest in the Bison Project, an exploratory well, from LLOG Exploration Offshore, Inc., the operator. The Bison Project, located in the Galveston region of the Gulf of Mexico, began drilling in December 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009. For the year ended December 31, 2008, dry-hole costs related to this well were $0.2 million. Additional dry-hole costs of $0.1 million, including plug and abandonment expenses, were incurred during the first quarter 2009.

F-12

Ridgewood Energy O Fund, LLC
Supplementary Financial Information
Information about Oil and Gas Producing Activities - Unaudited

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

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

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


	December 31,
	2008			2007

	(in thousands)
Advances to operators for working interests and expenditures	$	128		$	1,866
Unproved properties		984			5,961
Proved properties		12,525			5,603

Total oil and gas properties		13,637			13,430
Accumulated depletion and amortization		(4,238	)		(701	)

Oil and gas properties, net	$	9,399		$	12,729

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


	Year ended December 31,
	2008		2007

	(in thousands)
Exploratory drilling costs - capitalized	$	5,709	$	13,947
Developmental drilling costs-capitalized		133		—
Exploratory drilling costs - expensed		13,244		3,808
Geological costs		107		44

	$	19,193	$	17,799

F-13

Table III - Reserve Quantity Information

As of December 31, 2008 and 2007, oil and gas reserve data for the producing properties of the Fund was estimated by an independent petroleum engineer, Ryder Scott Company. As of December 31, 2008, the Fund had one non-producing property for which reserve data is based upon internal estimates. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.


	December 31, 2008						December 31, 2007

				United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)


Proved developed and undeveloped reserves:
Beginning of year		32,443			931,000			139,320			2,786,403
Discoveries		43,989			687,543			—			—
Revisions of previous estimates		27,035			795,858			(99,026	)		(1,718,072	)
Production		(32,425	)		(690,613	)		(7,851	)		(137,331	)

End of year		71,042			1,723,788			32,443			931,000


Proved developed reserves:
Beginning of year		32,443			931,000			139,320			2,786,403
Discoveries		22,537			352,743			—			—
Revisions of previous estimates		27,035			795,858			(99,026	)		(1,718,072	)
Production		(32,425	)		(690,613	)		(7,851	)		(137,331	)

End of year		49,590			1,388,988			32,443			931,000

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

Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Fund’s proved reserves to the year-end quantities of those reserves. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.


	December 31,
	2008			2007

	(in thousands)
Future estimated revenues	$	13,670		$	11,096
Future estimated production costs		(935	)		(684	)
Future estimated development costs		(1,745	)		—

Future net cash flows		10,990			10,412
10% annual discount for estimated timing of cash flows		(1,646	)		(1,350	)

Standardized measure of discounted future estimated net cash flows	$	9,344		$	9,062

F-14

Table V - Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

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


	Year ended December 31,
	2008			2007

	(in thousands)
Standardized measure beginning of the year	$	9,062		$	16,248
Sales of oil and gas production, net of production costs		(10,921	)		(1,822	)
Net changes in prices and production costs		(2,559	)		4,823
Extensions, discoveries, and improved recovery and techniques, less related costs		3,638			—
Development costs incurred during the period		—			1,581
Revisions of previous reserve quantities estimate		8,683			(15,737	)
Accretion of discount		906			798
Timing and other		535			3,171

Standardized measure end of the year	$	9,344		$	9,062

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

F-15

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 O FUND, LLC

Date: March 12, 2009	By:	/s/ ROBERT E. SWANSON

		Robert E. Swanson
		Chief Executive Officer
		(Principal Executive Officer)

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


Signature	Capacity	Date

/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)	March 12, 2009
>
Robert E. Swanson

/s/ KATHLEEN P. McSHERRY	Executive Vice President and Chief Financial Officer (Principal Accounting Officer)	March 12, 2009
>
Kathleen P. McSherry

RIDGEWOOD ENERGY CORPORATION

/s/ ROBERT E. SWANSON	Chief Executive Officer of Manager	March 12, 2009
>
Robert E. Swanson

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Avg

Ridgewood Energy O Fund 10-K2008 FY Annual report

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