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, 2009


or


o TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(D) OF THE


SECURITIES
EXCHANGE ACT OF 1934





For
the transition period from _____ to _____




Commission
File No. 000-52576




RIDGEWOOD
ENERGY S FUND, LLC


(Exact
name of registrant as specified in its charter)




Delaware
            20-4077773(State
      or other jurisdiction of
              incorporation
      or organization)
            (I.R.S.
      Employer
              Identification
      No.)




14
Philips Parkway, Montvale, NJ  07645


(Address
of principal executive offices) (Zip code)




(800)
942-5550


(Registrant’s
telephone number, including area code)




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


Securities
registered pursuant to Section 12(g) of the Act:


Shares of
LLC Membership Interest





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.


Yes 
o  No 
x





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


Yes 
o   No 
x





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





Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files).


Yes o      No
o





Indicate
by check mark if the disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will not
be contained, 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:





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





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 of LLC Membership Interest in the Fund. As of March 16,
2010 there are 839.5395 shares of LLC Membership Interest
outstanding.














RIDGEWOOD
ENERGY S FUND, LLC


2009
ANNUAL REPORT ON FORM 10-K


TABLE
OFCONTENTS




PAGEPART
      IITEM 1
            BUSINESS
            2ITEM 1A
            RISK FACTORS
            11ITEM 1B
            UNRESOLVED STAFF COMMENTS
            11ITEM 2
            PROPERTIES
            11ITEM 3
            LEGAL PROCEEDINGS
            12ITEM 4
            (REMOVED AND RESERVED)
            12PART
      IIITEM 5
            MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
      MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
            13ITEM 6
            SELECTED FINANCIAL DATA
            13ITEM 7
            MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
      AND RESULTS OF OPERATIONS
            13ITEM 7A
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
            19ITEM 8
            FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
            19ITEM 9
            CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
      AND FINANCIAL DISCLOSURE
            19ITEM 9A
            CONTROLS AND PROCEDURES
            19ITEM 9B
            OTHER INFORMATION
            19PART
      IIIITEM 10
            DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE
            20ITEM 11
            EXECUTIVE COMPENSATION
            21ITEM 12
            SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
      MANAGEMENT AND RELATED STOCKHOLDER MATTERS
            21ITEM 13
            CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
      DIRECTOR INDEPENDENCE
            22ITEM 14
            PRINCIPAL ACCOUNTING FEES AND SERVICES
            22PART
      IVITEM 15
            EXHIBITS, FINANCIAL STATEMENT SCHEDULES
            23








Table of Contents




FORWARD-LOOKING
STATEMENTS





Certain
statements in this Annual Report on Form 10-K (“Annual Report”) and the
documents Ridgewood Energy S 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 US Private Securities Litigation Reform
Act of 1995 that are based on current expectations and assumptions and are
subject to risks and uncertainties that may cause actual results to differ
materially from the forward-looking statements. You are therefore cautioned
against relying on any such forward-looking statements. Forward-looking
statements can generally be identified by words such as “believe,” “project,”
“expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,”
“pursue,” “may,” “will,” “will likely result,” and similar expressions and
references to future periods.  Examples of 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.  Examples of
forward-looking statements made herein include statements regarding future
projects, investments and insurance.  Forward-looking statements made
in this document speak only as of the date on which they are
made.  The Fund undertakes no obligation to update or revise publicly
any forward-looking statements, whether as a result of new information, future
events or otherwise, except as required by law.





WHERE
YOU CAN GET MORE INFORMATION





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









1
 Table of Contents




PART
I




ITEM
1.          BUSINESS




Overview




The Fund
is a Delaware limited liability company (“LLC”) formed on December 19, 2005
to acquire interests in oil and gas properties
located in the United States offshore waters of Texas, Louisiana and Alabama in
the Gulf of Mexico.




The Fund
initiated its private placement offering on February 1, 2006, selling whole and
fractional shares of LLC membership interests (“Shares”), primarily at $150
thousand per whole Share. There is no public market for the Shares and one is
not likely to develop. In addition, the Shares are subject to material
restrictions on transfer and resale and cannot be transferred or resold except
in accordance with the Fund’s limited liability company agreement (the “LLC
Agreement”) and applicable federal and state securities laws.  The private
placement offering was terminated on June 12, 2006. The Fund raised $124.4
million, and after payment of $19.9 million in offering fees, commissions and
investment fees, the Fund had $104.5 million for investments and operating
expenses.




Manager




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





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





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





As
compensation for its services, the Manager is entitled to an annual management
fee, payable monthly, equal to 2.5% of the total capital contributions made by
the Fund’s shareholders, net of cumulative dry-hole and related well costs
incurred by the Fund.  The Manager is entitled to receive an annual
management fee from the Fund regardless of the Fund’s profitability in that
year.  Management fees for the years ended December 31, 2009 and 2008
were $2.3 million and $2.4 million, respectively.  Additionally, the
Manager is entitled to receive a 15% interest in cash distributions made by the
Fund.  Distributions paid to the Manager for the years ended December
31, 2009 and 2008 were $1.3 million and $2.3 million, respectively.





Business
Strategy





The
Fund’s primary investment objective is to generate cash flow for distribution to
its shareholders by generating returns across a portfolio of exploratory or
development stage shallow water or deepwater projects.  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 Fund invests in the
drilling and development of both shallow and deepwater oil and natural gas
projects in the U.S. waters of the Gulf of Mexico, in partnership with leading
exploration and production companies.  Although the Fund focus is
primarily on exploratory oil and natural gas projects, it also investigates and,
if appropriate, invests in non-exploratory projects, such as producing projects
and projects that have proven undeveloped reserves, some of which may need
capital to construct, install or acquire the necessary infrastructure assets,
such as rigs, pipelines or other equipment needed to gather, process and
transport oil or natural gas.  Some of these non-exploratory projects
may also contain probable or possible reserves, which could be a factor in the
purchase price paid by the Fund to acquire such projects.  The Fund
rigorously screens and evaluates non-exploratory projects using the same
investment screening and selection process used for exploratory stage projects,
although, depending on the nature and type of a non-exploratory project,
additional or different evaluative tools and processes may be needed by the Fund
when evaluating such projects.




2
 Table of Contents




Investment
Strategy





The Fund
invests its capital with major operators through working interest with such
operators and, in some cases, other energy companies that also own or acquire
working interests in the projects.  A working interest is an undivided
fractional interest in a lease block acquired from the U.S. government or from
an operator who has acquired the working interest.  A working interest
includes the right to drill, produce and conduct operating activities and share
in any resulting oil and natural gas production.  It is standard
industry procedure for operators to take 25% to 50% interests in multiple
drilling projects, rather than 100% interests in a few projects, in order to
share risk, obtain independent technical validation and stretch exploration
budgets that are split across numerous regions of the
world.  Ridgewood Energy evaluates each project and its operator on an
individual project basis, allowing the Fund to invest in what Ridgewood Energy
believes are the projects with the most attractive risk/reward
ratios.  Critical to the success of this approach is the ability of
Ridgewood Energy to diversify the Fund’s portfolio across project types and
operators.  Attributes sought in projects for investment include:
depth of scientific analysis and preparation; strong potential project economics
and favorable operating agreement terms; similarity to existing producing
properties; and expertise of the operator in the proposed
region/geology/technical environment.  Attractive characteristics of
potential and existing operators include industry contacts and relationships,
sophisticated geological and geophysical teams and, most importantly, a strong
track record of success.





Invest
in “Drill-Ready” Exploratory Projects


Ridgewood
Energy’s strategy of investing the Fund’s capital alongside major operators only
at the drill-ready stage is designed to limit the Fund’s exposure to exploratory
risk.  A drill-ready project is one in which an operator has already
spent a significant amount of capital and technical resources on seismic and
engineering analysis to evaluate the opportunity, to complete the lease block
acquisition, to secure the drilling rights and to obtain internal management
approval to commit capital to begin drilling.  The upfront work
performed by the operator quantifies and reduces the Fund’s exposure to the risk
of drilling wells that are not commercially producible discoveries (or a dry
hole) and provides Ridgewood Energy with access to the analytics of
geoscientists and engineers and Gulf of Mexico operators.  In return,
the operator who performs this upfront work to generate the potential project
may receive a “promote” on the cost of the initial exploratory
well.  Under a promote arrangement, the Fund would pay a larger share
of the drilling costs of the first well.  For a successful well, all
of the Fund’s subsequent costs, including completion costs for the exploratory
well, the costs of all development wells, infrastructure costs such as
production platforms and pipelines, and day-to-day operating costs for the life
of the project, would be paid on a proportionate basis to its working interest
ownership.





Investment
Process


Although
Ridgewood Energy’s model of investing fund capital with operators affords it
access to industry-leading technical and engineering resources, Ridgewood Energy
performs its own due diligence on, and independently evaluates, all of the
projects in which the Fund invests and all investment decisions are based on the
collective analysis of the Ridgewood Energy management team.  The
Ridgewood Energy management team conducts an initial screening process to
identify new project investment opportunities utilizing their training,
experience and industry relationships.  Ridgewood Energy is selective
as to which projects it pursues.  Key criteria that form part of the
detailed evaluation include the identity of the operator and other partners, the
technical quality of the project, access to existing infrastructure, drilling
schedule and rig availability and project economics and terms.





Ridgewood
Energy maintains an investment committee consisting of five members, which
provides operational, financial, scientific and technical oil and gas expertise
to the Fund (the “Investment Committee”).  Four members of the
Investment Committee are based out of the Manager’s Montvale, New Jersey office
and one member is based out of the Manager’s Houston, Texas
office.  Once the technical and economic analyses of a potential
project are complete and a project has been deemed to satisfy Ridgewood Energy’s
technical criteria, provide an attractive economic risk/reward ratio, and fit
within Ridgewood Energy’s diversification strategy, final investment approval is
made by the Investment Committee.  When reviewing a project for final
investment approval, the Investment Committee seeks to balance the economics of
the projects, the potential sizes of the projects, the diversity of the
operators, and the likely timing of new projects   The Investment
Committee also considers the geological, financial and operating risks of the
proposed project and compares these risks to the existing portfolio of Ridgewood
Energy projects.  The Investment Committee further focuses on the
initial well cost relative to the overall revenue potential of the
project.




3
 Table of Contents




Participation
and Joint Operating Agreements


Once
Ridgewood Energy decides that a project is an appropriate investment for the
Fund, the Fund will seek to enter into a joint operating agreement with the
other working interest owners in a lease.  Ridgewood Energy negotiates
the joint operating agreement with the goal of achieving the best possible
economics and governance rights for the Fund in connection with acquiring the
interest.  Under the joint operating agreement, proposals and
decisions are made based on percentage ownership approvals and although an
operator’s percentage ownership may constitute a majority ownership, operators
generally seek consensus relating to project decisions.  As a result,
Ridgewood Energy and other partners generally retain the right to make proposals
and influence decisions involving certain operational matters associated with a
project.  This approval discretion and the operator’s desire to
execute the project efficiently and expeditiously can function to effectively
limit the operator’s inclination to act on its own, or against the interests of
the participants in the project.





Project
Information





Existing
projects, and future projects, if any, are expected to be located in the waters
of the Gulf of Mexico offshore from Texas, Louisiana and Alabama, on the Outer
Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“OCSLA”),
which was enacted in 1953, governs certain activities with respect to working
interests and the exploration of oil and natural gas in the OCS.  See
further discussion under the heading “Regulation” in this Item 1.
“Business”.





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





Leases in
the OCS are generally issued for a primary lease term of 5, 8 or 10 years
depending on the water depth of the lease block. The 5-year lease term is for
blocks in water depths generally less than 400 meters, 8 years for depths
between 400 meters and 800 meters and 10 years for depths in excess of 800
meters. During this primary lease term, except in limited circumstances, lessees
are not subject to any particular requirements to conduct exploratory or
development activities. However, once a lessee drills a well and begins
production, the lease term is extended for the duration of commercial
production.





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





Generally,
working interests in an offshore natural gas lease under the OCSLA pay a 16.67%
or 18.75% royalty to the Mineral Management Services (“MMS”) for shallow-water
projects, dependent upon the lease date, and a 12.5% royalty to the MMS for
deepwater projects. Therefore, the net revenue interest of the holders of 100%
of the working interest in the projects in which the Fund will invest is between
81.25% and 83.33% of the total revenue for shallow-water projects and 87.5% of
the total revenue for deepwater projects, and, such net revenue amount 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.  Other than MMS royalties, the Fund does not have material
royalty burdens.





Mineral
Management Services Deep Gas Royalty Incentive





On
January 26, 2004, the MMS promulgated a rule providing incentives for companies
to increase deep oil and natural gas production in the Gulf of Mexico (the
"Royalty Relief Rule"). Under the Royalty Relief Rule, lessees will be eligible
for royalty relief on their existing leases if they drill and perforate wells
for new and deeper reserves at depths greater than 15,000 feet subsea. In
addition, an even larger royalty relief would be available for wells drilled and
perforated deeper than 18,000 feet subsea. It should be noted that the Royalty
Relief Rule does not extend to deep waters of the Gulf of Mexico off the
continental shelf nor does it apply if the price of natural gas exceeds $10.48
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.




4
 Table of Contents




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





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




Properties




The Fund
owns working interests in thirteen wells; one is expected to commence drilling
in March 2010, one is currently drilling, six are discoveries, one is fully
depleted and four have been determined to be dry holes.








5
 Table of Contents


Off-shoreLocation
      in
                
                
                
                
                DrillingWorking
                Gulf
      of
                
                Target
                
                
                Risk
                
                
                Total
      Spent ThroughLease
      Block
                
                Interest
                Mexico
                
                Depth
                
                
                (b)
                
                
                December
      31, 2009(feet)
                
                
                (in
      thousands)Future
      and Current ProjectsBeta
      Project
                
                
                2.5
                %
                Louisiana
                
                
                20,000
                
                
                $
                1,721
                
                
                $
                -Targa
      Project
                
                
                2.0
                %
                Louisiana
                
                
                16,500
                
                
                $
                2,062
                
                
                $
                -DiscoveriesAspen
      Project
                
                
                2.25
                %
                Louisiana
                
                
                22,000
                
                
                
                N/A
                
                
                $
                4,284West
      Cameron 75
                
                
                20.0
                %
                Louisiana
                
                
                23,800
                
                
                
                N/A
                
                
                $
                23,786Main
      Pass 275
                
                
                30.0
                %
                Louisiana
                
                
                11,200
                
                
                
                N/A
                
                
                $
                5,764South
      Marsh Island 111
                
                
                22.5
                %
                Louisiana
                
                
                11,600
                
                
                
                N/A
                
                
                $
                6,243West
      Delta 68
                
                
                22.5
                %
                Louisiana
                
                
                14,000
                
                
                
                N/A
                
                
                $
                4,598West
      Delta 67
                
                
                22.5
                %
                Louisiana
                
                
                14,000
                
                
                
                N/A
                
                
                $
                2,957Fully
      Depleted2009Vermilion
      344
                
                
                22.5
                %
                Louisiana
                
                
                8,900
                
                
                
                N/A
                
                
                $
                7,339Dry
      Holes(a)2008Ruby
      Project
                
                
                18.0
                %
                Louisiana
                
                
                N/A
                
                
                
                N/A
                
                
                $
                3,279
  (a)
              Dry-hole
      costs represent costs incurred for wells that have been drilled but do not
      have commercially productive quantities of oil and/or natural gas
      reservoirs and have been plugged and abandoned.(b)
              Drilling
      risk represents the Fund’s committed exposure for estimated costs incurred
      prior to the determination of a well’s commercial
      productivity.  Such costs include costs for drilling the well
      and testing for the presence of hydrocarbons, as well as the cost for
      leasing land, seismic purchase and reprocessing.  Under the
      successful efforts method of accounting for oil and gas properties, the
      Fund capitalizes such costs pending determination of whether the well
      contains proved commercial reserves.  If proved commercial
      reserves are not found, such costs are expensed as dry-hole costs. The
      Fund expects such costs to be incurred within one year of the onset of
      drilling.







Beta
Project


In
February 2010, the Fund acquired a 2.5% working interest in the Beta Project, an
exploratory well.   The Beta Project is expected to commence
drilling in March 2010 and results are expected during the third quarter
2010.  The Fund’s total estimated capital budget for this well is $4.3
million.  At December 31, 2009, the Fund had not incurred capital
costs related to this well.





Targa
Project


Effective
September 2009, the Fund acquired a 2.0% working interest in the Targa Project,
an exploratory well.  The Targa Project began drilling in February
2010 and results are expected in the second quarter 2010.  The Fund’s
total estimated capital budget for this well is $7.7 million.  At
December 31, 2009, the Fund had not incurred capital costs related to this
well.





Aspen
Project


In July
2008, the Fund acquired a 2.25% working interest in the Aspen Project, an
exploratory well.  In April 2009, the first well of the
Aspen Project found hydrocarbons in three separate zones.  Second and
third delineation wells were drilled from during the third quarter 2009. 
The operator and working interest owners are continuing to evaluate possible
development plans and determine the economics of the completion and further
drilling.  The Aspen Project is a deepwater project that requires
significant infrastructure construction.  Through December 31, 2009, the
Fund has capitalized $4.3 million, net of insurance recoveries, related to this
project, for which the Fund’s total estimated capital budget is $8.0 million,
which includes two additional wells.  During the year ended December
31, 2009, the Fund received $0.4 million in connection with an insurance claim
filed by the operator of the Aspen Project related to an insurable event that
had occurred during the drilling of the well.




6
 Table of Contents




West
Cameron 75


In 2007,
the Fund acquired a 20.0% working interest in West Cameron 75, an exploratory
well.  The well was determined to be a discovery and production
commenced in 2007.  During November 2009, West Cameron 75 experienced
a production interruption related to a mechanical flow problem, which required a
workover of the well at a cost to the Fund of $0.3 million.  Upon
completion of the workover, the operator determined that a more extensive
sidetrack operation was required.  The sidetrack was completed in
January 2010 at a cost of $1.6 million to the Fund, of which $0.4 million was
incurred in 2009.  The well successfully resumed production in January
2010.  The Fund has capitalized $23.8 million related to this
well.





Main
Pass 275


In 2006,
the Fund acquired a 30.0% working interest in the Main Pass 275, an exploratory
well.  The well was determined to be a discovery and production
commenced in 2007.  The Fund has capitalized $5.8 million related to
this well.





LLOG
Projects:


In 2006,
the Fund acquired a 22.5% working interest in each of six exploratory wells from
LLOG Exploration Offshore, Inc. (“LLOG”), the operator, off the coast of
Louisiana.  Of the six wells, the Fund elected not to proceed with one
well and one well was determined to be a dry hole.





The Fund
has capitalized $21.1 million related to the four exploratory wells, which were
determined to be discoveries during 2007.  At December 31, 2009, the
Fund has additional amounts budgeted for these wells totaling $1.7 million,
related to various recompletion efforts.  At December 31, 2009,
Vermilion 344 was determined to be fully depleted by the Fund’s independent
petroleum engineer, Ryder Scott Company, L.P. (“Ryder Scott”).  During
the years ended December 31, 2009 and 2008, the Fund recorded impairments
related to Vermilion 344 totaling $2.8 million and $3.4 million,
respectively.





South
      Marsh Island 111
            Discovery
      July 2007; Production commenced February 2009Vermilion
      344
            Discovery
      January 2007; Production commenced December 2008; Fully depleted at
      December 31, 2009West
      Delta 68
            Discovery
      March 2007; Production commenced July 2008West
      Delta 67
            Discovery
      November 2007; Production commenced July
2008





Oil
and Natural Gas Agreements





The Fund
has entered into a 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
the oil and natural gas it sells. All of the Fund’s current projects are near
existing transportation infrastructure and pipelines.  The Manager
believes that it is likely that oil and natural gas from the Fund’s future
projects will have access to pipeline transportation and can be marketed in a
similar fashion.





Operator





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




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




7
 Table of Contents




Insurance





The
Manager has obtained and maintains what it believes to be adequate insurance for
the funds that it manages.  The Manager has obtained hazard, property,
general liability and other insurance in commercially reasonable amounts to
cover its projects, as well as general liability, directors’ and officers’
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.  Further, for the policy period August
2009 through July 2010, the Manager did not obtain coverage for named
windstorm.  As a result of the losses underwriters incurred from
claims arising from Hurricane Ike, a named windstorm in September 2008, the
Manager determined that the premiums sought by underwriters for, and the
deductibles applicable to, coverage for named windstorm made obtaining such
coverage for such policy period prohibitively expensive.  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.  The Manager will re-evaluate its coverage on an annual
basis.  While the Manager believes it has obtained adequate insurance
in accordance with customary industry practices, the possibility exists,
depending on the extent of the incident, that insurance coverage may not be
sufficient to cover all losses.  In addition, depending on the extent,
nature and payment of any claims to the Fund's affiliates, yearly insurance
limits may be exhausted and become insufficient to cover a claim made by the
Fund in a given year.  During the year ended December 31, 2009, the
Fund received $0.4 million in connection with an insurance claim related to the
Aspen Project.





Salvage
Fund




As to
projects in which the Fund owns a working interest, the Fund deposits in a
separate interest-bearing account, or salvage fund, which is in the nature of a
sinking fund, cash to provide for the Fund’s proportionate share of the
anticipated cost of dismantling production platforms and facilities, plugging
and abandoning the wells, and removing the platforms, facilities and wells in
respect of the projects after the end of their useful lives, in accordance with
applicable federal and state laws and regulations.  The Fund has
deposited $2.2 million from capital contributions into a salvage fund, which,
along with interest earned on this account, the Fund estimates to be sufficient
to meet the Fund’s potential requirements. If, at any time, the Manager
determines the salvage fund will not be sufficient to cover the Fund’s
proportionate share of expense, the Fund may transfer amounts from capital
contributions or operating income to fund the deficit.  Payments to
the salvage fund will reduce the amount of cash distributions that may be made
to investors by the Fund.  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 restrictions on the withdrawal or use of the
salvage fund.





Seasonality





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





The
Fund’s properties are located in the Gulf of Mexico; therefore its operations
and cash flows may be significantly impacted by hurricanes and other inclement
weather.  Such events may also have a detrimental impact on
third-party pipelines and processing facilities, upon which the Fund relies to
transport and process the oil and natural gas it produces. The National
Hurricane Center defines hurricane season in the Gulf of Mexico as June 1st
through November 30th. The Fund did not experience any damage or shut-ins, or
production stoppages, due to hurricane activity in 2009.





Customers





All of
the oil and natural gas production from the Fund’s producing properties is sold
by a third party.  As a result, the Fund did not contract to sell oil and
natural gas to customers.  Therefore, the Fund had no customers or any one
or few major customers upon which it depends.




8
 Table of Contents




Energy
Prices





Historically,
the markets for and prices of 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 oil and natural gas with any certainty.  Low commodity
prices could have an adverse affect on the Fund’s future
profitability.





Competition





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





In many
instances, the Fund competes for projects with large independent oil and natural
gas producers who generally have significantly greater access to capital
resources, have a larger staff, and more experience in oil and natural gas
exploration and production than the Fund. As a result, these larger companies
are in a position that they could outbid the Fund for a project. However,
because these companies are so large and have such significant resources, they
tend to focus more on projects that are larger, have greater reserve potential,
and cost significantly more to explore and develop.  The focus of
these companies on larger projects does not necessarily mean that they will not
investigate and/or acquire projects for which the Fund typically
competes.  The Manager is often able to win project participations
ahead of such competitors for the following reasons: (i) Ridgewood Energy has an
investment process that is not subject to the more layered decision-making
processes that typically exist within large oil and gas companies; such
processes enable Ridgewood Energy to assimilate financial, seismic and
operational data in relation to a prospective project and assess the terms on
which the project is being offered, which the Fund believes puts Ridgewood
Energy in a position to reach an investment decision well in advance of most
large oil and gas companies, (ii)  Ridgewood Energy is one of the most
active exploration and production participants in the Gulf of Mexico, and as a
result, the management team is in regular contact with all the major operators
and is therefore able to contribute valuable perspectives both from a geological
and operational viewpoint and (iii) Ridgewood Energy is typically not viewed as
a competitor by the syndicating operator, as Ridgewood Energy does not
participate in lease block sales but only invests in drill-ready syndicated
projects.




Employees





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





Offices





The
principal executive office of the Fund and the Manager is located at 14 Philips
Parkway, Montvale, NJ 07645, and its phone number is 800-942-5550. The Manager
leases additional office space at 11700 Old Katy Road, Houston, TX
77079.  In addition, the Manager 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.





The
Fund’s projects are located in the offshore waters of the Gulf of Mexico on the
OCS. The Fund’s operations and activities are therefore governed by the OCSLA
and certain other laws and regulations described herein.




9
 Table of Contents




Outer
Continental Shelf Lands Act





Under the
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.  The Fund is not
involved in the process of obtaining any such approvals or permits. Offshore
operations are subject to numerous regulatory requirements, including stringent
engineering and construction specifications related to offshore production
facilities and pipelines and safety-related regulations concerning the design
and operating procedures of these facilities and pipelines. MMS regulations also
restrict the flaring or venting of production and proposed regulations would
prohibit the flaring of liquid hydrocarbons and oil without prior
authorization.





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





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





Sales
and Transportation of Oil and Natural Gas





The Fund
sells its proportionate share of oil and natural gas, through the operator on
the Fund’s behalf, 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, it 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 OCSLA, the Natural Gas Policy Act and the Energy Policy
Act of 1992. Generally, depending on certain factors, pipelines can charge rates
that are either market-based or cost-of-service. In some circumstances, rates
can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge
the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such
rates would apply uniformly to all transporters on that pipeline and, as a
result, management does not anticipate that the impact to the Fund of any
changes in such rates, terms or conditions would be materially different than
the impact upon other oil or natural gas producers and marketers.





Environmental
Matters and Regulation





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




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





The Oil Pollution
Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends
Section 311 of the Federal Water Pollution Control Act of 1972 (the “Clean Water
Act”) and was enacted in response to the numerous tanker spills, including the
Exxon Valdez, that occurred in the 1980s. Among other things, the OPA clarifies
the federal response authority to, and increases penalties for, such 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.




10
 Table of Contents




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





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





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





Other
Environmental Laws. In addition to the above, the Fund’s operations may
be subject to the Resource
Conservation and Recovery Act of 1976, as amended, which regulates the
generation, transportation, treatment, storage, disposal and cleanup of certain
hazardous wastes, as well as the Comprehensive
Environmental Response, Compensation and Liability Act, which imposes
joint and several liability without regard to fault or legality of conduct on
classes of persons who are considered responsible for the release of a hazardous
substance into the environment.





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





ITEM
1A.  RISK FACTORS





Not
required.





ITEM
1B.  UNRESOLVED STAFF COMMENTS





Not
applicable.




ITEM
2.     PROPERTIES




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





Unaudited
Oil and Gas Reserve Quantities


The
preparation of the Fund’s oil and gas reserve estimates are completed in
accordance with the Fund’s internal control procedures over reserve
estimation.  The Fund’s management controls over proved reserve estimation
include: 1) verification of input data that is provided to an independent
petroleum engineering firm, 2) engagement of well-qualified and independent
reservoir engineers for preparation of reserve reports annually in accordance
with SEC reserve estimation guidelines and 3) a review of the reserve estimates
by the Manager.




11
 Table of Contents




The
Fund’s reserve estimates at December 31, 2009 and 2008 were prepared by Ryder
Scott, an independent petroleum engineering firm.  The information
regarding the qualifications of the petroleum engineer is included within the
report from Ryder Scott, which is included as Exhibit 99 of this Annual Report,
and is incorporated herein by reference.





Proved
oil and gas reserves are the estimated quantities of oil and natural gas, which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.  Proved developed oil and gas reserves are those
reserves expected to be recovered through existing wells with existing equipment
and operating methods.  The information regarding the Fund’s proved
reserves, which is contained in Item 7. “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” of this Annual Report under the
heading “Critical Accounting Estimates – Proved Reserves”, is incorporated
herein by reference.  The information regarding the Fund’s unaudited net
quantities of proved developed and undeveloped reserves, which is contained in
Table III in the “Supplementary Financial Information – Information about Oil
and Gas Producing Activities – Unaudited” included in Item 15.  “Exhibits,
Financial Statement Schedules” of this Annual Report, is incorporated herein by
reference.





Proved Undeveloped
Reserves.At December 31, 2009,
the Fund had approximately 7 thousand barrels and 5.1 million mcf of proved
undeveloped oil and natural gas reserves, respectively, related to South Marsh
Island 111 and West Cameron 75.The Fund is currently
evaluating the development alternatives for these proved undeveloped
reserves.  The Fund had no proved
undeveloped reserves at December 31, 2008.





Production
and Prices


The
information regarding the Fund’s production of oil and natural gas, and certain
price and cost information for the years ended December 31, 2009 and 2008 that
is contained in Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” of this Annual Report under the headings
“Results of Operations – Oil and Gas Revenue” and “Results of Operations –
Operating Expenses” is incorporated herein by reference.




ITEM
3.         LEGAL
PROCEEDINGS




None.




ITEM
4.         (REMOVEDAND RESERVED)









12
 Table of Contents




PART
II






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




There is
currently no established public trading market for the Shares.  As of
the date of this filing, there were 1,311 shareholders of record of the
Fund.




Distributions
are made in accordance with the provisions of the LLC Agreement.  At
various times throughout the year, the Manager determines whether there is
sufficient available cash, as defined in the LLC Agreement, for distribution to
shareholders.  There is, however, no requirement to distribute
available cash and as such, available cash is distributed to the extent and at
such times as the Manager believes is advisable.  During the years
ended December 31, 2009 and 2008, the Fund paid distributions totaling $8.9
million and $15.6 million, respectively.




ITEM
      6.
            SELECTED FINANCIAL DATA




Not
required.




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




Overview
of the Fund’s Business


The Fund
was organized to acquire interests in oil and gas properties located in the
United States offshore waters of Texas, Louisiana and Alabama in the Gulf of
Mexico. The Fund’s primary investment objective is to generate cash flow for
distribution to its shareholders by generating returns across a portfolio of
exploratory or development stage shallow water or deepwater
projects.  However, the Fund is not required to make distributions to
shareholders except as provided in the LLC Agreement.





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





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


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




13
 Table of Contents




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





Unproved
Property


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





Proved
Reserves


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





Asset
Retirement Obligations


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





Impairment
of Long-Lived Assets


The Fund
reviews the value of its oil and gas properties whenever management determines
that events and circumstances indicate that the recorded carrying value of
properties may not be recoverable.  Impairments of producing
properties are determined by comparing future net undiscounted cash flows to the
net book value at the end of each period.  If the net book value
exceeds the future net undiscounted cash flows, the carrying value of the
property is written down to “fair value,” which is determined using net
discounted future cash flows from the producing property.  Different
pricing assumptions, reserve estimates or discount rates could result in a
different calculated impairment.  The Fund provides for impairments on
unproved properties when it determines that the property will not be developed
or a permanent impairment in value has occurred.  Given the volatility
of oil and natural gas prices, it is reasonably possible that the Fund’s
estimate of discounted future net cash flows from proved oil and natural gas
reserves could change in the near term.  If oil and natural gas prices
decline significantly, even if only for a short period of time, it is possible
that write-downs of oil and gas properties could occur.




14
 Table of Contents




Results
of Operations




The following table summarizes the Fund’s results of
operations for the years ended December 31, 2009 and 2008 and should be
read in conjunction with the Fund’s financial statements and the notes thereto
included within Item 8. “Financial Statements and Supplementary Data” in this
Annual Report.




Year
      ended December 31,2009
              
              
              2008(in
      thousands)RevenueOil
      and gas revenue
              
              $
              8,962
              
              
              $
              19,032ExpensesDepletion
      and amortization
              
              
              7,898
              
              
              
              4,937Impairment
      of proved properties
              
              
              2,785
              
              
              
              3,407Dry-hole
      costs
              
              
              (30
              )
              
              
              3,193Management
      fees to affiliate
              
              
              2,284
              
              
              
              2,356Operating
      expenses
              
              
              1,450
              
              
              
              659Workover
      expenses
              
              
              397
              
              
              
              5General
      and administrative expenses
              
              
              455
              
              
              
              553Total
      expenses
              
              
              15,239
              
              
              
              15,110(Loss)
      income from operations
              
              
              (6,277
              )
              
              
              3,922Other
      incomeInterest
      income
              
              
              357
              
              
              
              926Realized
      gain on sale of marketable securities
              
              
              -
              
              
              
              325Total
      other income
              
              
              357
              
              
              
              1,251Net
      (loss) income
              
              
              (5,920
              )
              
              
              5,173Other
      comprehensive (loss) incomeUnrealized
      (loss) gain on
                marketable
      securities
              
              
              (246
              )
              
              
              487Total
      comprehensive (loss) income
              
              $
              (6,166
              )
              
              $
              5,660







Overview.
Since inception, the Fund has had six wells come onto production: Main Pass 275
in April 2007; West Cameron 75 in December 2007; West Delta 67 and West Delta 68
in July 2008, Vermilion 344 in December 2008 and South Marsh Island 111 in
February 2009.  Vermilion 344 was fully depleted as of December 31,
2009.





During the years ended December 31, 2009 and 2008, the
Fund’s revenue, depletion and amortization and lease operating expense were
affected by the timing of the onset of production of the Fund’s wells and by
the the impact of temporary shut-ins.  West Cameron 75 was
shut-in for approximately two months during 2009, due to mechanical issues, and
for approximately three months during 2008 due to hurricane
activity.  Hurricane activity also causedMain Pass 275 to be
shut-in for several weeks and West Delta 67 and West Delta 68 to be shut-in for
one month during 2008.  As previously
discussed in Item 1. “Business”, hurricane activity in the third quarter of 2008
did not cause material damage to any of the Fund’s wells or facilities, however,
damage to certain pipelines, coastal refineries and gas processing plants did
cause certain wells to be temporarily shut-in.





Oil and Gas
Revenue.Oil and gas revenue for the year ended December 31, 2009
was $9.0 million, a $10.1 million decrease from the year ended December 31,
2008.  The decrease is attributable to the impact of decreased average
prices totaling $12.0 million partially offset by an increase in sales volumes
totaling $2.0 million.





Oil sales
volumes were 20 thousand barrels and 25 thousand barrels for the years ended
December 31, 2009 and 2008, respectively.  The Fund’s oil prices
averaged $52 per barrel and $94 per barrel during the years ended December 31,
2009 and 2008, respectively.




15
 Table of Contents




Gas sales
volumes were 2.0 million mcf and 1.7 million mcf for the years ended December
31, 2009 and 2008, respectively.  The Fund’s gas prices averaged $3.72
per mcf and $9.34 per mcf during the years ended December 31, 2009 and 2008,
respectively.





The
decrease in oil volumes was primarily attributable to decreased production rates
for West Delta 67, West Delta 68 and Main Pass 275, due to natural declines in
production.  These decreases were partially offset by the onset of
production of South Marsh Island 111.





The increase in gas volumes was primarily attributable
to the onset of production of the Fund’s wells, as discussed above in
“Overview”, partially offset by a decrease in production for West Cameron
75.During November 2009, West Cameron 75 experienced a
production interruption related to a mechanical flow problem, which required a
workover and an extensive sidetrack, which was completed in January
2010.  See Item 1. “Business” for
additional information.





Depletion and
Amortization.  Depletion and amortization for the year ended
December 31, 2009 was $7.9 million, an increase of $3.0 million from the year
ended December 31, 2008.  The increase
resulted from an increase in average depletion rates totaling $2.2 million,
coupled with the impact of the increase in production volumes totaling $0.7
million.The increase in depletion rates was primarily the
result of higher cost reserve additions, principally attributable to Vermilion
344 and South Marsh Island 111, partially offset by decreased rates for Main
Pass 275 due to revisions of reserve estimates.





Impairment of
Proved Properties.  During the
year ended December 31, 2009, the Fund recorded impairments of proved properties
totaling $2.8 million, relating to Vermilion 344, which were attributable to
lower oil and gas commodity prices, a reduction in the Fund’s estimates of
proved oil and gas reserves, and the year-end determination that the well wasfully depleted.  During the year
ended December 31, 2008, the Fund recorded impairments of proved properties
totaling $3.4 million, relating to Vermilion 344, which were attributable to
increased project costs, lower oil and gas commodity prices and a reduction in
the Fund’s estimates of proved oil and gas reserves.  See additional
discussion in Item 1. “Business”.





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.  At times, the Fund receives
credits on certain wells from their respective operators upon review and audit
of the wells’ costs.  Dry-hole costs, inclusive of such credits, are
detailed in the following table.





Year
      ended December 31,Lease
      Block
              
              2009
              
              
              2008(in
      thousands)Ruby
      Project
              
              $
              (184
              )
              
              $
              3,464Other
      wells
              
              
              154
              
              
              
              (271
              )$
              (30
              )
              
              $
              3,193




Management Fees
to Affiliate.Management fees for the years ended December 31,
2009 and 2008 were $2.3 million and $2.4 million, respectively.  An
annual management fee, totaling 2.5% of total capital contributions, net of
cumulative dry-hole and related well costs incurred by the Fund, is paid monthly
to the Manager.  See additional discussion in Item 1.
“Business”.




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




Year
      ended December 31,2009
              
              
              2008(in
      thousands)Lease
      operating expense
              
              $
              1,264
              
              
              $
              610Geological
      costs
              
              
              150
              
              
              
              37Accretion
      expense
              
              
              36
              
              
              
              12$
              1,450
              
              
              $
              659




16
 Table of Contents





Lease
operating expense for the years ended December 31, 2009 and 2008 was related to
the Fund’s producing properties during each year as outlined above in
“Overview”. For the year ended
December 31, 2009, average production cost was $0.57 per mcfe compared to $0.31
per mcfe for the year ended December 31, 2008.  Geological costs for
the year ended December 31, 2009 related primarily to geological surveys related
to the Aspen and Targa projects.  Geological costs for the year ended
December 31, 2008 related primarily to geological surveys for the Ruby Project.
Accretion expense is related to the asset
retirement obligations established for the Fund’s proved
properties.





Workover
Expenses.  Workover expenses represent costs to restore or
stimulate production of existing reserves of a proved
property.  During the year ended December 31, 2009, workover expenses
of $0.3 million related to West Cameron 75, which experienced a mechanical flow
problem and workover expenses of $0.1 million related to well maintenance for
West Delta 67.  Workover expenses were $5 thousand during the year
ended December 31, 2008.





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




Year
      ended December 31,2009
              
              
              2008(in
      thousands)Insurance
      expense
              
              $
              239
              
              
              $
              246Accounting
      fees
              
              
              186
              
              
              
              242Trust
      fees and other
              
              
              30
              
              
              
              65$
              455
              
              
              $
              553




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





InterestIncome.  Interest income is
comprised of interest earned on money market accounts and investments in U.S.
Treasury securities.Interest income for the year ended
December 31, 2009 was $0.4 million, a $0.6 million decrease from the year ended
December 31, 2008.  The decrease was the result of a reduction in
average outstanding balances earning interest, due to ongoing capital
expenditures for oil and gas properties, coupled with lower interest rates
earned.





Realized Gain on
Sale of Marketable Securities.During the first quarter of
2008, the Fund sold $10.0 million of its available-for-sale marketable
securities, which resulted in a realized gain of $0.3 million.





Unrealized (Loss)
Gain on Marketable Securities.During 2007, the Fund
purchased available-for-sale U.S. Treasury securities, which mature in December
2010.  Unrealized gains and losses related to the securities' change
in fair value are recorded in other comprehensive income until
realized.  The Fund recorded unrealized losses of $0.2 million and
unrealized gains of $0.5 million during years ended December 31, 2009 and 2008,
respectively.




Capital
Resources and Liquidity




Operating
Cash Flows


Cash
flows provided by operating activities for the year ended December 31, 2009 were
$5.8 million, primarily related to revenue receipts of $9.6 million, interest
received of $0.5 million and favorable working capital of $0.2 million,
partially offset by management fees of $2.3 million, operating and workover
expenses totaling $1.8 million and general and administrative expenses of $0.5
million.





Cash
flows provided by operating activities for the year ended December 31, 2008 were
$15.9 million, primarily related to revenue receipts of $18.9 million and
interest received of $0.6 million, partially offset by management fees of $2.4
million, operating and workover expenses totaling $0.7 million and general and
administrative expenses $0.6 million.





Investing
Cash Flows


Cash
flows used in investing activities for the year ended December 31, 2009 were
$8.0 million, related to capital expenditures for oil and gas properties of $7.2
million and investments in the salvage fund of $1.2 million, inclusive of the
interest earned on this account, partially offset by insurance proceeds, related
to the Aspen Project claim, of $0.4 million.




17
 Table of Contents




Cash
flows provided by investing activities for the year ended December 31, 2008 were
$8.5 million, primarily related to proceeds from the sales and maturity of U.S.
Treasury securities of $37.4 million partially offset by capital expenditures
for oil and gas properties of $18.8 million and investments in U.S. Treasury
securities of $10.0 million.





Financing
Cash Flows


Cash
flows used in financing activities for the year ended December 31, 2009 were
$8.9 million, related to manager and shareholder distributions.





Cash
flows used in financing activities for year ended December 31, 2008 were $15.6
million related to manager and shareholder distributions.




Estimated
Capital Expenditures




The Fund
has entered into multiple agreements for the acquisition, 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, 2009,
the Fund had committed to spend an additional $18.6 million related to its
investment properties, of which $9.2 million is expected to be incurred during
the next twelve months.





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





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





Liquidity
Needs





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





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





Distributions,
if any, are funded from available cash from operations, as defined in the LLC
Agreement, and the frequency and amount are within the Manager’s
discretion.





Off-Balance
Sheet Arrangements





The Fund
had no off-balance sheet arrangements at December 31, 2009 and 2008 and does not
anticipate the use of such arrangements in the future.





Contractual
Obligations





The Fund
enters into participation and operating agreements with operators.  On
behalf of the Fund, an operator enters into various contractual commitments
pertaining to exploration, development and production activities.  The
Fund does not negotiate any contracts.  No contractual obligations
exist at December 31, 2009 and 2008 other than those discussed in “Estimated
Capital Expenditures” above.




Recent
Accounting Pronouncements




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




18
 Table of Contents


ITEM
      7A.
              QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK




Not
required.




ITEM
      8.
            FINANCIAL STATEMENTS AND SUPPLEMENTARY
  DATA




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


ITEM
      9.
              CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
      FINANCIAL DISCLOSURE
 
 None.


ITEM
      9A.
                CONTROLS
      AND
PROCEDURES




Disclosure
Controls and Procedures


Under the
supervision and with the participation of the Chief Executive Officer and Chief
Financial Officer of the Fund, management of the Fund and the Manager carried
out an evaluation of the effectiveness of the design and operation of the Fund’s
disclosure controls and procedures as defined in the Exchange Act Rule 13a-15(e)
as of December 31, 2009.  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, 2009.  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,
2009, 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.
Management’s report was not subject to attestation by the Fund’s registered
public accounting firm pursuant to temporary rules of the Securities and
Exchange Commission that permit the Fund to provide only management’s report in
this Annual Report.




Changes
in Internal Control over Financial Reporting


The Chief
Executive Officer and Chief Financial Officer of the Fund have concluded that
there have not been any changes in the Fund’s internal control over financial
reporting during the quarter ended December 31, 2009 that have materially
affected, or are reasonably likely to materially affect, the Fund’s internal
control over financial reporting.


ITEM
      9B.
                  OTHERINFORMATION


None.




19
 Table of Contents




PART
III




ITEM
      10.
            DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE




The Fund
has engaged Ridgewood Energy as the Manager.  The Manager has very
broad authority, including the authority to appoint the executive officers of
the Fund.  Executive officers of Ridgewood Energy and the Fund and
their ages at December 31, 2009 are as follows:




Officer
      ofRidgewood
      EnergyName,
      Age and Position with Registrant
              
              Corporation
      SinceRobert
      E. Swanson, 62Chief
      Executive Officer
              
              1982Kenneth
      W. Lang, 55President
      and Chief Operating Officer
              
              2009Kathleen
      P. McSherry, 44Executive
      Vice President andChief
      Financial Officer
              
              2001Robert
      L. Gold, 51Executive
      Vice President
              
              1987Daniel
      V. Gulino, 49Senior
      Vice President and General Counsel
              
              2003




The
officers in the above table have also been officers of the Fund since December
19, 2005, the date of inception of the Fund, with the exception of Mr. Lang who
has been an officer of Ridgewood Energy and the Fund since June
2009.  The officers are employed by and paid exclusively by the
Manager.  Set forth below is certain biographical information
regarding the executive officers of Ridgewood Energy and the Fund:





Robert E. Swanson has served
as the Chairman, Chief Executive Officer, and controlling shareholder of
Ridgewood Energy since its inception and is the Chairman of the Investment
Committee.  Mr. Swanson is also the Chairman of Ridgewood Renewable
Power, LLC and Ridgewood Capital Management, LLC, and President of Ridgewood
Securities Corporation, affiliates of Ridgewood Energy. 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.





Kenneth W. Langhas served as
the President and Chief Operating Officer of Ridgewood Energy since June 2009
and is a member of the Investment Committee.  Prior to joining the
Fund, Mr. Lang was with BP for twenty-four years, ultimately serving as Senior
Vice President for BP's Gulf of Mexico business and a member of the Board of
Directors for BP America, Inc.  Mr. Lang is a graduate of the
University of Houston.





Kathleen P. McSherry has
served as the Executive Vice President and Chief Financial Officer of Ridgewood
Energy since 2001 and is a member of the Investment Committee. Ms. McSherry also
serves as Vice President of Systems and Administration of Ridgewood Power. Ms.
McSherry holds a Bachelor of Science degree in Accounting.





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




20
 Table of Contents




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





Board
of Directors and Board Committees


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





Code
of Ethics


The
Manager of the Fund has adopted a code of ethics for all employees, including
the Manager’s principal executive officer and principal financial and accounting
officer. If any amendments are made to the code of ethics or the Manager of the
Fund grants any waiver, including any implicit waiver, from a provision of the
code to any of the Manager’s executive officers, the Fund will disclose the
nature of such amendment or waiver on our website or in a current report on Form
8-K.  Copies of the code of ethics are available, without charge, on
the Manager’s website at www.ridgewoodenergy.com and in print upon written
request to the business address of the Manager at 14 Philips Parkway, Montvale,
New Jersey 07645, ATTN:  General Counsel.





Section
16(a) Beneficial Ownership Reporting Compliance


Section
16(a) of the Exchange Act, as amended, requires the Fund’s executive officers
and directors, and persons who own more than 10% of a registered class of the
Fund’s equity securities, to file reports of ownership and changes in ownership
with the SEC. Based on a review of the copies of reports furnished or otherwise
available to the Fund, the Fund believes that during the year ended December 31,
2009, all filing requirements applicable to its officers, directors and 10%
beneficial owners were met.


ITEM
      11.
              EXECUTIVE
COMPENSATION


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




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




The
following table sets forth information with respect to beneficial ownership of
the shares as of March 16, 2010 (no person owns more than 5% of the shares)
by:




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


•
            all
      of the executive officers as a
group.




Beneficial
ownership is determined in accordance with the rules of the SEC and includes
voting or investment power with respect to the securities. Except as indicated
by footnote, and subject to applicable community property laws, the persons
named in the table below have sole voting and investment power with respect to
all shares shown as beneficially owned by them. Percentage of beneficial
ownership is based on 839.5395 shares outstanding at March 16, 2010. Other than
as indicated below, no officer of the Manager or the Fund owns any of the
Shares.




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





*
Represents less than one percent.


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





21
 Table of Contents




ITEM
      13.
            CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE




The LLC
Agreement provides that the Manager render management, administrative and
advisory services. For such services, the Manager is paid an annual management
fee, payable monthly, of 2.5% of total capital contributions, net of cumulative
dry-hole and related well costs incurred by the Fund.  Management fees
were $2.3 million and $2.4 million for the years ended December 31, 2009 and
2008, respectively.




The
Manager is entitled to receive a 15% interest in cash distributions made by the
Fund.   Distributions paid to the Manager forthe years ended December 31, 2009 and 2008,were
$1.3 million and $2.3 million,
respectively.





At times,
short-term payables and receivables, which do not bear interest, arise from
transactions with affiliates in the ordinary course of business.





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





The Fund
has working interest ownership in certain projects to acquire and develop oil
and natural gas projects with other entities that are likewise managed by the
Manager.  See the discussion under the heading “Properties” in Item 1.
“Business”.




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




ITEM
      14.
            PRINCIPAL ACCOUNTING FEES AND
  SERVICES




The
following table presents fees for services rendered by Deloitte & Touche LLP
for the years ended December 31, 2009 and 2008.




Year
      ended December 31,2009
              
              
              2008(in
      thousands)Audit
      fees (1)
              
              $
              130
              
              
              $
              130Audit-related
      fees (2)
              
              
              3
              
              
              
              -$
              133
              
              
              $
              130




(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
      for consultations regarding the Fund’s disclosure controls and procedures
      in accordance with Section 906 of the Sarbanes-Oxley Act of
      2002.








22
 Table of Contents




PART
IV




ITEM
      15.
            EXHIBITS, FINANCIAL STATEMENT
  SCHEDULES




(a)
      (1)
            Financial
      Statements




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




(a)
      (2)
            Financial
      Statement Schedules




None.




(a)
(3)




EXHIBITNUMBER
              
              TITLE OF
      EXHIBIT
              
              METHOD OF
      FILING3.1
              
              Articles
      of Formation of Ridgewood Energy S Fund, LLC
              
              Incorporated
      by reference to the Fund'sfiled
      with the Secretary of State of the State of Delaware
              
              Form
      10 filed on April 24, 2007on
      December 19, 20053.2
              
              Limited
      Liability Company Agreement between Ridgewood Energy
              
              Incorporated
      by reference to the Fund'sCorporation
      and Investors of Ridgewood Energy S Fund, LLC
              
              Form
      10 filed on April 24, 2007dated
      February 1, 200631.1
              
              Certification
      of Robert E. Swanson, Chief Executive Officer of the Fund,
              
              Filed
      herewithpursuant
      to Securities Exchange Act Rule 13a-14(a)31.2
              
              Certification
      of Kathleen P. McSherry, Chief Financial Officer of the
    Fund,
              
              Filed
      herewithpursuant
      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 Fund and Kathleen P. McSherry, Chief
      Financial Officer of the Fund
              
              Filed
      herewith99
              
              Report
      of Ryder Scott Company, L.P.
              
              Filed
      herewith








23
 Table of Contents




INDEX
      TO FINANCIAL STATEMENTS
            PAGEReport of Independent Registered Public Accounting
      Firm
            F-2Balance Sheets as of December 31, 2009 and
    2008
            F-3Statements of Operations and Comprehensive (Loss) Income for
      the years ended December 31, 2009 and 2008
            F-4Statements of Changes in Members’ Capital for the years ended
      December 31, 2009 and 2008
            F-5Statements of Cash Flows for the years ended December 31, 2009
      and 2008
            F-6Notes to Financial Statements
            F-7Supplementary Financial Information - Information about Oil
      and Gas Producing Activities -Unaudited
            F-13








F-1
 Table of Contents




REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the
shareholders and Manager of Ridgewood Energy S Fund, LLC:





We have
audited the accompanying balance sheets of Ridgewood Energy S Fund, LLC (the
“Fund”) as of December 31, 2009 and 2008, and the related statements of
operations and comprehensive (loss) income, changes in members’ capital, and
cash flows for the years ended December 31, 2009 and 2008.  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 audits 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 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 S Fund, LLC as of December 31, 2009 and
2008, and the results of its operations and its cash flows for the years ended
December 31, 2009 and 2008, in conformity with accounting principles generally
accepted in the United States of America.





As
discussed in Note 3 to the financial statements, the Fund adopted the reserve
estimation and disclosure requirements of Extractive Activities – Oil and
Gas as of December 31, 2009.





/s/ Deloitte & Touche
LLP





Parsippany,
New Jersey


March 16,
2010








F-2
 Table of Contents




RIDGEWOOD
      ENERGY S FUND, LLCBALANCE
      SHEETS(in
      thousands, except share data)December
      31,2009
              
              
              2008ASSETSCurrent
      assets:Cash
      and cash equivalents
              
              $
              4,948
              
              
              $
              16,046Short-term
      investment in available-for-sale securities
              
              
              10,366
              
              
              
              -Production
      receivable
              
              
              308
              
              
              
              985Other
      current assets
              
              
              86
              
              
              
              335Total
      current assets
              
              
              15,708
              
              
              
              17,366Long-term
      investment in available-for-sale securities
              
              
              -
              
              
              
              10,743Salvage
      fund
              
              
              2,331
              
              
              
              1,113Oil
      and gas properties:Unproved
      properties
              
              
              4,284
              
              
              
              4,840Proved
      properties
              
              
              44,566
              
              
              
              45,173Less:  accumulated
      depletion and amortization
              
              
              (12,537
              )
              
              
              (10,242
              )Total
      oil and gas properties, net
              
              
              36,313
              
              
              
              39,771Total
      assets
              
              $
              54,352
              
              
              $
              68,993LIABILITIES
      AND MEMBERS' CAPITALCurrent
      liabilities:Due
      to operators
              
              $
              2,159
              
              
              $
              2,663Accrued
      expenses
              
              
              208
              
              
              
              81Total
      current liabilities
              
              
              2,367
              
              
              
              2,744Asset
      retirement obligations
              
              
              2,160
              
              
              
              1,391Total
      liabilities
              
              
              4,527
              
              
              
              4,135Commitments
      and contingencies (Note 8)Members'
      capital:Manager:Distributions
              
              
              (3,791
              )
              
              
              (2,461
              )Retained
      earnings
              
              
              2,042
              
              
              
              1,459Manager's
      total
              
              
              (1,749
              )
              
              
              (1,002
              )Shareholders:Capital
      contributions (1,000 shares authorized;839.5395
      issued and outstanding)
              
              
              124,401
              
              
              
              124,401Syndication
      costs
              
              
              (14,236
              )
              
              
              (14,236
              )Distributions
              
              
              (21,484
              )
              
              
              (13,947
              )Accumulated
      deficit
              
              
              (37,348
              )
              
              
              (30,845
              )Shareholders'
      total
              
              
              51,333
              
              
              
              65,373Accumulated
      other comprehensive income
              
              
              241
              
              
              
              487Total
      members' capital
              
              
              49,825
              
              
              
              64,858Total
      liabilities and members' capital
              
              $
              54,352
              
              
              $
              68,993


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




F-3
 Table of Contents





RIDGEWOOD
      ENERGY S FUND, LLCSTATEMENTS
      OF OPERATIONS ANDCOMPREHENSIVE (LOSS)
    INCOME(in
      thousands, except per share data)Year
      ended December 31,2009
              
              
              2008RevenueOil
      and gas revenue
              
              $
              8,962
              
              
              $
              19,032ExpensesDepletion
      and amortization
              
              
              7,898
              
              
              
              4,937Impairment
      of proved properties
              
              
              2,785
              
              
              
              3,407Dry-hole
      costs
              
              
              (30
              )
              
              
              3,193Management
      fees to affiliate (Note 6)
              
              
              2,284
              
              
              
              2,356Operating
      expenses
              
              
              1,450
              
              
              
              659Workover
      expenses
              
              
              397
              
              
              
              5General
      and administrative expenses
              
              
              455
              
              
              
              553Total
      expenses
              
              
              15,239
              
              
              
              15,110(Loss)
      income from operations
              
              
              (6,277
              )
              
              
              3,922Other
      incomeInterest
      income
              
              
              357
              
              
              
              926Realized
      gain on sale of marketable securities
              
              
              -
              
              
              
              325Total
      other income
              
              
              357
              
              
              
              1,251Net
      (loss) income
              
              
              (5,920
              )
              
              
              5,173Other
      comprehensive (loss) incomeUnrealized
      (loss) gain on
                marketable
      securities
              
              
              (246
              )
              
              
              487Total
      comprehensive (loss) income
              
              $
              (6,166
              )
              
              $
              5,660Manager
      InterestNet
      income
              
              $
              583
              
              
              $
              2,232Shareholder
      InterestNet
      (loss) income
              
              $
              (6,503
              )
              
              $
              2,941Net
      (loss) income per share
              
              $
              (7,746
              )
              
              $
              3,503




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




F-4
 Table of Contents




RIDGEWOOD
      ENERGY S FUND, LLCSTATEMENTS
      OF CHANGES INMEMBERS' CAPITAL(in
      thousands, except share data)OtherComprehensive#
      of Shares
              
              
              Manager
              
              
              Shareholders
              
              
              Income
      (Loss)
              
              
              TotalBalances,
      December 31, 2007
              
              
              839.5395
              
              
              $
              (893
              )
              
              $
              75,700
              
              
              $
              -
              
              
              $
              74,807Distributions
              
              
              -
              
              
              
              (2,341
              )
              
              
              (13,268
              )
              
              
              -
              
              
              
              (15,609
              )Net
      income
              
              
              -
              
              
              
              2,232
              
              
              
              2,941
              
              
              
              -
              
              
              
              5,173Other
      comprehensive income
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              487
              
              
              
              487Balances,
      December 31, 2008
              
              
              839.5395
              
              
              
              (1,002
              )
              
              
              65,373
              
              
              
              487
              
              
              
              64,858Distributions
              
              
              -
              
              
              
              (1,330
              )
              
              
              (7,537
              )
              
              
              -
              
              
              
              (8,867
              )Net
      income (loss)
              
              
              -
              
              
              
              583
              
              
              
              (6,503
              )
              
              
              -
              
              
              
              (5,920
              )Other
      comprehensive loss
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (246
              )
              
              
              (246
              )Balances,
      December 31, 2009
              
              
              839.5395
              
              
              $
              (1,749
              )
              
              $
              51,333
              
              
              $
              241
              
              
              $
              49,825


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




F-5
 Table of Contents





RIDGEWOOD
      ENERGY S FUND, LLCSTATEMENTS
      OFCASH FLOWS(in
      thousands)Year
      ended December 31,2009
              
              
              2008Cash
      flows from operating activitiesNet
      (loss) income
              
              $
              (5,920
              )
              
              $
              5,173Adjustments
      to reconcile net (loss) income to net cashprovided
      by operating activities:Depletion
      and amortization
              
              
              7,898
              
              
              
              4,937Impairment
      of proved properties
              
              
              2,785
              
              
              
              3,407Dry-hole
      costs
              
              
              (30
              )
              
              
              3,193Accretion
      expense
              
              
              36
              
              
              
              12Realized
      gain on marketable securities
              
              
              -
              
              
              
              (325
              )Interest
      earned on marketable securities
              
              
              -
              
              
              
              (500
              )Amortization
      of premium on investment
              
              
              131
              
              
              
              146Changes
      in assets and liabilities:Decrease
      (increase) in production receivable
              
              
              677
              
              
              
              (92
              )Decrease
      (increase) in other current assets
              
              
              177
              
              
              
              (50
              )Increase
      in due to operator
              
              
              75
              
              
              
              62Decrease
      in accrued expenses
              
              
              (32
              )
              
              
              (110
              )Net
      cash provided by operating activities
              
              
              5,797
              
              
              
              15,853Cash
      flows from investing activitiesCapital
      expenditures for oil and gas properties
              
              
              (7,221
              )
              
              
              (18,848
              )Investments
      in salvage fund
              
              
              (1,218
              )
              
              
              (32
              )Proceeds
      from insurance recovery
              
              
              411
              
              
              
              -Proceeds
      from maturity of held-to-maturity securities
              
              
              -
              
              
              
              27,386Proceeds
      from sale of available-for-sale securities
              
              
              -
              
              
              
              10,001Investment
      in held-to-maturity securities
              
              
              -
              
              
              
              (10,001
              )Net
      cash (used in) provided by investing activities
              
              
              (8,028
              )
              
              
              8,506Cash
      flows from financing activitiesDistributions
              
              
              (8,867
              )
              
              
              (15,609
              )Net
      cash used in financing activities
              
              
              (8,867
              )
              
              
              (15,609
              )Net
      (decrease) increase in cash and cash equivalents
              
              
              (11,098
              )
              
              
              8,750Cash
      and cash equivalents, beginning of year
              
              
              16,046
              
              
              
              7,296Cash
      and cash equivalents, end of year
              
              $
              4,948
              
              
              $
              16,046






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




F-6
 Table of Contents




RIDGEWOOD
ENERGY S FUND, LLC


NOTES
TOFINANCIAL STATEMENTS




1.  Organization
and Purpose




The
Ridgewood Energy S Fund, LLC (the “Fund”), a Delaware limited liability company,
was formed on December 19, 2005 and operates pursuant to a limited liability
company agreement (the “LLC Agreement”) dated as of February 1, 2006 by and
among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the
Fund. The Fund was organized to acquire interests in oil and gas properties
located in the United States offshore waters of Texas, Louisiana, and Alabama in
the Gulf of Mexico.




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




2.  Summary
of Significant Accounting Policies




Use
of Estimates


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




Cash
and Cash Equivalents


All
highly liquid investments with maturities, when purchased, of three months or
less, are considered cash and cash equivalents.  At times, bank
deposits may be in excess of federally insured limits.  Effective
January 1, 2010, the federally insured limits of the Fund’s deposits are $250
thousand per insured financial institution.  Based upon these limits,
at December 31, 2009, the Fund’s bank balances would have exceeded federally
insured limits by $4.5 million, of which $2.7 million was invested in money
market accounts that invest solely in U.S. Treasury bills and
notes.





Investments
in Marketable Securities


At times the Fund may invest in U.S. Treasury bills and
notes. These investments are considered short-term when their maturities are
greater than three months and one year or less, and long-term when their
maturities are greater than one year.





At
December 31, 2009, the Fund has investments in U.S. Treasury securities, which
mature in December 2010, that are classified as
available-for-sale.  Available-for-sale securities are carried in the
financial statements at fair value.  In March 2008, the Fund sold a
portion of its available-for-sale investments in U.S. Treasury
notes.  Gross proceeds from the sale totaled $10.0 million, which
included interest income of $0.1 million and a gross realized gain on investment
of $0.3 million.  The following table is
a summary available-for-sale investments at December 31, 2009 and
2008:




GrossAmortized
              
              
              Unrealized
              
              
              FairCost
              
              
              Gains
              
              
              ValueAvailable-for-Sale
              
              (in
      thousands)U.S.
      Treasury notesDecember
      31, 2009
              
              $
              10,125
              
              
              $
              241
              
              
              $
              10,366December
      31, 2008
              
              $
              10,256
              
              
              $
              487
              
              
              $
              10,743




F-7
 Table of Contents





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




Salvage
Fund


The Fund
deposits in a separate interest-bearing account, or salvage fund, money to
provide for the dismantling and removal of production platforms and facilities
and plugging and abandoning its wells at the end of their useful lives, in
accordance with applicable federal and state laws and regulations.  At
December 31, 2009, the Fund had investments in U.S. Treasury securities within
its salvage fund that are classified as held-to-maturity of $1.2 million and
$1.1 million, which mature in November 2010 and December 2012, respectively.
Held-to-maturity investments are those securities that the Fund has the ability
and intent to hold until maturity, and are recorded at cost plus accrued income,
adjusted for the amortization of premiums and discounts, which approximates fair
value.




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




Oil
and Gas Properties


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




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




Upon the
sale or retirement of a proved property, the cost and related accumulated
depletion and amortization will be eliminated from the property accounts, and
the resultant gain or loss is recognized. Upon the sale or retirement of an
unproved property, gain or loss on the sale is recognized.




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




As of
December 31, 2009 and 2008, amounts recorded in due to operators totaling $2.0
million and $2.5 million respectively, related to capital expenditures for oil
and gas properties.




Advances
to Operators for Working Interests and Expenditures


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




Asset
Retirement Obligations


For oil
and gas properties, there are obligations to perform removal and remediation
activities when the properties are retired. When a project reaches drilling
depth and is determined to be either proved or dry, an asset retirement
obligation is incurred. Plug and abandonment costs associated with unsuccessful
projects are expensed as dry-hole costs.  The following table presents
changes in asset retirement obligations for the years ended December 31, 2009
and 2008.




F-8
 Table of Contents




December
      31,2009
              
              
              2008(in
      thousands)Balance,
      beginning of year
              
              $
              1,391
              
              
              $
              131Liabilities
      incurred
              
              
              733
              
              
              
              1,183Liabilities
      settled
              
              
              -
              
              
              
              -Accretion
      expense
              
              
              36
              
              
              
              12Revisions
      to previous estimates
              
              
              -
              
              
              
              65Balance,
      end of year
              
              $
              2,160
              
              
              $
              1,391





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





Syndication
Costs


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




Revenue
Recognition and Imbalances


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




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




Derivative
Instruments


The Fund
may periodically utilize derivative instruments in its marketing and trading
activities and to manage price risk attributable to the Fund’s forecasted sales
of oil and natural gas production.  Derivatives are carried
on the balance sheet at fair value and recorded as either an asset or
liability.  Changes in fair value of derivatives are recorded currently in
earnings unless special hedge accounting criteria are met.  The Fund has
exposure to credit risk to the extent the derivative-instrument counterparty is
unable to satisfy its settlement commitment. The Fund actively monitors the
creditworthiness of each counterparty and assesses the impact, if any, on its
derivative positions.  There was no derivative activity in 2009 and
2008.





Impairment
of Long-Lived Assets


The Fund
reviews the value of its oil and gas properties whenever management determines
that events and circumstances indicate that the recorded carrying value of
properties may not be recoverable. Impairments of producing properties are
determined by comparing future net undiscounted cash flows to the net book value
at the time of the review.  If the net book value exceeds the future
net undiscounted cash flows, the carrying value of the property is written down
to fair value, which is determined using net discounted future cash flows from
the producing property. The Fund provides for impairments on unproved properties
when it determines that the property will not be developed or that a permanent
impairment in value has occurred.  The fair value determinations
require considerable judgment and are sensitive to change.  Different
pricing assumptions, reserve estimates or discount rates could result in a
different calculated impairment. Given the volatility of oil and natural gas
prices, it is reasonably possible that the Fund’s estimate of discounted future
net cash flows from proved oil and natural gas reserves could change in the near
term.  If oil and natural gas prices decline significantly, even if
only for a short period of time, it is possible that write-downs of oil and gas
properties could occur.





During the year ended December 31, 2009, the Fund
recorded impairments of proved properties totaling $2.8 million, relating to
Vermilion 344, which were attributable to lower oil and gas commodity prices, a
reduction in the Fund’s estimates of proved oil and gas reserves, and the
year-end determination that the well wasfully depleted.  During the year ended December 31, 2008, the Fund
recorded an impairment of proved properties of $3.4 million, relating to
Vermilion 344, which was attributable to increased project costs, lower oil and
gas commodity prices and a reduction in the Funds estimates of proved oil and
gas reserves.The fair value of the impaired well was determined based on
level 3 inputs, which include projected income from proved and probable reserves
utilizing forward price curves, net of anticipated costs,
discounted.




F-9
 Table of Contents




Depletion
and Amortization


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





Income
Taxes


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





Income
and Expense Allocation




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




3.  Recent
Accounting Standards




In
January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance
on improving disclosures about fair value measurements.  This guidance has
new requirements for disclosures related to recurring or nonrecurring fair-value
measurements including significant transfers into and out of Level 1 and Level 2
fair-value measurements and information on purchases, sales, issuances, and
settlements in a rollforward reconciliation of Level 3 fair-value measurements.
This guidance is effective for the first reporting period beginning after
December 15, 2009, which will be effective for the Fund beginning January 1,
2010.  The Level 3 reconciliation disclosures are effective for fiscal
years beginning after December 15, 2010, which will be effective for the Fund
December 31, 2011. The adoption of the guidance is not expected to have a
material impact on Fund’s financial statements.





In
June 2009, the FASB issued Accounting Standards Codification as the source
of GAAP to be applied to nongovernmental agencies. This guidance explicitly
recognizes rules and interpretive releases of the SEC under authority of federal
securities laws as authoritative GAAP for SEC registrants. It was effective for
interim or annual periods ending after September 15, 2009.  The guidance
was adopted for the third quarter 2009 and did not have a material impact on the
Fund’s financial statements.





In
May 2009, the FASB issued guidance on subsequent events, which sets forth
general standards of accounting for and disclosure of events that occur after
the balance sheet date but before financial statements are issued or are
available to be issued. The guidance was adopted effective for the second
quarter 2009 and did not have a material impact on the Fund’s financial
statements.





In
April 2009, the FASB issued guidance on interim disclosures about fair
value of financial instruments, which requires quarterly disclosure of
information about the fair value of financial instruments.  The guidance
was adopted effective for the second quarter 2009 and did not have a material
impact on the Fund’s financial statements.





In April
2009, the FASB issued guidance on the recognition and presentation of
other-than-temporary impairments, which amends the other-than-temporary
impairment guidance for debt securities to make the guidance more operational
and to improve the presentation and disclosure of other-than-temporary
impairments on debt and equity securities in the financial statements. This
guidance does not amend existing recognition and measurement guidance related to
other-than-temporary impairments of equity securities. This guidance does not
require disclosures for earlier periods presented for comparative purposes at
initial adoption. In periods after initial adoption, this guidance requires
comparative disclosures only for periods ending after initial adoption. The
guidance was adopted effective for the second quarter 2009 and did not have a
material impact on the Fund’s financial statements.





In
September 2006, the FASB issued guidance related to fair value measurements.
This guidance 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 FASB also issued guidance on the methods used
to measure fair value and required expanded disclosures related to fair value
measurements. The Fund adopted this guidance for financial assets and financial
liabilities effective January 1, 2008 and for non-financial assets and
non-financial liabilities effective January 1, 2009.  The adoption did not
have a material impact on the Fund’s financial statements.




F-10
 Table of Contents




In
December 2008, the SEC issued Release No. 33-8995, “Modernization of
Oil and Gas Reporting” (“Release No. 33-8995”), amending oil and gas reporting
requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in
Regulation S-K.  The new requirements provide for consideration of new
technologies in evaluating reserves, allow companies to disclose their probable
and possible reserves to investors, report oil and gas reserves using an average
price based on the prior 12-month period rather than year-end prices, and revise
the disclosure requirements for oil and gas operations.  The final rules
were effective for fiscal years ending on or after
December 31, 2009.  In January 2010, the FASB issued guidance on
oil and gas reserve estimation and disclosures to align the Accounting Standards
Codification with the disclosure requirements of Release
No. 33-8995.  The FASB and SEC guidance has been adopted for the
year ended December 31, 2009.  In the unaudited supplementary financial
information, the 2009 future estimated cash inflows are determined on average
price based on the prior 12-month period whereby 2008 future estimated cash
inflows are determined based on year-end prices.




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.  At December 31, 2009, the
Fund had no unproved properties with capitalized exploratory well costs in
excess of one year.  The following table reflects the net changes in
unproved properties for the years ended December 31, 2009 and 2008.




December
      31,2009
              
              
              2008(in
      thousands)Balance,
      beginning of year
              
              $
              4,840
              
              
              $
              11,215Additions
      to capitalized exploratory well costspending
      the determination of proved reserves
              
              
              5,686
              
              
              
              7,380Reclassifications
      to proved properties based onthe
      determination of proved reserves
              
              
              (6,242
              )
              
              
              (13,755
              )Capitalized
      exploratory well costs charged todry-hole
      costs
              
              
              -
              
              
              
              -Balance,
      end of year
              
              $
              4,284
              
              
              $
              4,840


Capitalized
exploratory well costs are expensed as dry-hole costs in the event that reserves
are not found or are not in sufficient quantities to complete the well and
develop the field.  At times, the Fund receives credits on certain
wells from their respective operators upon review and audit of the wells’
costs.  Dry-hole costs, inclusive of such credits, for the years ended
December 31, 2009 and 2008 are detailed in the following table.





Year
      ended December 31,Lease
      Block
              
              2009
              
              
              2008(in
      thousands)Ruby
      Project
              
              $
              (184
              )
              
              $
              3,464Other
      wells
              
              
              154
              
              
              
              (271
              )$
              (30
              )
              
              $
              3,193




5.  Distributions




Distributions
to shareholders are allocated in proportion to the number of shares held.
Certain shares have early investment incentive and advance distribution rights,
as defined in the LLC Agreement, which range from approximately $8 thousand to
$12 thousand per share.  The Fund began making distributions to
eligible early investors in September 2007 and to all investors in May
2008.




The
Manager determines whether available cash from operations, as defined in the LLC
Agreement, will be distributed. Such distributions are allocated 85% to the
shareholders and 15% to the Manager, as required by the LLC
Agreement.




F-11
 Table of Contents




Available
cash from dispositions, as defined in the 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.




6.  Related
Parties




The LLC
Agreement provides that the Manager render management, administrative and
advisory services. For such services, the Manager is paid an annual management
fee, payable monthly, of 2.5% of total capital contributions, net of cumulative
dry-hole and related well costs incurred by the Fund.  Management fees
were $2.3 million and $2.4 million for the years ended December 31, 2009 and
2008, respectively.




At times,
short-term payables and receivables, which do not bear interest, arise from
transactions with affiliates in the ordinary course of business.





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





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





7.  Fair
Value of Financial Instruments




At
December 31, 2009 and 2008, cash and cash equivalents, production receivable,
salvage fund and accrued expenses approximate fair value. At December 31, 2009
and 2008, available-for-sale investments are recorded at fair value based on
Level 1 inputs – quoted prices in active markets.




8.  Commitments
and Contingencies




Capital
Commitments


The Fund
has entered into multiple agreements for the drilling and development of its
investment properties.  The estimated capital expenditures associated
with these agreements vary depending on the stage of development on a
property-by-property basis.  As of December 31, 2009, the Fund had
committed to spend an additional $18.6 million related to its investment
properties, of which $9.2 million is expected to be incurred during the next
twelve months.





Environmental
Considerations


The
exploration for and development of oil and natural gas involves the extraction,
production and transportation of materials which, under certain conditions, can
be hazardous or cause environmental pollution problems.  The Manager
and operators of the Fund’s properties are continually taking action they
believe appropriate to satisfy applicable federal, state and local environmental
regulations and do not currently anticipate that compliance with federal, state
and local environmental regulations will have a material adverse effect upon
capital expenditures, results of operations or the competitive position of the
Fund in the oil and 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, 2009 and 2008, there were no known environmental contingencies 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 that is not insured or not fully insured could have an adverse impact
upon earnings and financial position.  Moreover, insurance is obtained
as a package covering all of the funds managed by the Manager.  Claims
made by other funds managed by the Manager can reduce or eliminate insurance for
the Fund.  During the year ended December 31, 2009, the Fund received
$0.4 million in connection with an insurance claim related to the Aspen Project
relative to an insurable event that had occurred during the drilling of the
well.





9.   Subsequent
Events





The Fund
has assessed the impact of subsequent events through the date of the
issuance of its financial statements, and has concluded that there
were no such events that require adjustment to, or disclosure in, the notes to
the financial statements.




F-12
 Table of Contents




Ridgewood
Energy S Fund, LLC


Supplementary
Financial Information


Information
about Oil and Gas Producing Activities -Unaudited




In
accordance with the Financial Accounting Standards Board guidance on disclosures
of oil and gas producing activities, this section provides supplementary
information on oil and gas exploration and producing activities of the Fund. The
Fund is engaged solely in oil and gas activities, all of which are currently
located in the United States offshore waters of Louisiana in the Gulf of
Mexico.




Table
      I - Capitalized Costs Relating to Oil and Gas Producing
      ActivitiesDecember
      31,2009
                
                
                2008(in
      thousands)Unproved
      properties
                
                $
                4,284
                
                
                $
                4,840Proved
      properties
                
                
                44,566
                
                
                
                45,173Total
      oil and gas properties
                
                
                48,850
                
                
                
                50,013Accumulated
      depletion and amortization
                
                
                (12,537
                )
                
                
                (10,242
                )Oil
      and gas properties, net
                
                $
                36,313
                
                
                $
                39,771
  Table
      II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and
      DevelopmentYear
      ended December 31,2009
                
                
                2008(in
      thousands)Exploration
      costs
                
                $
                6,874
                
                
                $
                9,519Development
      costs
                
                
                312
                
                
                
                5,789$
                7,186
                
                
                $
                15,308








F-13
 Table of Contents




Table
      III - Reserve Quantity InformationOil
      and gas reserves of the Fund have been estimated by an independent
      petroleum engineer, Ryder Scott Company, L.P. at December 31, 2009 and
      2008.  These reserve disclosures have been prepared in
      compliance with the Securities and Exchange Commission rules and represent
      all reserves managed by Ridgewood Energy Corporation, the Manager of the
      Fund.   The reserve data disclosed in the following tables
      represent the Fund's share of such reserves based on the Fund's net
      revenue interest in each property.  Due to inherent
      uncertainties and the limited nature of recovery data, estimates of
      reserve information are subject to change as additional information
      becomes available.  The reserve quantities for gas are inclusive
      of plant product reserve estimates on a dollar cost equivalent
      basis.    December
      31, 2009
                
                
                December
      31, 2008United
      StatesOil
      (BBLS)
                
                
                Gas
      (MCF)
                
                
                Oil
      (BBLS)
                
                
                Gas
      (MCF)Proved
      developed and undeveloped reserves:Beginning
      of year
                
                
                169,954
                
                
                
                12,304,977
                
                
                
                42,866
                
                
                
                14,988,700Extensions
      and discoveries
                
                
                9,042
                
                
                
                2,152,287
                
                
                
                140,244
                
                
                
                1,332,561Purchases
      of minerals in place
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Revisions
      of previous estimates (a)
                
                
                (5,994
                )
                
                
                (1,337,603
                )
                
                
                12,017
                
                
                
                (2,299,630
                )Production
                
                
                (19,528
                )
                
                
                (2,108,746
                )
                
                
                (25,173
                )
                
                
                (1,716,654
                )End
      of year
                
                
                153,474
                
                
                
                11,010,915
                
                
                
                169,954
                
                
                
                12,304,977Proved
      developed reserves:Beginning
      of year
                
                
                169,954
                
                
                
                12,304,977
                
                
                
                42,866
                
                
                
                14,988,700End
      of year
                
                
                146,362
                
                
                
                5,868,040
                
                
                
                169,954
                
                
                
                12,304,977Proved
      undeveloped reserves:Beginning
      of year
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -End
      of year
                
                
                7,112
                
                
                
                5,142,875
                
                
                
                -
                
                
                
                -
   (a) Revisions
of previous estimates are primarily attributable to the depletion of one of the
Fund's wells during the year
ended December 31, 2009 coupled with revisions due to well
performance.


F-14
 Table of Contents




Table
      IV - Standardized Measure of Discounted Future Net Cash Flows Relating to
      Proved Oil and Gas ReservesSummarized
      in the following table is information for the Fund with respect to the
      standardized measure of discounted future net cash flows relating to
      proved oil and gas reserves.  At December 31, 2009, future cash
      inflows were determined based on average prices for the prior twelve month
      period.  At December 31, 2008, future cash inflows were
      determined based on year-end prices.  Future production and
      development costs are derived based on current costs assuming continuation
      of existing economic conditions.  December
      31,2009
              
              
              2008(in
      thousands)Future
      estimated revenues
              
              $
              52,035
              
              
              $
              78,334Future
      estimated production costs
              
              
              (5,840
              )
              
              
              (4,606
              )Future
      estimated development costs
              
              
              (6,248
              )
              
              
              (2,325
              )Future
      net cash flows
              
              
              39,947
              
              
              
              71,40310%
      annual discount for estimated timing of cash flows
              
              
              (10,446
              )
              
              
              (17,889
              )Standardized
      measure of discounted future estimated net cash flows
              
              $
              29,501
              
              
              $
              53,514








Table
      V - Changes in the Standardized Measure for Discounted Cash
      FlowsThe
      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 31,2009
                
                
                2008(in
      thousands)Sales
      and transfers of oil and gas produced during the period
                
                $
                (7,698
                )
                
                $
                (18,422
                )Net
      change in sales and transfer prices and in production
                  costs
      related to future production
                
                
                (15,553
                )
                
                
                (411
                )Net
      change due to extensions, discoveries, and improved
    recovery
                
                
                4,623
                
                
                
                10,126Changes
      in estimated future development costs
                
                
                (1,650
                )
                
                
                -Net
      change due to revisions in quantity estimates
                
                
                (5,723
                )
                
                
                (8,795
                )Accretion
      of discount
                
                
                5,351
                
                
                
                6,346Other
                
                
                (3,363
                )
                
                
                1,208Aggregate
      change in the standardized measure of discounted
                  future
      net cash flows for the year
                
                $
                (24,013
                )
                
                $
                (9,948
                )





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 number of
estimates.  Reserve quantities cannot be measured with precision and
their estimation requires many judgmental determinations and frequent
revisions.  The required projection of production and related
expenditures over time requires further estimates with respect to pipeline
availability, rates and governmental control.  Actual future prices
and costs are likely to be substantially different from the current price and
cost estimates utilized in the computation of reported amounts.  Any
analysis or evaluation of the reported amounts should give specific recognition
to the computational methods utilized and the limitation inherent
therein.




F-15
 Table of Contents




SIGNATURES




Pursuant
to the requirements of Section 13 or 15(d) 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 S FUND, LLCDate:
      March 16, 2010
            By:
            /s/
      ROBERT E. SWANSONRobert
      E. SwansonChief
      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
            Date:
      March 16, 2010Robert
      E. Swanson
            
            (Principal
      Executive Officer)/s/
      KATHLEEN P. MCSHERRY
            
            Executive
      Vice President and Chief Financial
            Date:
      March 16, 2010Kathleen
      P. McSherry
            
            Officer
      (Principal Accounting Officer)RIDGEWOOD
      ENERGY CORPORATION/s/
      ROBERT E. SWANSON
            
            Chief
      Executive Officer of Manager
            Date:
      March 16, 2010Robert
      E. Swanson