---

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

FORM 10-K

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


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


For the transition period from _____ to _____

Commission File No. 000-51924

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

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

1314 King Street, Wilmington, Delaware 19801(Address of principal executive offices) (Zip
code)

(302)
888-7444(Registrants telephone number, including area code)

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

Shares of LLC Membership Interest

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

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

|                                                                                                                                                                                                                                                                                                                                                                               | 
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | 
|Indicate by check mark
  whether the registrant (1) has filed all reports required to be filed by
  Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
  preceding 12 months (or for such shorter period that the registrant was
  required to file such reports) and (2) has been subject to
  such filing requirements for the past 90 days. Yes x   No o
|                                                                                                                                                                                                                                                                                                                                                                               | 
|Indicate by check mark 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). Yes o   No x

There is no market for the
shares. As of March 21, 2008 there are 870.6486 shares outstanding.

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

|         |         |                                                                                                                     |     
|-------- | ------- | ------------------------------------------------------------------------------------------------------------------- | ----
|         |         |                                                                                                                     | PAGE
|         |         |                                                                                                                     |     
|         |         |                                                                                                                     |     
|PART I   |         |                                                                                                                     |     
|         | ITEM 1  | BUSINESS                                                                                                            | 2   
|         | ITEM 1A | RISK FACTORS                                                                                                        | 12  
|         | ITEM 1B | UNRESOLVED STAFF COMMENTS                                                                                           | 12  
|         | ITEM 2  | PROPERTIES                                                                                                          | 12  
|         | ITEM 3  | LEGAL PROCEEDINGS                                                                                                   | 12  
|         | ITEM 4  | SUBMISSION OF MATTERS TO A VOTE OF SECURITY
  HOLDERS                                                               | 12  
|PART II  |         |                                                                                                                     |     
|         | ITEM 5  | MARKET FOR REGISTRANTS COMMON EQUITY, RELATED
  SECURITY HOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES | 12  
|         | ITEM 6  | SELECTED FINANCIAL DATA                                                                                             | 14  
|         | ITEM 7  | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
  CONDITION AND RESULTS OF OPERATIONS                             | 14  
|         | 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                                                                                                   | 21  
|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 SECURITY HOLDER MATTERS                | 22  
|         | ITEM 13 | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
  AND DIRECTOR INDEPENDENCE                                          | 23  
|         | ITEM 14 | PRINCIPAL ACCOUNTANT FEES AND SERVICES                                                                              | 23  
|PART IV  |         |                                                                                                                     |     
|         | ITEM 15 | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES                                                                          | 24  
|         |         |                                                                                                                     |     

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FORWARD-LOOKING STATEMENTS

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

AVAILABLE INFORMATION

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

REPORTS TO SHAREHOLDERS

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

WHERE YOU CAN GET MORE INFORMATION

The Fund files
annual, quarterly and current reports and certain other information with the
SEC. Persons may read and copy any documents the Fund files at the SECs public
reference room at 100 F Street, NE, Washington D.C. 20549. Information may be
obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet
site that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the SEC at
http://www.sec.gov. A copy of any such filings will be provided free of charge
to any shareholder upon written request to the Fund at its business address 947
Linwood Avenue, Ridgewood, New Jersey 07450, ATTN: General Counsel.

1

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PART
I

ITEM 1. BUSINESS

Overview

The Fund is a
Delaware limited liability company formed on December 21, 2004 to acquire
interests primarily in oil and natural gas projects located in the U.S. waters
of the Gulf of Mexico. Ridgewood Energy Corporation, a Delaware corporation, is
the Manager. As the Manager, Ridgewood Energy has direct and exclusive control
over the management and control of Fund operations.

The Fund
initiated its private placement offering on February 16, 2005, selling whole
and fractional shares of membership interests primarily at $150 thousand per
share. There is no public market for these shares and one is not likely to
develop. In addition, the shares are subject to severe restrictions on transfer
and resale and cannot be transferred or resold except in accordance with the
Funds limited liability company agreement (LLC agreement) and applicable
federal and state securities laws. The offering was terminated on June 30,
2005. The Fund raised $129.0 million. As of March 21, 2008, the Fund had 1,613
shareholders.

Manager

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

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

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

As
compensation for their management services, the Manager is entitled to an
annual Management Fee, payable monthly, equal to 2.5% of the total capital
contributions made by the Funds shareholders, net of cumulative dry-hole
expenses incurred by the Fund. The Fund paid the Manager for its management
services fees totaling $2.3 million and $3.2 million for the years ended
December 31, 2007 and 2006, respectively. Additionally, the Manager receives a
15% interest in the cash distributions made by the Fund. The Manager was paid
$0.1 million in distributions in 2007. There were no cash distributions paid in
2006.

Business Strategy

The Funds
primary investment objective is to generate cash flow from the acquisition,
exploration, production and sale of crude oil and natural gas from oil and
natural gas projects. The Fund has invested and participates in exploration and
production projects located in the waters of the Gulf of Mexico offshore Texas,
Louisiana and Alabama on the Outer Continental Shelf (OCS). These activities
are governed by the Outer Continental Shelf Lands Act (OCSLA) enacted in 1953
and administered by the Mineral Management Services (MMS). The Fund generally
looks to invest in projects that have been proposed by larger independent oil
and natural gas companies seeking to minimize their risks by selling a portion
of their interest in a project. These investments may require the Fund to pay a
disproportionate part of the drilling costs on the exploratory well of a
project than its ownership interest would otherwise require. This is called a
promote and is common in the oil and natural gas exploration industry. In
addition, notwithstanding the sale of an interest to the Fund, the seller may
retain a right for some period of time to payments from sales of oil and
natural gas production from a well or project. This is called an overriding
interest, which is also relatively common in this industry. Notwithstanding any
such promote or overriding interest, the Fund has tried to invest in projects
that it believes contain sufficient commercial quantities of oil or natural gas
and which are near (i) existing oil or natural gas gathering and processing
infrastructure and (ii) developed markets where the Fund can sell its oil or
natural gas.

2

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The
Fund tries to focus on projects that have significant reserve potential and are
projected to have the shortest time period from investment to first production.
However during 2007, the Fund participated in one project, Walker Ridge 155,
which is considered a deepwater project that will have a longer drilling period
as well as a longer period of time between initial investment and first production,
if successful. The Fund does not operate these projects, and although it has a
vote, it is not in control of the schedule pursuant to which its projects are
developed and completed. Moreover, when performing due diligence with respect
to a project, the Fund must rely on the independent reservoir engineers who are
hired and paid, in most cases, by the operator. The Fund does engage certain
consultants to examine and review such reserve estimates and seismic
information on its behalf.

Managers Investment Committee and Investment
Criteria

The New Jersey
office has five executives on the investment committee, three of whom have been
working together at Ridgewood Energy for over twenty years. The Houston office,
which opened in 2003, has four executives on the investment committee who
provide operational, scientific and technical oil and gas expertise. In
considering projects, the Manager and investment committee investigates each
such project against a list of factors that it believes will result in the selection
of projects that have the highest probability of success. These factors, in no
particular order, include, but are not limited to, the following (i) targeting
projects that have or are expected to have operators with significant resources
and experience in oil and gas exploration; (ii) targeting projects that have or
are expected to have partners that also have significant resources and
experience in oil and gas exploration; (iii) technical quality of the project
including its geology, seismic profile, locational trends, and whether the
project has potential for multiple prospects; (iv) oil or gas reserve
potential; (v) whether and the extent to which the operator participates as a
working interest owner in the project; (vi) economic factors, such as potential
revenues from the project, the rate of return, and estimated time to first
production; (vii) risk factors associated with exploration, as more fully
described in this filing; (viii) existence of drilling rigs, platforms and
other infrastructure, at or nearby the project; (ix) proposed drilling
schedule; (x) terms of the proposed transaction, including contractual
restrictions and obligations and lease term; and (xi) overall cost of the
project.

Properties

The Fund owns
working interests and has participated in the drilling of eleven wells, five of
which have been determined to be dry-holes, four that are currently drilling or
scheduled to drill, and two that have been determined to have proved reserves.

3

---



|                                   |  |                 |  |          |   |                                   |  |                   |  |                             |           |                                            |  |        |  |  |   |       |  |  |  |   |        |  | 
|---------------------------------- |  | --------------- |  | -------- | - | --------------------------------- |  | ----------------- |  | --------------------------- | --------- | ------------------------------------------ |  | ------ |  |  | - | ----- |  |  |  | - | ------ |  | 
|Lease
  Block                      |  | WorkingInterest |  | Operator |   | Off-shoreLocation inGulf ofMexico |  | TargetDepth(Feet) |  | Drilling Risk(in thousands) |           | Total Spentthrough12/31/2007(in thousands) | 
|                                   |  |                 |  |          |   |                                   |  |                   |  |                             |           |                                            | 
|Currently Drilling/Future Projects |  |                 |  |          |   |                                   |  |                   |  |                             |           |                                            |  |        |  |  |   | (a)   |  |  |  |   |        |  | 
|Walker Ridge 155                   |  |                 |  | 1.00     | % |                                   |  | Anadarko          |  |                             | Louisiana |                                            |  | 32,000 |  |  | $ | 3,470 |  |  |  | $ | 2,155  |  | 
|High Island 38                     |  |                 |  | 12.50    | % |                                   |  | W&T
  Offshore    |  |                             | Texas     |                                            |  | 15,100 |  |  | $ | 4,000 |  |  |  | $ | 3,480  |  | 
|Mississippi Canyon 360             |  |                 |  | 10.00    | % |                                   |  | Challenger        |  |                             | Louisiana |                                            |  | 11,000 |  |  | $ | 4,370 |  |  |  | $ | 90     |  | 
|South Timbalier 287                |  |                 |  | 4.00     | % |                                   |  | Apache            |  |                             | Louisiana |                                            |  | 20,000 |  |  | $ | 1,790 |  |  |  | $ |       |  | 
|Successful Property                |  |                 |  |          |   |                                   |  |                   |  |                             |           |                                            |  |        |  |  |   |       |  |  |  |   |        |  | 
|South Pelto 9                      |  |                 |  | 16.67    | % |                                   |  | McMoRan           |  |                             | Louisiana |                                            |  | 17,700 |  |  |   | N/A   |  |  |  | $ | 5,566  |  | 
|Eugene Island 346/347              |  |                 |  | 5.00     | % |                                   |  | McMoRan           |  |                             | Louisiana |                                            |  | 12,900 |  |  |   | N/A   |  |  |  | $ | 2,101  |  | 
|Dry Holes (b)                      |  |                 |  |          |   |                                   |  |                   |  |                             |           |                                            |  |        |  |  |   |       |  |  |  |   |        |  | 
|West Cameron 296                   |  |                 |  | 16.67    | % |                                   |  | Newfield          |  |                             | Louisiana |                                            |  | 13,500 |  |  |   | N/A   |  |  |  | $ | 2,680  |  | 
|West Delta 95                      |  |                 |  | 28.05    | % |                                   |  | Apache            |  |                             | Louisiana |                                            |  | 17,900 |  |  |   | N/A   |  |  |  | $ | 16,508 |  | 
|West Cameron 78/95                 |  |                 |  | 30.00    | % |                                   |  | El
  Paso         |  |                             | Louisiana |                                            |  | 14,500 |  |  |   | N/A   |  |  |  | $ | 4,343  |  | 
|Eugene Island 334                  |  |                 |  | 33.33    | % |                                   |  | Devon             |  |                             | Louisiana |                                            |  | 17,000 |  |  |   | N/A   |  |  |  | $ | 9,149  |  | 
|Eugene Island 357                  |  |                 |  | 18.00    | % |                                   |  | Newfield          |  |                             | Louisiana |                                            |  | 15,500 |  |  |   | N/A   |  |  |  | $ | 4,376  |  | 

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

Currently Drilling/Future Projects

Walker
Ridge 155In 2007 the Fund acquired a 1.0% working interest
in the exploratory project Walker Ridge 155 from Kerr-McGee Oil & Gas
Corporation (Kerr McGee), a wholly owned subsidiary of Anadarko Petroleum
Corporation (Anadarko), the operator of the project. Drilling for Walker
Ridge 155, a deepwater project began in mid-August 2007.

While drilling
the initial well, Anadarko found traces of oil throughout much of the
4,500-foot interval as well as a thin section of high-quality oil. However,
this initial well did not encounter the sedimentary formations that had been
targeted. As a result, the working interest owners are evaluating additional
three-dimensional data gathered during the drilling phase as well as new data
to determine whether the operator should divert the well to a location more
likely to encounter commercial reservoirs. The operator plans to re-use the
majority of the initial well-bore in order to save time and money. Although
encouraged by the data gathered thus far, which confirms the presence of oil in
the geologic basin, the well has not been determined to be a successful property.
Once diverted to a new location, if the well is not deemed commercial, it will
be plugged and abandoned as a dry hole. Through December 31, 2007, the Fund has
spent $2.2 million related to this property, for which the total estimated
budget is $14.4 million.

High
Island 38In the
fourth quarter 2007, the Fund acquired a 12.5% working interest in the High
Island 38 project, which is operated by W&T Offshore, Inc. (W&T
Offshore). Total budgeted expenditures for this project are $6.5 million, of
which $3.5 million has been spent through December 31, 2007. Results for this
property are expected during the second quarter of 2008.

Mississippi
Canyon 360In the third quarter 2007, the Fund acquired a 10%
working interest in Mississippi Canyon 360 from Andex Resources, L.L.C. and
Howard Energy Co., Inc. The operator of this property is Challenger Minerals
Inc. (Challenger). This property was originally scheduled to begin drilling
in October 2007. Due to new safety regulations regarding drilling during hurricane
season adopted by the Minerals Management Service, the federal agency that
regulates offshore oil and gas exploration, drilling has been delayed. The
property is currently expected to begin drilling in the second quarter of 2008.
Through December 31, 2007, the Fund has spent $0.1 million related to this
property, for which the total estimated budget is $10.0 million.

4

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South Timbalier
287In November 2007,
the Fund acquired a 4.0% working interest in the exploratory project South
Timbalier 287 from GOM Shelf LLC (Apache Corporation) (Apache), the operator.
South Timbalier 287 is located southwest of the Mississippi River Delta in
about 480 feet of water. This project is expected to start drilling in April
2008. The total estimated budget for South Timbalier 287 is $2.6 million. The
Fund has not made any expenditures toward this project at December 31, 2007.

Successful Properties

South
Pelto 9In July 2006, the Fund acquired a 16.67% working
interest from Newfield Exploration Company (Newfield). South Pelto 9 was
deemed successful in late-2006 and production commenced in late-August 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 Fund has spent $5.6 million on this property.

Eugene
Island 346/347In March 2007, the Fund acquired a 5% working
interest in the exploratory project Eugene Island 346/347 from Newfield, the
operator. In June 2007, the well was deemed successful. In August 2007,
Newfield sold its interest in this property to McMoRan. At that time, McMoRan
assumed Newfields responsibilities as the operator of this property.
Completion is ongoing and production is expected in the second quarter 2008.
Through December 31, 2007, the Fund has spent $2.1 million related to this
property, for which the total estimated budget is $3.0 million.

Dry Holes

West
Cameron 296In the third quarter 2007, the Fund acquired a
16.67% working interest in 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 natural gas or oil and has been deemed an unsuccessful well or dry hole.
As a result of the dry hole, the Fund concluded that a charge for impairment of
its working interest in the West Cameron 296 lease block was required and the well
was plugged and abandoned, resulting in a charge of $2.7 million in the fourth
quarter of 2007.

West
Delta 95The Fund acquired a 20% working interest in West
Delta 95 from Apache, and an 8.05% working interest from 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. On May 11, 2005 the first
exploratory well began drilling. 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 and received $11.2 million of insurance proceeds.
The Fund recorded casualty losses totaling $1.8 million related to the
deductible, changes in estimates to, and the ultimate settlement of, this
insurance claim.

On February
12, 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. As a result of the dry-hole, West Delta 95 was plugged and abandoned.
The abandonment and impairment resulted in a charge of $15.2 million in the
fourth quarter 2006 and $1.3 million in 2007, bringing the total dry-hole costs
to $16.5 million, net of insurance recovery amounts.

5

---



West Cameron 78/95The Fund
acquired a 30% working interest from the Operator, El Paso Production Company
(El Paso). The well began drilling on April 21, 2006. Drilling went according
to plan until the well reached a depth of 10,781 feet on May 17, 2006 when the
drill string became stuck. The smaller drill pipe was recovered and the well
was sidetracked (re-drilled) at a depth of 4,880 feet. Drilling continued to
14,500 feet, at which point the well was determined to be a dry-hole. On July
6, 2006 the decision was made to plug and abandon the well. Dry-hole costs
including plug and abandonment expenses incurred by the Fund for the year ended
December 31, 2006, totaled $4.4 million, net of insurance recovery amounts. The
Fund recorded casualty losses totaling $1.7 million related to the deductible,
changes in estimates to, and the ultimate settlement of, this insurance claim.
The Fund received proceeds of $2.3 million for the settlement of this claim
during the fourth quarter of 2007.

Eugene Island 357The Fund
acquired an 18% working interest from Newfield, the operator. In consideration
of this interest, the Fund paid a promote of 1.32 to 1 on total drilling costs.
The well had two targets; one at 14,500 feet and one at 15,500 feet and if
successful, there was a smaller third target at 16,500 feet which was the
planned total depth of the well. The well began drilling on January 10, 2006.
Newfield encountered problems with lost circulation and rig repairs. Evaluation
of the well at both 14,500 feet and 15,500 feet indicated both zones contained
sands with saltwater and not hydrocarbons. On March 20, 2006, the decision was
made to plug and abandon the well. Dry-hole costs including plug and
abandonment expenses incurred by the Fund were $4.4 million, of which $4.1
million were incurred during the year ended December 31, 2006.

Eugene Island 334The Fund
acquired a 33.33% working interest from the operator, Devon Energy Production
Co. LP (Devon). The well began drilling on March 25, 2006 and on May 22, 2006
the decision was made to plug and abandon the well. Dry-hole costs including
plug and abandonment expenses incurred by the Fund totaled $9.1 million, of
which $9.0 million were incurred during the year ended December 31, 2006.

Working Interest in
Oil and Natural Gas LeasesExisting
projects, and future projects, if any, are expected to be located in the waters
of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS.
The OCSLA, which was enacted in 1953, governs certain activities with respect
to working interests and the exploration of oil and natural gas in the OCS. See
further discussion under the heading Regulation.

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

The winning
bidder(s) at the lease sale, or the lessee(s), are given a lease by the MMS
that grants such lessee(s) the exclusive right to conduct oil and natural gas
exploration and production activities within a specific lease block. Leases in
the OCS are generally issued for a primary lease term of 5, 8 or 10 years
depending on the water depth of the lease block. The 5-year lease term is for
blocks in water depths generally less than 400 meters, 8 years for depths
between 400 meters to 800 meters and 10 years for depths in excess of 800
meters. During this primary lease term, except in limited circumstances,
lessees are not subject to any particular requirements to conduct exploratory
or development activities. However, once a lessee drills a well and begins
production, the lease term is extended for the duration of commercial
production.

The lessee of
a particular block, for the term of the lease, has the right to drill and
develop exploratory wells and conduct other activities throughout the block. If
the initial well on the block is successful, a lessee (or third-party operator
for a project) may conduct additional geological studies and may determine to drill
additional or development wells. If a development well is to be drilled in the
block, each lessee owning working interests in the block must be offered the
opportunity to participate in, and cover the costs of, the development well up
to that particular lessees working interest ownership percentage.

6

---



Generally, working interests
in an offshore gas lease under the OCSLA pay a 16.67% royalty to the MMS for
shallow-water projects, and a 12.5% royalty to the MMS for deepwater projects,
such as Walker Ridge 155. Therefore, the net revenue interest of the holders of
100% of the working interest in the projects in which the Fund will invest is
83.33% for shallow-water projects and 87.5% for deepwater projects of the total
revenue of the project, and, is further reduced by any other royalty burdens
that apply to a lease block. However, as described below, the MMS has adopted
royalty relief for existing OCS leases for those who drill deep oil and natural
gas projects.

Mineral Management Services Deep Natural Gas
Royalty Incentive

On January 26,
2004, the MMS promulgated a rule providing incentives for companies to increase
deep oil and natural gas production in the Gulf of Mexico (the Royalty Relief
Rule). Under the Royalty Relief Rule, lessees will be eligible for royalty
relief on their existing leases if they drill and perforate wells for new and
deeper reserves at depths greater than 15,000 feet subsea. In addition, an even
larger royalty relief would be available for wells drilled and perforated deeper
than 18,000 feet subsea. It should be noted that the Royalty Relief Rule does
not extend to deep waters of the Gulf of Mexico off the continental shelf nor
does it apply if the price of natural gas exceeds $10.19 Million British
Thermal Units (mmbtu) adjusted annually for inflation. The Royalty Relief
Rule is limited to leases in a water depth less than 656 feet, or 200 meters.

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

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

Oil and Natural Gas AgreementsThe 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. The Manager believes that it is likely that oil and
natural gas from the Funds future projects will have access to pipeline
transportation and can be marketed in a similar fashion. Upon completion,
production from future projects may use existing capacity on existing pipelines.
As mentioned above under the heading Managers Investment Committee and
Investment Criteria, as part of the Managers review of a potential project,
access to existing transportation infrastructure is an extremely important
factor, as the existence of such infrastructure enables production from a
successful well to get to market quickly. The Fund is currently investing in
one project, Walker Ridge 155, which, if successful, will need to build
additional infrastructure, thereby extending the amount of time from drilling
to production.

Operator

The projects in which the Fund has invested
are operated and controlled by unaffiliated third-party entities acting as
operators (the Operators). The Operators are responsible for drilling,
administration and production activities for leases jointly owned by working
interest owners and acts on behalf of all working interest owners under the
terms of the applicable offshore operating agreements. In certain
circumstances, Operators will enter into agreements with independent
third-party subcontractors and suppliers to provide the various services
required for operating leases. Currently, the Funds projects are operated by
Anadarko, Apache, Challenger, McMoRan, and W&T Offshore.

7

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

Insurance

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

Salvage Fund

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

Seasonality

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

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

8

---



The Manager
has had past experiences that indicate the typical interruption in operations resulting
from a hurricane that does not result in significant damage may be
approximately three to seven days. The Manager has experienced the range of
possible interruptions in operations due to hurricanes from as little as no
damage and no interruptions to significant damage and extended interruptions.
However, it is impossible to predict whether and to what extent hurricanes and
damage may occur and to what projects. The West Delta 95 project, which was the
only project owned by the Fund that sustained significant damage or operational
interruption as a result of the 2005 hurricane season, incurred $13.0 million
of recovery costs. In January 2007, after an 18 month delay, West Delta 95 was
able to be re-drilled, resulting in a dry-hole determination in February 2007.

Customers

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

Energy Prices

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

Competition

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

In many
instances, the Fund competes for projects with large independent oil and
natural gas producers who generally have significantly greater access to
capital resources, have a larger staff, and more experience in oil and natural
gas exploration and production than the Fund. As a result, these larger
companies are in a position that they could outbid the Fund for a project.
However, because these companies are so large and have such significant
resources, they tend to focus more on projects that are larger, have greater
reserve potential, but cost significantly more to explore and develop. These
larger projects increasingly tend to be projects in the deepwater areas of the
Gulf of Mexico and the North Sea off the coast of Great Britain. However, the
focus of these companies on larger projects does not necessarily mean that they
will not investigate and/or acquire smaller projects in shallow waters for
which the Fund 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.

9

---



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 Natural Gas/Oil

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

10

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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 Operators responsibility for
compliance, in the event of an oil spill, the Fund, along with the operator and
other working interest owners, could be liable under the OPA for the resulting
environmental damage.

Clean Water Act. Generally, the Clean Water
Act imposes
liability for the unauthorized discharge of pollutants including petroleum
products into the surface and coastal U.S. waters except in strict conformance
with discharge permits issued by the federal (or state if applicable) agency.
Regulations governing water discharges also impose other requirements, such as
the obligation to prepare spill response plans. The Funds Operators are
responsible for compliance with the Clean Water Act although the Fund may be liable
for any failure of the 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 the Resource Conservation and Recovery
Act, which regulates the generation, transportation, treatment,
storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation
and Liability 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.

11

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

|         |             
|-------- | ------------
|ITEM 1A. | RISK FACTORS

Not required.

|         |                          
|-------- | -------------------------
|ITEM 1B. | UNRESOLVED STAFF COMMENTS

Not
applicable.

|        |           
|------- | ----------
|ITEM 2. | PROPERTIES

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

|        |                  
|------- | -----------------
|ITEM 3. | LEGAL PROCEEDINGS

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

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

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

None.

PART
II

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

Market Price of Shares, Distributions and Related Shareholder
Matters

There is currently no
established public trading market for the Shares. As of the date of this
filing, there were 1,613 shareholders of record of the Fund. The Fund began
paying distributions in December 2007, which totaled $0.5 million.

Participation in Costs and Revenues

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

| |   |                                                                                
| | - | -------------------------------------------------------------------------------
| |  | determine
  what cash flow will be available for distributions to shareholders,
| |  | distribute
  available cash flow,                                              
| |  | give the
  Manager a share of cash flow, if available,                         
| |  | handle
  returns of capital contributions,                                     
| |  | allocate
  income and deductions for tax purposes, and                         
| |  | maintain
  capital accounts for shareholders.                                  

12

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

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

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

Available Cash from Operations is all other available cash.

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

Distributions from Operations

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

Distributions of
Available Cash from Capital Transactions

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

| |   |                                                                                                                                                                                                           
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Before shareholders have received total distributions equal to their
  capital contributions, 99% of Available Cash from Capital Transactions will
  be distributed to shareholders and 1% to the Manager.
| |   |                                                                                                                                                                                                           
| |  | After shareholders have received total distributions equal to their
  capital contributions, 85% of Available Cash from Capital Transactions will
  be distributed to shareholders and 15% to the Manager.

General Distribution
Provisions

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

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

Return of Capital
Contributions

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

Capital Accounts and
Allocations

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

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

13

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|                                | 
|------------------------------- | 
|ITEM 6. SELECTED FINANCIAL DATA

Not required.

|                                                                                               | 
|---------------------------------------------------------------------------------------------- | 
|ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
 RESULTS OF OPERATIONS

Overview of the Funds Business

The Fund is an
independent oil and natural gas producer. The Funds primary investment
objective is to generate cash flow for distribution to its shareholders through
participation in oil and natural gas exploration and development projects in
the Gulf of Mexico. Since inception in December 2004, the Fund has acquired an
interest in eleven offshore projects and has participated in the drilling of
eleven wells. The Fund was notified by project operators that five projects
resulted in dry-holes. Two properties, Eugene Island 346/347 and South Pelto 9
were determined to be commercially successfully in May 2007 and November 2006,
respectively. South Pelto 9 began producing in September 2007 and Eugene Island
346/347 is expected to begin producing in the second quarter of 2008.

The Manager
performs certain duties on the Funds behalf including the evaluation of
potential projects for investment and ongoing administrative and advisory
services associated with these projects. The Fund does not currently, nor is
there any plan to operate any project in which the Fund participates. The Manager
enters into operating agreements with third-party operators for the management
of all exploration, development and producing operations, as appropriate. As
compensation for the above duties, the Manager is paid a one time investment
fee (4.5% of capital raised) for the evaluation of projects on the Funds
behalf and an annual management fee (2.5% of capital contributions, net of
cumulative dry-hole costs), payable monthly, for ongoing administrative and
advisory duties as well as reimbursement of expenses. The Manager also
participates in distributions. See also Item 1. Business.

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.

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

Accounting for Exploration and Development
Costs

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

14

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

Proved
Reserves

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

Unproved
Properties

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

Asset
Retirement Obligations

For oil and
natural gas properties, there are obligations to perform removal and
remediation activities when the properties are retired. When a project reaches
drilling depth and is determined to be either proved or dry, a liability is
recognized for the fair value of legally required asset retirement obligations
once it can be reasonably estimated. The Fund capitalizes the associated asset
retirement costs as part of the carrying amount of the long-lived assets. Plug
and abandonment costs associated with unsuccessful projects are expensed as
dry-hole costs.

Impairment of Long-Lived Assets

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

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

15

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Results of Operations

The following review of operations
for the years ended December 31, 2007 and 2006 should be read in
conjunction with the Funds financial statements and the notes thereto within
Item 8. Financial Statements and Supplementary Data contained in this Annual
Report.

|                                          |  |                         |        |      |   |         |  
|----------------------------------------- |  | ----------------------- | ------ | ---- | - | ------- | -
|                                          |  | Year ended December 31,
|                                          |  | 2007                    |        | 2006 |  
|                                          |  |                         |        |      |   |         |  
|                                          |  | (in
 thousands)        
|Revenue                                   |  |                         |        |      |   |         |  
|Oil and gas revenue                       |  | $                       | 1,883  |      | $ |        |  
|                                          |  |                         |        |      |   |         |  
|                                         
|Expenses                                  |  |                         |        |      |   |         |  
|Depletion and amortization                |  |                         | 701    |      |   |        |  
|Dry-hole costs                            |  |                         | 3,808  |      |   | 32,728  |  
|Management fees to affiliate              |  |                         | 2,300  |      |   | 3,225   |  
|Lease operating expenses                  |  |                         | 61     |      |   |        |  
|Casualty loss                             |  |                         | 3,193  |      |   | 380     |  
|Other operating expenses                  |  |                         | 46     |      |   |        |  
|General and administrative expenses       |  |                         | 603    |      |   | 642     |  
|                                          |  |                         |        |      |   |         |  
|Total expenses                            |  |                         | 10,712 |      |   | 36,975  |  
|                                          |  |                         |        |      |   |         |  
|Loss from operations                      |  |                         | (8,829 | )    |   | (36,975 | )
|Other income                              |  |                         |        |      |   |         |  
|Interest income                           |  |                         | 2,627  |      |   | 3,514   |  
|                                          |  |                         |        |      |   |         |  
|Net loss                                  |  |                         | (6,202 | )    |   | (33,461 | )
|                                         
|Other comprehensive loss                  |  |                         |        |      |   |         |  
|Unrealized
 loss on marketable securities |  |                         |       |      |   | (45     | )
|                                          |  |                         |        |      |   |         |  
|                                         
|Total
 comprehensive loss                 |  | $                       | (6,202 | )    | $ | (33,506 | )
|                                          |  |                         |        |      |   |         |  

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

Oil and Gas Revenue.
In September 2007, the Fund began earning operating revenues with the onset of
production for the South Pelto 9 well. Oil and gas revenue for the year ended
December 31, 2007 was $1.9 million. Prior to September 2007, the Fund earned no
operating revenues.

During the
year ended December 31, 2007 the South Pelto 9 wells produced approximately 8
thousand barrels of oil and 137 thousand mcf of natural gas. Since the onset of
production in September 2007, oil prices have averaged $85 per barrel and
natural gas prices have averaged $8.84 per mcf.

Depletion and Amortization. Depletion and amortization of the cost of
proved oil and natural gas properties are calculated using the units of
production method. Proved developed reserves are used as the base for depleting
the cost of successful exploratory drilling and development costs. The sum of
proved developed and proved undeveloped reserves is used as the base for
depleting (or amortizing) leasehold acquisition costs, the costs to acquire
proved properties and platform and pipeline costs. For the year ended December
31, 2007 the Fund had recorded depletion and amortization of $0.7 million
relating to the onset of production of one of the Funds properties, South
Pelto 9. The Fund had no producing properties during the year ended December
31, 2006 and therefore had no depletion and amortization expense.

16

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

|                   |  |                         |       |      |   |        | 
|------------------ |  | ----------------------- | ----- | ---- | - | ------ | 
|                   |  | Year ended December 31,
|                   |  | 2007                    |       | 2006 |  
|                   |  |                         |       |      |  
|                   |  | (in thousands)          |      
|West Cameron 296   |  | $                       | 2,680 |      | $ |       | 
|West Delta 95      |  |                         | 1,342 |      |   | 15,165 | 
|West Cameron 78/95 |  |                         | (52   | )    |   | 4,395  | 
|Eugene Island 357  |  |                         | (14   | )    |   | 4,120  | 
|Eugene Island 334  |  |                         | (148  | )    |   | 9,048  | 
|                   |  |                         |       |      |   |        | 
|                   |  | $                       | 3,808 |      | $ | 32,728 | 
|                   |  |                         |       |      |   |        | 

Management Fee. For the years ended December 31, 2007
and 2006, the Fund incurred management fees totaling $2.3 million and $3.2
million, respectively. Management fees are charged by the Manager to cover
expenses associated with overhead and on-going management, administrative and
advisory services. Such overhead expenses include but are not limited to rent,
payroll and benefits for employees of the Manager, and other administrative
costs. The decrease of $0.9 million in 2007 was attributable to a policy change
by the Manager, reducing the calculation of the fee for the amount of
cumulative dry-hole costs incurred.

Casualty
Loss. For the years ended December 31, 2007 and
2006, the Fund recorded a casualty loss of $3.2 million and $0.4 million,
respectively. During 2006, the $0.4 million casualty loss related to the Funds
portion of the insurance deductible for the West Delta 95 and West Cameron
78/95 damage claim. During 2007, the claims were settled and the Fund recorded
an additional casualty loss of $3.2 million. See Item 1. - Business for further
discussion of the events giving rise to the losses.

Lease Operating Expenses.Lease operating expenses represent the
day-to-day cost of operating and maintaining wells and related facilities. For
the year ended December 31, 2007 the Fund had recorded lease operating expense
of $0.1 million relating to the onset of production of one of the Funds
properties, South Pelto 9. The Fund had no producing properties during the year
ended December 31, 2006 and therefore had no lease operating expense.

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

|                          |  |                         |     |      |   |     | 
|------------------------- |  | ----------------------- | --- | ---- | - | --- | 
|                          |  | Year ended December 31,
|                          |  | 2007                    |     | 2006 |  
|                          |  |                         |     |      |  
|                          |  | (in thousands)         
|Insurance                 |  | $                       | 304 |      | $ | 289 | 
|Accounting and legal fees |  |                         | 198 |      |   | 197 | 
|Trust fees and other      |  |                         | 101 |      |   | 156 | 
|                          |  |                         |     |      |   |     | 
|                          |  | $                       | 603 |      | $ | 642 | 
|                          |  |                         |     |      |   |     | 

Accounting and
legal fees represent annual audit and tax preparation fees, quarterly reviews
and filing fees of the Fund. Insurance expense represents premiums related to
well control insurance, which increases as drilling activity increases, and
directors and officers liability policy, which is allocated by the Manager to
the Fund based on capital raised by the Fund to total capital raised by all oil
and natural gas funds managed by the Manager. Trust fees represent bank fees
associated with the management of the Funds short-term investment portfolio in
US Treasury securities, which have increased during the year ended December 31,
2007 due to decrease in investment activity as cash is expended on properties.

Interest Income.Interest
income is earned on money market accounts and US Treasury securities. Interest
income for the years ended December 31, 2007 and 2006, totaled $2.6 million and
$3.5 million, respectively. During the year ended December 31, 2007, interest
income decreased as a result of a reduction in cash and investment balances
available partially offset by increased interest rates for the year ended
December 31, 2007.

17

---



Other
Comprehensive Loss. Other comprehensive loss is
comprised solely of the re-classification of previously recorded unrealized
gains on available-for-sale marketable debt securities. During 2006, the
available-for-sale security reached its maturity and the previously recorded
unrealized gain was reclassified to other income. As of December 31, 2007, all
investments in short-term US Treasury Notes are considered held-to-maturity
investments and are recorded at cost plus accrued interest.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows used in operating activities for the year ended December 31,
2007 were $0.4 million, primarily related to payments for management fees,
general and administrative expenses, and lease and other operating expenses of
$2.3 million, $0.6 million and $0.1 million, respectively. Partially offsetting
these payments were revenue receipts of $1.3 million, interest income received
totaling $1.1 million and favorable working capital of $0.2 million.

Cash flows used in operating
activities for the year ended December 31, 2006 were approximately $3.2
million, payments for management fees and general and administrative expenses
of approximately $3.2 million and $0.6 million. During 2006, the Fund incurred
a casualty loss of $0.4 million related to insurable losses for West Delta 95
and West Cameron 78/95. These uses were partially offset by interest income
received of approximately $1.0 million.

Investing Cash Flows

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 marketable securities, inclusive
of salvage fund, of $65.4 million, partially offset by proceeds from the
maturity of US 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.

Cash flows provided by
investing activities for the year ended December 31, 2006 were approximately
$27.8 million. The Fund received proceeds of approximately $116.0 million from
marketable securities that matured during 2006 and made investments in
marketable securities of approximately $65.0 million. Cash used in investing
activities primarily related to $12.2 million of expenditures for insured
recovery efforts for West Delta 95 and West Cameron 78/95, capital expenditures
of approximately $3.7 million for unproved oil and natural gas properties and
$7.2 million for properties that were determined to be unsuccessful, or
dry-holes, during 2006.

Financing Cash Flows

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.

Cash flows used in financing
activities were $22 thousand for the year ended December 31, 2006 due to the
payment of syndication costs.

Estimated Capital Expenditures

The Fund has
entered into multiple offshore operating agreements for the drilling and
development of its investment properties. The estimated capital expenditures
associated with these agreements can vary depending on the stage of development
on a property-by-property basis. As of December 31, 2007, the Fund has
commitments related to authorizations for expenditures totaling $18.8 million
for properties. If the properties were to be successful, the Fund would make
additional expenditures totaling $9.9 million related to the completion of
these properties.

Liquidity Needs

The Funds primary
short-term liquidity needs are to fund its 2008 operations, including
management fees and capital expenditures, with existing cash on-hand and income
earned from its short-term investments and cash and cash equivalents. The
Manager is entitled to receive an annual management fee from the Fund regardless
of whether the Fund is profitable in that year. The annual fee, payable
monthly, is equal to 2.5% of total capital contributed by shareholders, net of
cumulative dry-hole costs incurred.

18

---



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

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

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

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

Off-Balance Sheet Arrangements

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

Contractual Obligations

The Fund
enters into operating agreements with operators. On behalf of the Fund, an
operator enters into various contractual commitments pertaining to exploration,
development and production activities. The Fund does not discuss or negotiate
any such contracts. No contractual obligations exist at December 31, 2007 and
2006 other than those discussed in Estimated Capital Expenditures above.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

Not required.

ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

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

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

The Fund was
formed on December 21, 2004 and filed its Registration Statement on Form 10 in
April 2006; thus, the year ended December 31, 2005 was the Funds first audited
reporting period. Perelson Weiners audit report on the financial
statements of the Fund for the period December 21, 2004 (Inception) through
December 31, 2005 did not contain an adverse opinion or disclaimer of opinion,
nor was such report qualified or modified as to uncertainty, audit scope or
accounting principles.

19

---



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

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

As reported on
a Form 8-K filed with the SEC on July 13, 2006, the Manager of the Fund
appointed Deloitte & Touche LLP as the Funds independent registered
public accountants effective July 12, 2006.

ITEM
9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Managements Report on Internal Control
over Financial Reporting

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

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

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

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

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

Changes in Internal Controls over Financial
Reporting

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

20

---



ITEM
9B. OTHER INFORMATION

None.

PART
III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND
CORPORATE GOVERNANCE

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

|                                                               |              
|-------------------------------------------------------------- | -------------
|Name, Age
and Position with Registrant                         | Officer
Since
|                                                               |              
|Robert E. Swanson, 60                                          |              
|President and Chief Executive Officer                          | 1982         
|                                                               |              
|W. Greg Tabor, 47                                              |              
|Executive Vice President and
 Director of Business Development |              
|2004                                                          
|                                                               |              
|Robert L. Gold, 49                                             |              
|Executive Vice President                                       | 1987         
|                                                               |              
|Kathleen P. McSherry, 42                                       |              
|Executive Vice President and 
 Chief Financial Officer         |              
|2000                                                          
|                                                               |              
|Daniel V. Gulino, 47                                           |              
|Senior Vice President and General Counsel                      | 2003         
|                                                               |              
|Adrien Doherty, 55                                             |              
|Executive Vice President                                       | 2006         

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

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

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

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

21

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

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

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

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

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

Section 16(a) Beneficial Ownership Reporting ComplianceSection 16(a) of the
Exchange Act, as amended, requires the Funds executive officers and directors,
and persons who own more than 10% of a registered class of the Funds equity
securities, to file reports of ownership and changes in ownership with the SEC.
Based on a review of the copies of reports furnished or otherwise available to
the Fund, the Fund believes that during the year ended December 31, 2007, all
filing requirements applicable to its officers, directors and 10% beneficial
owners were met.

ITEM 11. EXECUTIVE COMPENSATION

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

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

The following
table sets forth information with respect to beneficial ownership of the shares
as of March 21, 2008 (no person owns more than 5% of the shares) by:

| |   |                                                       
| | - | ------------------------------------------------------
| |  | each
  executive officer (there are no directors); and
| |   |                                                       
| |  | all of the
  executive officers as a group.           

22

---



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 21, 2008.
Other than the below, no officer and director owns any of the Funds Shares.

|                                             |  |                  |        |         |  |   | 
|-------------------------------------------- |  | ---------------- | ------ | ------- |  | - | 
|Name of
beneficial owner                     |  | Number
of shares |        | Percent | 
|                                             |  |                  |        |         | 
|                                             |  |                  |        |         |  |   | 
|Robert E.
  Swanson (1), President and Chief |  |                  |        |         |  |   | 
|Executive
  Officer                          |  |                  | 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 Manager is paid an annual
management fee, payable monthly, equal to 2.5% of total capital contributions,
net of cumulative dry-hole costs incurred, for general and administrative and
management services supplied to the Fund. Additionally, when distributions are
made, the Manager is entitled to a portion of funds distributed to
shareholders. For the years ended December 31, 2007 and 2006 the Fund paid the
Manager management fees totaling $2.3 million and $3.2 million, respectively.
For the year ended December 31, 2007 the Manager received distributions from
the Fund of $0.1 million. No distributions were paid during 2006.

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

From time to time, short-term
payables and receivables, which do not bear interest, arise from transactions
with affiliates in the ordinary course of business. At December 31, 2007, the
Fund owed affiliates $0.7 million related to insurance proceeds and revenue
allocations. As of December 31, 2006, the Fund had a $16 thousand receivable,
recorded in other current assets, related to insurance and the overpayment of
fees from affiliates.

ITEM
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

|                 |  |                         |     |      |   |     | 
|---------------- |  | ----------------------- | --- | ---- | - | --- | 
|                 |  | Year ended December 31, |    
|                 |  | 2007                    |     | 2006 |  
|                 |  |                         |     |      |  
|                 |  | (in thousands)          |    
|Audit Fees
  (1) |  | $                       | 125 |      | $ | 125 | 
|Tax fees (2)     |  |                         |    |      |   | 41  | 
|                 |  |                         |     |      |   |     | 
|Total            |  | $                       | 125 |      | $ | 166 | 
|                 |  |                         |     |      |   |     | 

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

23

---



PART
IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT
SCHEDULES.

(a) (1)     Financial
Statements

See Index to Financial Statements set forth on page F-1.

(a) (2)     Financial
Statement Schedules

None.

|     |  |                                                                                                                                                                                                                                                                     
|---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     |  | Exhibit
  Index                                                                                                                                                                                                                                                     
|10.1 |  | Participation Agreement
  between Newfield Exploration Company and Ridgewood Energy Corporation as
  Manager for Eugene Island 346/347. (previously filed)                                                                                                          
|     |  |                                                                                                                                                                                                                                                                     
|10.2 |  | Participation Agreement
  between Devon Energy Production Company L.P. and Ridgewood Energy Corporation
  as Manager for Eugene Island 334. (previously filed)                                                                                                      
|     |  |                                                                                                                                                                                                                                                                     
|10.3 |  | Participation Agreement
  between Kerr-McGee Oil & Gas Corporation and Ridgewood Energy Corporation
  as Manager for Walker Ridge 155. (previously filed)                                                                                                           
|     |  |                                                                                                                                                                                                                                                                     
|10.4 |  | Participation Agreement
  between Newfield Exploration Company and Ridgewood Energy Corporation as
  Manager for West Cameron 296. (previously filed)                                                                                                               
|     |  |                                                                                                                                                                                                                                                                     
|10.5 |  | Participation Agreement
  between Apache Corporation and Ridgewood Energy Corporation as Manager for
  South Timbalier 287.                                                                                                                                         
|     |  |                                                                                                                                                                                                                                                                     
|10.6 |  | Participation Agreement
  between W & T Offshore, Inc. and Ridgewood Energy Corporation as Manager
  for High Island 38.                                                                                                                                            
|     |  |                                                                                                                                                                                                                                                                     
|23.1 |  | Consent of Ryder Scott
  Company, L.P.                                                                                                                                                                                                                              
|     |  |                                                                                                                                                                                                                                                                     
|31.1 |  | Certification of Robert E.
  Swanson, Chief Executive Officer, pursuant to Securities Exchange Act Rule
  13a-14(a).                                                                                                                                                
|     |  |                                                                                                                                                                                                                                                                     
|31.2 |  | Certification of Kathleen
  P. McSherry, Chief Financial Officer, pursuant to Securities Exchange Act
  Rule 13a-14(a).                                                                                                                                             
|     |  |                                                                                                                                                                                                                                                                     
|32   |  | Certifications pursuant to
  18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley
  Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the
  Company and Kathleen P. McSherry, Chief Financial Officer of the Company.

24

---



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

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, 2007 and 2006, the related statements of operations
and other comprehensive loss, changes in members capital and cash flows for
the years ended December 31, 2007 and 2006. These financial statements are the
responsibility of the Funds management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

In our
opinion, such financial statements present fairly, in all material respects,
the financial position of Ridgewood Energy O Fund, LLC as of December 31, 2007
and 2006, and the results of its operations and its cash flows for the years
ended December 31, 2007 and 2006, in conformity with accounting principles
generally accepted in the United States of America.

/s/ Deloitte
& Touche LLP

March 21, 2008
Parsippany, New Jersey

F-2

---



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

|                                                                                |  |              |         |      |   |         |  
|------------------------------------------------------------------------------- |  | ------------ | ------- | ---- | - | ------- | -
|                                                                                |  | December 31, |        
|                                                                                |  | 2007         |         | 2006 |  
|                                                                                |  |              |         |      |  
|ASSETS                                                                          |  |              |         |      |  
|Current
 assets:                                                                |  |              |         |      |   |         |  
|Cash and cash equivalents                                                       |  | $            | 14,546  |      | $ | 33,188  |  
|Short-term investment in marketable
 securities                                 |  |              | 40,602  |      |   | 25,185  |  
|Production receivable                                                           |  |              | 598     |      |   |        |  
|Insurance receivable                                                            |  |              |        |      |   | 16,643  |  
|Other current assets                                                            |  |              | 372     |      |   | 245     |  
|                                                                                |  |              |         |      |   |         |  
|Total current assets                                                            |  |              | 56,118  |      |   | 75,261  |  
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|Salvage fund                                                                    |  |              | 1,110   |      |   | 1,060   |  
|                                                                                |  |              |         |      |   |         |  
|Oil and gas
 properties                                                         |  |              |         |      |   |         |  
|Advances to operators for working interests
 and expenditures                   |  |              | 1,866   |      |   |        |  
|Unproved properties                                                             |  |              | 5,961   |      |   |        |  
|Proved properties                                                               |  |              | 5,603   |      |   | 3,917   |  
|Less: accumulated depletion and
 amortization                                   |  |              | (701    | )    |   |        |  
|                                                                                |  |              |         |      |   |         |  
|Total oil and gas properties                                                    |  |              | 12,729  |      |   | 3,917   |  
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|Total assets                                                                    |  | $            | 69,957  |      | $ | 80,238  |  
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|LIABILITIES AND MEMBERS CAPITAL                                                |  |              |         |      |   |         |  
|Current
 liabilities:                                                           |  |              |         |      |   |         |  
|Due to operators                                                                |  | $            | 2,070   |      | $ | 6,344   |  
|Accrued expenses payable                                                        |  |              | 126     |      |   | 98      |  
|Due to affiliates (Note 6)                                                      |  |              | 652     |      |   |        |  
|                                                                                |  |              |         |      |   |         |  
|Total current liabilities                                                       |  |              | 2,848   |      |   | 6,442   |  
|                                                                                |  |              |         |      |   |         |  
|Asset retirement obligations                                                    |  |              | 39      |      |   | 37      |  
|                                                                                |  |              |         |      |   |         |  
|Total liabilities                                                               |  |              | 2,887   |      |   | 6,479   |  
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|Commitments
 and contingencies (Note 8)                                         |  |              |         |      |   |         |  
|Members
 capital:                                                              |  |              |         |      |   |         |  
|Manager:                                                                        |  |              |         |      |   |         |  
|Distributions                                                                   |  |              | (73     | )    |   |        |  
|Accumulated deficit                                                             |  |              | (1,447  | )    |   | (1,248  | )
|                                                                                |  |              |         |      |   |         |  
|Managers total                                                                 |  |              | (1,520  | )    |   | (1,248  | )
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|Shareholders:                                                                   |  |              |         |      |   |         |  
|Capital contributions (935 shares
 authorized; 870.6486 issued and outstanding) |  |              | 128,990 |      |   | 128,990 |  
|Syndication costs                                                               |  |              | (14,742 | )    |   | (14,742 | )
|Distributions                                                                   |  |              | (414    | )    |   |        |  
|Accumulated deficit                                                             |  |              | (45,244 | )    |   | (39,241 | )
|                                                                                |  |              |         |      |   |         |  
|Shareholders total                                                             |  |              | 68,590  |      |   | 75,007  |  
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|Total members capital                                                          |  |              | 67,070  |      |   | 73,759  |  
|                                                                                |  |              |         |      |   |         |  
|                                                                                |  |              |         |      |   |         |  
|Total liabilities and members
capital                                          |  | $            | 69,957  |      | $ | 80,238  |  
|                                                                                |  |              |         |      |   |         |  

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

F-3

---



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

|                                         |  |                         |        |      |   |         |  
|---------------------------------------- |  | ----------------------- | ------ | ---- | - | ------- | -
|                                         |  | Year ended December 31, |       
|                                         |  | 2007                    |        | 2006 |  
|                                         |  |                         |        |      |  
|Revenue                                  |  |                         |        |      |   |         |  
|Oil and gas revenue                      |  | $                       | 1,883  |      | $ |        |  
|                                         |  |                         |        |      |   |         |  
|Expenses                                 |  |                         |        |      |   |         |  
|Depletion and amortization               |  |                         | 701    |      |   |        |  
|Dry-hole costs                           |  |                         | 3,808  |      |   | 32,728  |  
|Management fees to affiliate (Note 6)    |  |                         | 2,300  |      |   | 3,225   |  
|Lease operating expense                  |  |                         | 61     |      |   |        |  
|Casualty loss                            |  |                         | 3,193  |      |   | 380     |  
|Other operating expenses                 |  |                         | 46     |      |   |        |  
|General and administrative expenses      |  |                         | 603    |      |   | 642     |  
|                                         |  |                         |        |      |   |         |  
|Total expenses                           |  |                         | 10,712 |      |   | 36,975  |  
|                                         |  |                         |        |      |   |         |  
|Loss from operations                     |  |                         | (8,829 | )    |   | (36,975 | )
|Other income                             |  |                         |        |      |   |         |  
|Interest income                          |  |                         | 2,627  |      |   | 3,514   |  
|                                         |  |                         |        |      |   |         |  
|Net loss                                 |  |                         | (6,202 | )    |   | (33,461 | )
|Other comprehensive loss                 |  |                         |        |      |   |         |  
|Unrealized loss on marketable securities |  |                         |       |      |   | (45     | )
|                                         |  |                         |        |      |   |         |  
|Total comprehensive loss                 |  | $                       | (6,202 | )    | $ | (33,506 | )
|                                         |  |                         |        |      |   |         |  
|                                         |  |                         |        |      |   |         |  
|Manager Interest                         |  |                         |        |      |   |         |  
|Net loss                                 |  | $                       | (199   | )    | $ | (855    | )
|                                         |  |                         |        |      |   |         |  
|Shareholder
  Interest                   |  |                         |        |      |   |         |  
|Net loss                                 |  | $                       | (6,003 | )    | $ | (32,606 | )
|Net loss per share                       |  | $                       | (6,895 | )    | $ | (37,450 | )

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, 2005                |  |             | 870.6486 |         | $ | (393         | ) | $     | 107,658 |   | $ | 107,265 |  
|                                           |  |             |          |         |   |              |   |       |         |   |   |         |  
|Net loss incurred in the exploratory
stage |  |             |         |         |   | (855         | ) |       | (32,606 | ) |   | (33,461 | )
|Other comprehensive loss                   |  |             |         |         |   |             |   |       | (45     | ) |   | (45     | )
|                                           |  |             |          |         |   |              |   |       |         |   |   |         |  
|                                           |  |             |          |         |   |              |   |       |         |   |   |         |  
|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  |  
|                                           |  |             |          |         |   |              |   |       |         |   |   |         |  

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, |        
|                                                                                                                       |  | 2007                    |         | 2006 |  
|                                                                                                                       |  |                         |         |      |  
|                                                                                                                      
|Cash flows from operating activities                                                                                   |  |                         |         |      |   |         |  
|Net loss                                                                                                               |  | $                       | (6,202  | )    | $ | (33,461 | )
|Adjustments to reconcile net loss to net
 cash used in operating activities                                            |  |                         |         |      |   |         |  
|Depletion and amortization                                                                                             |  |                         | 701     |      |   |        |  
|Dry-hole costs                                                                                                         |  |                         | 3,808   |      |   | 32,728  |  
|Casualty loss                                                                                                          |  |                         | 3,193   |      |   |        |  
|Accretion expense                                                                                                      |  |                         | 2       |      |   |        |  
|Interest earned on marketable securities                                                                               |  |                         | (1,712  | )    |   | (2,314  | )
|Changes in assets and liabilities:                                                                                     |  |                         |         |      |   |         |  
|Increase in production receivable                                                                                      |  |                         | (598    | )    |   |        |  
|Decrease (increase) in other current
assets                                                                            |  |                         | 142     |      |   | (187    | )
|Increase (decrease) in due to affiliates                                                                               |  |                         | 177     |      |   | (12     | )
|Increase in accrued expenses payable                                                                                   |  |                         | 72      |      |   | 28      |  
|                                                                                                                       |  |                         |         |      |   |         |  
|Net cash used in operating activities                                                                                  |  |                         | (417    | )    |   | (3,218  | )
|                                                                                                                       |  |                         |         |      |   |         |  
|                                                                                                                      
|Cash flows from investing activities                                                                                   |  |                         |         |      |   |         |  
|Payments to operators for working interests
 and expenditures                                                          |  |                         | (1,866  | )    |   |        |  
|Capital expenditures for oil and gas
 properties                                                                       |  |                         | (16,025 | )    |   | (23,149 | )
|Salvage fund investments                                                                                               |  |                         | (50     | )    |   | (46     | )
|Proceeds from insurance recovery                                                                                       |  |                         | 13,908  |      |   |        |  
|Proceeds from the sale of marketable
 securities                                                                       |  |                         | 51,613  |      |   | 116,000 |  
|Investment in marketable securities                                                                                    |  |                         | (65,318 | )    |   | (65,001 | )
|                                                                                                                       |  |                         |         |      |   |         |  
|Net cash (used in) provided by investing
 activities                                                                   |  |                         | (17,738 | )    |   | 27,804  |  
|                                                                                                                       |  |                         |         |      |   |         |  
|                                                                                                                      
|Cash flows from financing activities                                                                                   |  |                         |         |      |   |         |  
|Distributions                                                                                                          |  |                         | (487    | )    |   |        |  
|Syndication costs paid                                                                                                 |  |                         |        |      |   | (22     | )
|                                                                                                                       |  |                         |         |      |   |         |  
|Net cash used in financing activities                                                                                  |  |                         | (487    | )    |   | (22     | )
|                                                                                                                       |  |                         |         |      |   |         |  
|Net (decrease) increase in cash and cash
 equivalents                                                                  |  |                         | (18,642 | )    |   | 24,564  |  
|                                                                                                                      
|Cash and cash equivalents, beginning of
 period                                                                        |  |                         | 33,188  |      |   | 8,624   |  
|                                                                                                                       |  |                         |         |      |   |         |  
|Cash and cash equivalents, end of period                                                                               |  | $                       | 14,546  |      | $ | 33,188  |  
|                                                                                                                       |  |                         |         |      |   |         |  
|                                                                                                                      
|Supplemental schedule of non-cash investing
 activities                                                                |  |                         |         |      |   |         |  
|Advances used for capital expenditures in
 oil and gas properties reclassified to dry-hole costs and proved properties |  | $                       |        |      | $ | 9,957   |  
|                                                                                                                       |  |                         |         |      |   |         |  

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

F-6

---



RIDGEWOOD ENERGY O FUND, LLCNOTES 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 as of February 16, 2005 by and
among Ridgewood Energy Corporation (the Manager), and the shareholders of the
Fund. Although the date of formation is December 21, 2004, the Fund did not
begin business activities until February 16, 2005 when it began its private
offering of shares of LLC member interest (the Shares). There were no
business activities prior to February 16, 2005.

The Fund was
organized to acquire, drill, construct and develop oil and natural gas properties
located in the United States offshore waters of Texas, Louisiana and Alabama in
the Gulf of Mexico. The Fund has devoted most of its efforts to raising capital
for oil and natural gas exploration activities. During 2007, the Fund began
earning revenue and was determined to no longer be an exploratory stage
enterprise.

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

2. Summary of Significant Accounting Policies

Use of Estimates

The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. On an ongoing basis, the Manager reviews its estimates,
including those related to amounts advanced to and billed by operators,
determination of proved reserves, impairment allowances and asset retirement
obligations. Actual results may differ from those estimates.

Cash
and Cash Equivalents

All highly liquid
investments with maturities when purchased of three months or less are
considered as cash and cash equivalents. At times, bank deposits may be in
excess of federal insured limits. At December 31, 2007 and December 31, 2006,
bank balances inclusive of the salvage fund exceeded federally insured limits
by $14.4 million and $8.0 million, respectively. The Fund maintains bank
deposits with accredited financial institutions to mitigate such risk.

Investments
in Marketable Securities

At times the
Fund may purchase short-term investments comprised of US Treasury Notes with
maturities greater than three months that are considered held-to-maturity
investments. Held-to-maturity securities are those investments that the Fund
has the ability and intent to hold to maturity. Held-to-maturity investments
are recorded at cost plus accrued income, adjusted for the amortization of
premiums and discounts, which approximate fair value. Interest income is
accrued as earned. At December 31, 2007, the Fund had held-to-maturity
investments totaling $40.6 million, which matured in February 2008.

Salvage
Fund

Pursuant to
the Funds LLC Agreement, the Fund deposits in a separate interest-bearing
account, or a salvage fund, money to provide for dismantling production
platforms and facilities, plugging and abandoning the wells and removing the
platforms, facilities and wells after their useful lives, in accordance with
applicable federal and state laws and regulations.

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

F-7

---



Oil
and Natural Gas Properties

Investments in
oil and natural gas properties are operated by unaffiliated entities (the
Operators) that are responsible for drilling, administering and producing
activities pursuant to the terms of the applicable operating agreements with
working interest owners. The Funds portion of exploration, drilling, operating
and capital equipment expenditures relating to the wells are advanced and
billed by Operators through authorization for expenditures.

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

Upon the sale
or retirement of a proved property, the cost and related accumulated depletion
and amortization will be eliminated from the property accounts, and the
resultant gain or loss is recognized. On the sale or retirement of an unproved
property, gain or loss on the sale is recognized, taking into consideration the
amount of any recorded impairment if the property had been assessed for
impairment. The Manager does not currently intend to sell any of the Funds
property interests.

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

As of December
31, 2007 and 2006 amounts recorded in due to operators totaling $2.0 million
and $6.3 million, respectively, related to the acquisition of oil and gas
property, both successful and unsuccessful, as well as recovery efforts. The 2007
balance was paid in the first quarter of 2008.

Advances
to Operators for Working Interests and Expenditures

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

Asset
Retirement Obligations

For oil and
natural gas properties, there are obligations to perform removal and
remediation activities when the properties are retired. When a project reaches
drilling depth and is determined to be either proved or dry, an asset
retirement obligation is incurred. Plug and abandonment costs associated with
unsuccessful projects are expensed as dry-hole costs.

|                        |  |                |      |      |   |      |  
|----------------------- |  | -------------- | ---- | ---- | - | ---- | -
|                        |  | 2007           |      | 2006 |  
|                        |  |                |      |      |  
|                        |  | (in thousands) |     
|Balance -
 January 1,   |  | $              | 37   |      | $ |     |  
|Liabilities
 incurred   |  |                | 904  |      |   | 469  |  
|Liabilities
 settled    |  |                | (904 | )    |   | (432 | )
|Accretion
 expense      |  |                | 2    |      |   |     |  
|                        |  |                |      |      |   |      |  
|Balance -
 December 31, |  | $              | 39   |      | $ | 37   |  
|                        |  |                |      |      |   |      |  

Syndication
Costs

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

Revenue
Recognition and Production Receivable

Oil and
natural gas sales are recognized and a production receivable is recorded when
delivery is made by the Operator to the purchaser and title is transferred
(i.e., production has been delivered to a pipeline or transport vehicle). The
Fund began earning revenue in September 2007, with the onset of production for
South Pelto 9. During 2006, the Fund had not earned revenue as there were no
producing properties.

F-8

---



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

Impairment
of Long-Lived Assets

In accordance
with the provisions of SFAS No. 144, Accounting for the Impairment of
Long-Lived Assets, long-lived assets, such as oil and natural gas
properties, are evaluated when events or changes in circumstances indicate the
carrying value of such assets may not be recoverable. The determination of
whether impairment has occurred is made by comparing the carrying values
of long-lived assets to the estimated future undiscounted cash flows
attributable to the asset. The impairment loss recognized is the excess of the
carrying value over the future discounted cash flows attributable to the asset
or the estimated fair value of the asset. No impairments have been recorded in
the Fund since inception.

Depletion
and Amortization

Depletion and
amortization of the cost of proved oil and natural gas properties are
calculated using the units of production method. Proved developed reserves are
used as the base for depleting the cost of successful exploratory drilling and
development costs. The sum of proved developed and proved undeveloped reserves
is used as the base for depleting (or amortizing) leasehold acquisition costs,
the costs to acquire proved properties and platform and pipeline costs. At
December 31, 2006, the Fund did not have accumulated depletion as it had not
had any production.

Income
Taxes

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

Income
and Expense Allocation

Profits and
losses are to be allocated 85% to shareholders in proportion to their relative
capital contributions and 15% to the Manager, except for items of expense,
loss, deduction and credit that are attributable to the expenditure of
shareholders capital contributions, which are allocated 99% to shareholders
and 1% to the Manager.

3. Recent
Accounting Standards

In February 2007, the
Financial Accounting Standards Board (the FASB) issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial Liabilities (SFAS No.
159), which permits entities to measure many financial instruments and certain
other items at fair value that are not currently required to be measured at
fair value. An entity would report unrealized gains and losses on items for
which the fair value option has been elected in earnings at each subsequent
reporting date. The objective is to improve financial reporting by providing
entities with the opportunity to mitigate volatility in reported earnings
caused by measuring related assets and liabilities differently without having
to apply complex hedge accounting provisions. The decision about whether to
elect the fair value option is applied instrument by instrument, with a few
exceptions; the decision is irrevocable; and it is applied only to entire
instruments and not to portions of instruments. The statement requires
disclosures that facilitate comparisons (a) between entities that choose different
measurement attributes for similar assets and liabilities and (b) between
assets and liabilities in the financial statements of an entity that selects
different measurement attributes for similar assets and liabilities. SFAS No.
159 is effective for financial statements issued for fiscal years beginning
after November 15, 2007. The adoption of SFAS No. 159 will not have a material
impact on its financials. The Fund did not elect to measure existing assets and
liabilities at fair value on the date of adoption.

In September
2006, the FASB issued SFAS No. 157, Fair Value Measurements, (SFAS No.157),
which applies under most other accounting pronouncements that require or permit
fair value measurements. SFAS No. 157 provides a common definition of fair
value as the price that would be received to sell an asset or paid to transfer
a liability in a transaction between market participants. The new standard also
provides guidance on the methods used to measure fair value and requires
expanded disclosures related to fair value measurements. SFAS No. 157 had
originally been effective for financial statements issued for fiscal years
beginning after November 15, 2007, however the FASB has agreed on a one year
deferral for all nonfinancial assets and liabilities. The Fund believes this
guidance will not have a material impact on the financial statements.

F-9

---



4. Unproved Properties - Capitalized
Exploratory Well Costs

Leasehold
acquisition and exploratory drilling costs are capitalized pending
determination of whether the well has found proved reserves. Unproved
properties are assessed on a quarterly basis by evaluating and monitoring if
sufficient progress is made on assessing the reserves. The following table
reflects the net changes in unproved properties for the years ended December
31, 2007 and 2006. As of December 31, 2007 and 2006, the Fund had no capitalized
exploratory well costs greater than one year.

|                                                                                               |  |                |        |      |   |         |  
|---------------------------------------------------------------------------------------------- |  | -------------- | ------ | ---- | - | ------- | -
|                                                                                               |  | 2007           |        | 2006 |  
|                                                                                               |  |                |        |      |  
|                                                                                               |  | (in thousands) |       
|Balance - January 1,                                                                           |  | $              |       |      | $ | 16,873  |  
|                                                                                               |  |                |        |      |   |         |  
|Additions to capitalized exploratory well costs pending the
  determination of proved reserves |  |                | 7,647  |      |   | 3,879   |  
|Reclassifications to proved properties based on the determination of
  proved reserves         |  |                | (1,686 | )    |   | (3,879  | )
|Capitalized exploratory
  well costs charged to dry hole costs                                 |  |                |        |      |   | (16,873 | )
|                                                                                               |  |                |        |      |   |         |  
|Balance - December 31,                                                                         |  | $              | 5,961  |      | $ |        |  
|                                                                                               |  |                |        |      |   |         |  

Capitalization
costs are expensed as dry-hole costs in the event that reserves are not found
or are not in sufficient quantities to complete the well and develop the field.
Dry-hole costs are detailed in the table below.

|                   |  |                         |       |      |   |        | 
|------------------ |  | ----------------------- | ----- | ---- | - | ------ | 
|                   |  | Year ended December 31, |      
|                   |  | 2007                    |       | 2006 |  
|                   |  |                         |       |      |  
|                   |  | (in thousands)          |      
|West Cameron 296   |  | $                       | 2,680 |      | $ |       | 
|West Delta 95      |  |                         | 1,342 |      |   | 15,165 | 
|West Cameron 78/95 |  |                         | (52   | )    |   | 4,395  | 
|Eugene Island 357  |  |                         | (14   | )    |   | 4,120  | 
|Eugene Island 334  |  |                         | (148  | )    |   | 9,048  | 
|                   |  |                         |       |      |   |        | 
|                   |  | $                       | 3,808 |      | $ | 32,728 | 
|                   |  |                         |       |      |   |        | 

5. Distributions

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

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

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

In December 2007, the Fund
made its initial distributions to the Manager and shareholders totaling $0.1
million and $0.4 million, respectively. There were no distributions made by the
Fund during the year ended December 31, 2006.

6. Related Parties

The LLC
Agreement provides that the Manager render management, administrative and
advisory services. For such services, the Manager receives an annual management
fee, payable monthly, of 2.5% of total capital contributions, net of cumulative
dry-hole costs incurred. Management fees of $2.3 million and $3.2 million were
incurred for the years ended December 31, 2007 and 2006, respectively.

From time to time,
short-term payables and receivables, which do not bear interest, arise from
transactions with affiliates in the ordinary course of business. At December
31, 2007, the Fund owed affiliates $0.7 million related to insurance proceeds
and revenue allocations. As of December 31, 2006, the Fund had a $16 thousand
receivable, recorded in other current assets, related to insurance and the
overpayment of fees from affiliates.

F-10

---



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

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

7. Fair Value of Financial Instruments

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

8. Commitments and Contingencies

Capital
Commitments

The Fund has entered into
multiple offshore operating agreements for the drilling and development of its
investment properties. The estimated capital expenditures associated with these
agreements vary depending on the stage of development on a property-by-property
basis. As of December 31, 2007, the Fund had committed to spend an additional $18.8
million relating to the properties.

Environmental
Considerations

The
exploration for and development of oil and natural gas involves the extraction,
production and transportation of materials which, under certain conditions, can
be hazardous or cause environmental pollution problems. The Manager and the
Operators are continually taking action they believe appropriate to satisfy
applicable federal, state and local environmental regulations and do not
currently anticipate that compliance with federal, state and local
environmental regulations will have a material adverse effect upon capital
expenditures, results of operations or the competitive position of the Fund in
the oil and natural gas industry. However, due to the significant public and
governmental interest in environmental matters related to those activities, the
Manager cannot predict the effects of possible future legislation, rule
changes, or governmental or private claims. At December 31, 2007 and 2006,
there were no known environmental issues that required the Fund to record a
liability.

Insurance
Coverage

The Fund is
subject to all risks inherent in the exploration for and development of oil and
natural gas. Insurance coverage as is customary for entities engaged in similar
operations is maintained, but losses may occur from uninsurable risks or
amounts in excess of existing insurance coverage. The occurrence of an event
which is not insured or not fully insured could have an adverse impact upon
earnings and financial position. Moreover, insurance is obtained as a package
covering all of the Managers investment programs. Claims made by other such
programs can reduce or eliminate insurance for the Fund. The Fund records
receivables for insured losses when the expected insurance proceeds are probable
and reasonably estimable based upon assumptions and estimates derived from
currently known facts.

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.

The Fund recorded casualty losses totaling $1.8 million related to the
deductible, changes in estimates to, and the ultimate settlement of, this
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.

F-11

---



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

In accordance
with Statement of Financial Accounting Standards No. 69, Disclosures about Oil
and Gas Producing Activities, this section provides supplemental information
on oil and natural gas exploration and producing activities of the Fund. The
Fund has one well classified as a proved property, South Pelto 9, which was
deemed to have proved reserves in late-2006.

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

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

|                                                               |  |                |        |      |   |       | 
|-------------------------------------------------------------- |  | -------------- | ------ | ---- | - | ----- | 
|                                                               |  | December 31,   |       
|                                                               |  | 2007           |        | 2006 |  
|                                                               |  |                |        |      |  
|                                                               |  | (in thousands) |       
|Advances to operators for
  working interests and expenditures |  | $              | 1,866  |      | $ |      | 
|Unproved oil and gas
  properties                              |  |                | 5,961  |      |   |      | 
|Proved oil and gas properties                                  |  |                | 5,603  |      |   | 3,917 | 
|                                                               |  |                |        |      |   |       | 
|Total oil and gas
  properties                                 |  |                | 13,430 |      |   | 3,917 | 
|Accumulated depletion and
  amortization                       |  |                | (701   | )    |   |      | 
|                                                               |  |                |        |      |   |       | 
|Oil and gas properties,
  net                                  |  | $              | 12,729 |      | $ | 3,917 | 
|                                                               |  |                |        |      |   |       | 

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

|                                         |  |                         |        |      |   |       | 
|---------------------------------------- |  | ----------------------- | ------ | ---- | - | ----- | 
|                                         |  | Year ended December 31, |       
|                                         |  | 2007                    |        | 2006 |  
|                                         |  |                         |        |      |   |       | 
|                                         |  | (in thousands)          |       
|Exploratory drilling
  costs-capitalized |  | $                       | 13,947 |      | $ | 3,917 | 
|Exploratory drilling
  costs-expensed    |  |                         | 3,808  |      |   | 5,898 | 
|Geological costs                         |  |                         | 44     |      |   |      | 
|                                         |  |                         |        |      |   |       | 
|                                         |  | $                       | 17,799 |      | $ | 9,815 | 
|                                         |  |                         |        |      |   |       | 

F-12

---



Table III - Reserve Quantity Information

Oil and gas
reserves of the Fund have been estimated by an independent petroleum engineer,
Ryder Scott Company, L.P., for the year ended December 31, 2007. The reserve
estimates for December 31, 2007 were based on estimated future reserves as of
December 31, 2007 provided by Ryder Scott Company, L.P. The reserve data at
December 31, 2006 was based upon internal engineering estimates due to the
timing of the discovery. These reserve disclosures have been prepared in compliance
with the Securities and Exchange Commission rules.

Proved
reserves are classified as either developed or undeveloped. Proved developed
reserves are the quantities expected to be recovered through existing wells
with existing equipment and operating methods. There are no proved undeveloped
reserves at December 31, 2007 or 2006.

|                                |  |                                   |         |                                   |  |            |   |           |         |  |  |           | 
|------------------------------- |  | --------------------------------- | ------- | --------------------------------- |  | ---------- | - | --------- | ------- |  |  | --------- | 
|                                |  | December 31, 2007
  United States |         | December 31, 2006
  United States | 
|                                |  | Oil (BBLS)                        |         | Gas (MCF)                         |  | Oil (BBLS) |   | Gas (MCF) |        
|                                |  |                                   |         |                                   |  |            |   |           |         |  |  |           | 
|                                |  |                                   |         |                                   |  |            |   |           |         |  |  |           | 
|Proved developed reserves:      |  |                                   |         |                                   |  |            |   |           |         |  |  |           | 
|Beginning of year               |  |                                   | 139,320 |                                   |  | 2,786,403  |   |           |        |  |  |          | 
|Discoveries                     |  |                                   |        |                                   |  |           |   |           | 139,320 |  |  | 2,786,403 | 
|Revisions of previous estimates |  |                                   | (99,026 | )                                 |  | (1,718,072 | ) |           |        |  |  |          | 
|Production                      |  |                                   | (7,851  | )                                 |  | (137,331   | ) |           |        |  |  |          | 
|                                |  |                                   |         |                                   |  |            |   |           |         |  |  |           | 
|End of year                     |  |                                   | 32,443  |                                   |  | 931,000    |   |           | 139,320 |  |  | 2,786,403 | 
|                                |  |                                   |         |                                   |  |            |   |           |         |  |  |           | 

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

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

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

|                                                                     |  |                |        |      |   |        |  
|-------------------------------------------------------------------- |  | -------------- | ------ | ---- | - | ------ | -
|                                                                     |  | December 31,   |       
|                                                                     |  | 2007           |        | 2006 |  
|                                                                     |  |                |        |      |  
|                                                                     |  | (in thousands) |       
|Future estimated revenues                                            |  | $              | 11,096 |      | $ | 24,221 |  
|Future estimated production costs                                    |  |                | (684   | )    |   | (1,012 | )
|Future estimated development costs                                   |  |                |       |      |   | (1,581 | )
|                                                                     |  |                |        |      |   |        |  
|Future net cash flows                                                |  |                | 10,412 |      |   | 21,628 |  
|10% annual discount for estimated timing of
  cash flows             |  |                | (1,350 | )    |   | (5,380 | )
|                                                                     |  |                |        |      |   |        |  
|Standardized measure of discounted future
  estimated net cash flows |  | $              | 9,062  |      | $ | 16,248 |  
|                                                                     |  |                |        |      |   |        |  

F-13

---



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

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

|                                                                                   |  |                         |         |      |   |        | 
|---------------------------------------------------------------------------------- |  | ----------------------- | ------- | ---- | - | ------ | 
|                                                                                   |  | Year ended December 31, |        
|                                                                                   |  | 2007                    |         | 2006 |  
|                                                                                   |  |                         |         |      |  
|                                                                                   |  | (in thousands)          |        
|Standardized measure beginning of the year                                         |  | $                       | 16,248  |      | $ |       | 
|Sales of oil and gas production, net of production costs                           |  |                         | (1,822  | )    |   |       | 
|Net changes in prices and production costs                                         |  |                         | 4,823   |      |   |       | 
|Extensions, discoveries, and improved recovery and techniques, less
 related costs |  |                         |        |      |   | 15,977 | 
|Development costs incurred during the period                                       |  |                         | 1,581   |      |   |       | 
|Revisions of previous reserve quantities estimate                                  |  |                         | (15,737 | )    |   |       | 
|Accretion of discount                                                              |  |                         | 798     |      |   | 271    | 
|Timing and other                                                                   |  |                         | 3,171   |      |   |       | 
|                                                                                   |  |                         |         |      |   |        | 
|Standardized measure end of the year                                               |  | $                       | 9,062   |      | $ | 16,248 | 
|                                                                                   |  |                         |         |      |   |        | 

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-14

---



SIGNATURES

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

|                      |                              |                               
|--------------------- | ---------------------------- | ------------------------------
|                      | RIDGEWOOD ENERGY O FUND, LLC
|                      |                             
|Date: March
 21, 2008 | By:                          | /s/ ROBERT
 E. SWANSON        
|                      |                              | Robert E.
 Swanson            
|                      |                              | Chief
 Executive Officer      
|                      |                              | (Principal
 Executive Officer)

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

|                             |  |                                                        |  |                
|---------------------------- |  | ------------------------------------------------------ |  | ---------------
|Signature                    |  | Capacity                                               |  | Date           
|                             |  |                                                        |  |                
|/s/ ROBERT
 E. SWANSON       |  | Chief
 Executive Officer (Principal Executive Officer) |  | March 21,
 2008
|                             |  |                                                        |  |                
|Robert E.
 Swanson           |  |                                                        |  |                
|                             |  |                                                        |  |                
|/s/ KATHLEEN
 P. MCSHERRY    |  | Executive
 Vice President and Chief Financial Officer  |  | March 21,
 2008
|                             |  | (Principal Accounting Officer)                         |  |                
|Kathleen P.
 McSherry        |  |                                                        |  |                
|                             |  |                                                        |  |                
|RIDGEWOOD ENERGY CORPORATION |  |                                                        |  |                
|/s/ ROBERT
 E. SWANSON       |  | Chief
 Executive Officer of Manager                    |  | March 21,
 2008
|                             |  |                                                        |  |                
|Robert E.
 Swanson           |  |                                                        |  |                

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