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. 000-51268





RIDGEWOOD
ENERGY M FUND, LLC


(Exact
name of registrant as specified in its charter)





Delaware
              (State
      or other jurisdiction of
              incorporation
      or organization)
            
            13-4285167
              (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
the 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 535.6818 shares of LLC Membership Interest
outstanding.












RIDGEWOOD
ENERGY M FUND, LLC


2009
ANNUAL REPORT ON FORM 10-K


TABLE
OFCONTENTS




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








Table of Contents




FORWARD-LOOKING
STATEMENTS




Certain
statements in this Annual Report on Form 10-K (“Annual Report”) and the
documents Ridgewood Energy M 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 August 2, 2004 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 September 7, 2004, 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 November 30, 2004. The Fund raised
$78.9 million, and after payment of $12.2 million in offering fees, commissions
and investment fees, the Fund had $66.7 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.




In
accordance with the LLC Agreement, the Manager is entitled to an annual
management fee, equal to 2.5% of the total shareholder
capital.  During 2007, the Manager waived its management fee for the
remaining life of the Fund.





The
Manager is entitled to 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 $0.1 million and $37 thousand, respectively. Effective
July 1, 2009, the Manager elected to permanently waive its right to
distributions from the Fund.




Business
Strategy




The
Fund’s primary investment objective has been to generate cash flow for
distribution to its shareholders through the acquisition of working interests in
the exploration, production and sale of oil and natural gas. Distributions are
funded from cash flow from operations, and the frequency and amount are within
the Manager’s discretion, subject to available cash from operations, reserve
requirements and Fund operations.  A working interest is a percentage
of ownership in an oil and natural gas lease granting its owner the right to
explore, drill and produce oil and natural gas from projects on that lease
block.  The Fund has focused on projects that have significant reserve
potential and are projected to have the shortest time period from investment to
first production.  The Fund does not operate these projects, and
although it has a vote, it is not in control of the schedule pursuant to which
its projects are developed and completed.  Working interest owners are
obligated to pay a corresponding percentage of the cost of leasing, drilling,
producing and operating a well.  After royalties are paid, the working
interest also entitles its owner to share in production revenues with other
working interest owners, based on the percentage of working interest
owned.




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




2
 Table of Contents




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




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




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




Manager’s
Investment Committee




The
Manager maintains an investment committee, consisting of five members, which
provides operational, 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 were complete and a project was
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 was made by the Investment
Committee.  When reviewing a project for final investment approval,
the Investment Committee sought 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 considered the
geological, financial and operating risks of the proposed project and compared
these risks to the existing portfolio of Ridgewood Energy
projects.  The Investment Committee further focused on the initial
well cost relative to the overall revenue potential of the project.




Post-Investment
Activities


The Fund
has reached the end of its investment cycle.  All of the wells in
which a Fund owns a working interest are currently producing, have been
determined to be dry holes or have been fully depleted.  The
Investment Committee continually evaluates the production rates of the Fund’s
producing wells and takes steps to ensure that optimal prices are obtained for
the oil and natural gas produced by the Fund’s wells.




Properties




The Fund
owns working interests and has participated in the drilling of fifteen
wells.  Four wells are currently producing and eleven wells have been
determined to be dry holes or have been fully depleted.




3
 Table of Contents




Off-shoreLocation
      in
                
                
                
                
                Total
      SpentWorking
                
                Gulf
      of
                
                Well
                
                
                throughLease
      Block
                
                Interest
                
                Mexico
                
                Depth
                
                
                12/31/2009Discoveries
                
                
                
                
                
                
                (feet)
                
                
                (in
      thousands)Whistler
      Project
                
                
                20.0
                %
                
                Louisiana
                
                
                4,400
                
                
                $
                4,022South
      Marsh Island 111
                
                
                8.75
                %
                
                Louisiana
                
                
                11,600
                
                
                $
                2,428West
      Delta 68
                
                
                8.75
                %
                
                Louisiana
                
                
                14,000
                
                
                $
                1,788West
      Delta 67
                
                
                8.75
                %
                
                Louisiana
                
                
                14,000
                
                
                $
                1,150Dry
      Holes (a)2008South
      Marsh Island 213
                
                
                5.5
                %
                
                Louisiana
                
                
                N/A
                
                
                $
                1,645Fully
      Depleted2009Eugene
      Island 337
                
                
                20.0
                %
                
                Louisiana
                
                
                N/A
                
                
                $
                6,019Vermilion
      344
                
                
                8.75
                %
                
                Louisiana
                
                
                N/A
                
                
                $
                2,854West
      Cameron 57
                
                
                12.5
                %
                
                Louisiana
                
                
                N/A
                
                
                $
                4,7682008West
      Cameron 77
                
                
                14.5
                %
                
                Louisiana
                
                
                N/A
                
                
                $
                8,784
  (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.






Whistler
Project


In July
2008, the Fund acquired a 20.0% working interest in the Whistler Project, an
exploratory well.  The Whistler Project was determined to be a
discovery in November 2008 and production commenced in January
2010.  Through December 31, 2009, the Fund has spent $4.0 million
relating to this well, for which the Fund’s total estimated budget is $4.8
million.  During the year ended December 31 2009, the Fund recorded an
impairment of $2.1 million related to the Whistler Project.





LLOG
Projects


In 2006,
the Fund acquired an 8.75% working interest in six exploratory wells which are
operated by LLOG Exploration Offshore, Inc. (“LLOG”), 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
spent $8.2 million related to the four exploratory wells, which were determined
to be discoveries during 2007.  At December 31, 2009, the Fund has
additional budgets for these wells of $0.6 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 $1.1 million and $1.3 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





Eugene
Island 337


In 2005,
the Fund acquired a 20.0% working interest in Eugene Island 337, an exploratory
well.  The well was determined to be a discovery in July 2006 and
production commenced in November 2007.  During the third quarter 2008,
the pipeline utilized to transport oil and natural gas production for Eugene
Island 337 suffered damage as a result of hurricane activity, shutting down
production until June 2009.  At December 31, 2009, Eugene Island 337
was determined to be fully depleted.  The Fund has spent $6.0 million
relating to this well and recorded impairments totaling $5.7 million, of which
$0.2 million was recorded during the year ended December 31, 2009.




4
 Table of Contents




West
Cameron 57


In 2007,
the Fund acquired a 12.5% working interest in West Cameron 57, an exploratory
well. The well was determined to be a discovery in February 2008 and production
commenced in December 2008.  The Fund has spent $4.8 million relating
to this well.  During the year ended December 31, 2009, the Fund
recorded an impairment totaling $4.3 million related to West Cameron 57 as the
well was determined to be fully depleted.




Working
Interest in Oil and Gas Leases




Existing
projects, and future projects, if any, are expected to be located in the waters
of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The
OCSLA 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 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.




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.




5
 Table of Contents




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 producing properties are
operated by Helis Oil and Gas Company, L.L.C. and LLOG.




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




Insurance




The
Manager has obtained 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.




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 $1.9 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.




6
 Table of Contents




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. During third quarter 2008, two hurricanes struck in the
Gulf of Mexico, which significantly impacted the Fund’s operations. These two
storms, Hurricanes Gustav and Ike, came ashore in Louisiana and Texas,
respectively, and caused production curtailments due to damage to third-party
pipelines and disrupted the operations of crews that could assess and repair the
damage. While the Fund’s platforms avoided major damage, the Fund’s production
was curtailed from the time personnel were evacuated for safety purposes, until
assessment and repair to the Fund’s platforms were completed and until repairs
to third-party pipelines and facilities, for which the Fund was not responsible,
were completed.  As a result, West Delta 68 and West Delta 67 were
shut-in for approximately one month, with production resuming in October 2008
and Eugene Island 337 well was shut-in for approximately ten months, with
production resuming in June 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.




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. The Fund has not engaged in any price
risk management programs or hedges.




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.  As the Fund has reached the end of its investment cycle, it
no longer competes for the acquisition of percentage ownership interests in oil
and natural gas working interests.




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.




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 US 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.




7
 Table of Contents




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.




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.




8
 Table of Contents




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.               RISKFACTORS




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 heading “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.





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 934 barrels and 742 thousand
mcf of proved undeveloped oil and natural gas reserves, respectively,
attributable to South Marsh Island 111 and the Whistler Project. The proved
undeveloped reserves relating to the Whistler Project, consisting of 556
thousand mcf of natural gas, were fully developed and the Whistler Project
commenced production in January 2010.  The Fund is currently
evaluating the development alternatives for the proved undeveloped reserves
related to South Marsh Island 111.  At December 31, 2008, the Fund had
no proved undeveloped oil reserves and approximately 556 thousand mcf of proved
undeveloped natural gas reserves, which were attributable to the Whistler
Project.




9
 Table of Contents




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




On August
16, 2006, the Manager of the Fund filed a lawsuit against the former independent
registered public accounting firm for the Fund, Perelson Weiner, LLP,
(“Perelson”) in New Jersey Superior Court, captioned Ridgewood Energy
Corporation v. Perelson Weiner, LLP, Docket No. L-6092-06.  The suit
alleged professional malpractice and breach of contract in connection with audit
and accounting services performed for the Fund by Perelson. Thereafter, Perelson
filed a counterclaim against the Manager on October 20, 2006, alleging breach of
contract due to unpaid invoices in the amount of $326,554. Discovery is ongoing
and a trial date is currently set for May 2010.




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




ITEM
4.             (REMOVEDAND RESERVED)




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
March 16, 2010, there were 954 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 $0.7 million and $0.2
million, respectively.  Effective July 1, 2009, the Manager waived its
right to cash distributions for the remaining life of the Fund.




ITEM
      6.
            SELECTED FINANCIAL DATA




Not
required.




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




Overview
of the Fund’s Business




The Fund
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 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 the 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.





10
 Table of Contents




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 and Development Costs


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




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




Unproved
Property


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





Proved
Reserves


Annually,
the Fund engages an independent petroleum engineer, Ryder Scott, 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.




11
 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
              
              $
              2,004
              
              
              $
              1,369ExpensesDepletion
      and amortization
              
              
              2,675
              
              
              
              732Dry-hole
      costs
              
              
              (99
              )
              
              
              1,700Impairment
      of proved properties, net
              
              
              7,688
              
              
              
              7,688Workover
      expenses
              
              
              25
              
              
              
              909Operating
      expenses
              
              
              427
              
              
              
              246General
      and administrative expenses
              
              
              300
              
              
              
              489Total
      expenses
              
              
              11,016
              
              
              
              11,764Loss
      from operations
              
              
              (9,012
              )
              
              
              (10,395
              )Other
      incomeInterest
      income
              
              
              29
              
              
              
              181Net
      loss
              
              $
              (8,983
              )
              
              $
              (10,214
              )




Overview.During
the year ended December 31, 2009, the Fund had six producing
wells.  Eugene Island 337 commenced production in 2007, West Delta 67
and West Delta 68 commenced production in July 2008, West Cameron 57 and
Vermilion 344 commenced production in December 2008, and South Marsh Island 111
commenced production in February 2009.  Eugene Island 337, Vermilion
344 and West Cameron 57 were determined to be fully depleted at December 31,
2009.  During the year ended December 31, 2008 the Fund had six
producing wells consisting of Eugene Island 337, West Delta 67, West Delta 68,
West Cameron 57, Vermilion 344 and West Cameron 77.  West Cameron 77
was determined to be fully depleted at December 31, 2008.  Oil and gas
sales were all located within the United States.





As
previously discussed in Item 1. “Business”, the pipeline utilized to transport
Eugene Island 337’s oil and gas production suffered damage as a result of
hurricane activity in the third quarter of 2008, thereby shutting down
production for Eugene Island 337, which resumed production in June
2009.





Oil and Gas
Revenue.Oil
and gas revenue for the year ended December 31, 2009 was $2.0 million, a $0.6
million increase from the year ended December 31, 2008.  The increase
is primarily attributable to an increase in sales volumes of $2.8 million,
partially offset by the impact of lower average prices of $2.3
million.





Oil sales
volumes were 6 thousand barrels during the year ended December 31, 2009 compared
to 4 thousand barrels during the year ended December 31, 2008.  The
Fund’s oil prices averaged $52 per barrel and $88 per barrel during the years
ended December 31, 2009 and 2008, respectively.





Gas sales
volumes were 418 thousand mcf during the year ended December 31, 2009, compared
to 111 thousand mcf during the year ended December 31, 2008.  The
Fund’s gas prices averaged $3.81 per mcf and $8.68 per mcf during the years
ended December 31, 2009 and 2008, respectively.




12
 Table of Contents




The
increase in oil and gas volumes for the year ended December 31, 2009 compared to
the year ended December 31, 2008 was primarily attributable to the timing of the
onset of production of the Fund’s wells, as discussed above in “Overview.” This
increase was partially offset by lower gas sales volumes for West Cameron 77,
which was fully depleted at December 31, 2008 and lower gas sales volumes for
Eugene Island 337, which suffered damage as a result of hurricane activity in
the third quarter of 2008, shutting down its production until June
2009.





Depletion and
Amortization.  Depletion and amortization for the year ended
December 31, 2009 was $2.7 million, a $1.9 million increase from the year ended
December 31, 2008.  The increase resulted from an increase in
production volumes totaling $1.7 million, coupled with an increase in average
depletion rates totaling $0.2 million.  The increase in depletion
rates was primarily the result of higher cost reserve additions, principally
attributable to Vermilion 344, South Marsh Island 111 and West Cameron 57,
partially offset by lower cost reserve additions, principally attributable to
West Delta 67 and West Delta 68 and decreased rates for Eugene Island 337
attributable to the impairment charges taken for that well.





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)South
      Marsh Island 213
              
              $
              (43
              )
              
              $
              1,688Other
      wells
              
              
              (56
              )
              
              
              12$
              (99
              )
              
              $
              1,700




Impairment of
Proved Properties, net.  During the years ended December 31,
2009 and 2008, the Fund recorded impairments to proved properties as detailed in
the following table.




Year
      ended December 31,2009
              
              
              2008(in
      thousands)West
      Cameron 57
              
              $
              4,275
              
              
              $
              -Whistler
      Project
              
              
              2,073
              
              
              
              -Vermilion
      344
              
              
              1,083
              
              
              
              1,325Eugene
      Island 337
              
              
              217
              
              
              
              570West
      Cameron 77
              
              
              86
              
              
              
              6,263Eugene
      Island 364
              
              
              (46
              )
              
              
              (470
              )$
              7,688
              
              
              $
              7,688


During
the year ended December 31, 2009, the impairments to Eugene Island 337 and West
Cameron 57 were primarily the result of the determination that such wells were
fully depleted.  The impairments to Vermilion 344 were attributable to
lower oil and gas commodity prices, revisions to reserve estimates, and the
year-end determination that the well was fully depleted.  The
impairment to the Whistler Project was the result of increased project costs and
lower oil and gas commodity prices.  The impairments related to West
Cameron 77 and Eugene Island 364 were the result of revisions to asset
retirement cost estimates.  During the year ended December 31, 2008,
the impairments to Vermilion 344 and Eugene Island 337 were the result of lower
oil and gas commodity prices and the impairment to West Cameron 77 was the
result of the determination that such well was fully
depleted.  Additionally, during the year ended December 31, 2008, the
Fund received a $0.5 million credit related to the previously impaired Eugene
Island 364 as a result of its operator’s review of the well’s cost.





Workover
Expenses. Workover expenses represent costs to restore or stimulate
production of existing reserves of a proved property.   Workover
expenses of $25 thousand during the year ended December 31, 2009 were primarily
attributable to West Delta 67.  Workover expenses of $0.9 million
during the year ended December 31, 2008 were attributable to recompletion
efforts for the upper reservoir zone of West Cameron 77, which ultimately proved
unsuccessful.





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




13
 Table of Contents


Year
      ended December 31,2009
              
              
              2008(in
      thousands)Lease
      operating expense
              
              $
              407
              
              
              $
              155Geological
      costs
              
              
              -
              
              
              
              75Accretion
      expense
              
              
              20
              
              
              
              16$
              427
              
              
              $
              246





Lease
operating expense for the years ended December 31, 2009 and 2008 related to the
Fund’s producing properties during each period as outlined above in
“Overview”.  For the year ended December 31, 2009, the average
production cost was $0.86 per mcfe compared to $1.12 per mcfe for the year ended
December 31, 2008. Geological costs for the year ended December 31, 2008 related
primarily to the Whistler project.  Accretion expense is related to
the asset retirement obligations established for the Fund’s proved
properties.





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





Year
      ended December 31,2009
              
              
              2008(in
      thousands)Accounting
      fees
              
              $
              139
              
              
              $
              175Management
      reimbursement
              
              
              80
              
              
              
              80Insurance
      expense
              
              
              80
              
              
              
              217Trust
      fees and other
              
              
              1
              
              
              
              17$
              300
              
              
              $
              489




Accounting
fees represent audit and tax preparation fees, quarterly review and filing fees
incurred by the Fund.  Management reimbursement relates to
reimbursement for various administrative costs incurred on the Fund’s
behalf.  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.
Trust fees represent bank fees associated with the management of the Fund’s cash
accounts.





Interest
Income.  Interest income is comprised of interest earned on
money market accounts and investments in U.S. Treasury securities within the
Fund’s salvage fund.  Interest income for the year ended December 31,
2009 was $29 thousand, a $0.2 million decrease from the year ended December 31,
2008.  The decrease was attributable to a reduction in the average
outstanding balances earning interest due to ongoing capital expenditures for
oil and gas properties, coupled with lower interest rates earned.





Capital
Resources and Liquidity





Operating Cash
Flows


Cash
flows provided by operating activities for the year ended December 31, 2009 were
$1.4 million, primarily related to revenue receipts of $2.1 million, partially
offset by operating and workover expenses totaling $0.5 million and general and
administrative expenses of $0.3 million.





Cash
flows used in operating activities for the year ended December 31, 2008 were
$0.2 million, primarily related to workover expenses of $0.9 million, general
and administrative expenses of $0.5 million, operating expenses of $0.2 million
and unfavorable working capital of $0.1 million, partially offset by revenue
received of $1.4 million and interest received of $0.2 million.





Investing
Cash Flows


Cash
flows used in investing activities for the year ended December 31, 2009 were
$3.0 million, related to capital expenditures for oil and gas properties of $2.1
million and salvage fund investments of $0.9 million.





Cash
flows used in investing activities for the year ended December 31, 2008 were
$4.0 million, related to capital expenditures for oil and gas properties of $9.1
million, partially offset by proceeds from the maturity of U.S. Treasury
securities of $5.1 million.





Financing
Cash Flows


Cash
flows used in financing activities for the year ended December 31, 2009 were
$0.7 million related to manager and shareholder distributions.




14
 Table of Contents




Cash
flows used in financing activities for the year ended December 31, 2008 were
$0.2 million related to manager and shareholder distributions.




Estimated
Capital Expenditures




The Fund
has entered into multiple agreements for the drilling and development of its
investment properties.  The estimated capital expenditures associated
with these agreements can vary depending on the stage of development on a
property-by-property basis.  As of December 31, 2009, the Fund had
committed to spend an additional $1.4 million related to its investment
properties.  The Fund does not expect to participate in any additional
investment properties.




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 is limited and each
unsuccessful project the Fund experienced reduced its ability to generate
revenue and exhausted its capital.




Liquidity
Needs




The
Fund’s primary short-term liquidity needs are to fund its operations and capital
expenditures for its investment properties.  Operations are funded
utilizing operating income, existing cash on-hand and income earned therefrom.
The Fund has reached the end of its investment cycle.  At December 31,
2009, the Fund has capital commitments of $1.4 million that exceed, by $1.0
million, its current available working capital of $0.4 million.  Based
upon its current reserve estimates, the Fund expects cash flow from operations
to be sufficient to cover these deficiencies, as well as ongoing
operations.  Reserve estimates are projections based on engineering
data that cannot be measured with precision, require substantial judgment, and
are subject to frequent revision.  In the event of a temporary
production stoppage, causing the Fund’s wells to not produce cash flow from
operations, the Fund may borrow from the Manager until such time that production
is resumed.  At such time the Manager determines that the Fund is no
longer capable of continuing to fund its operations, the Manager would elect to
dissolve the Fund.





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
subject to available cash from operations, reserve requirements and the Fund’s
operations.  Effective July 1, 2009, the Manager elected to
permanently waive its right to distributions from the Fund. During the third
quarter 2009, the Manager suspended Fund distributions to shareholders through
December 2009. The Manager continues to evaluate the Fund’s ability to make
distributions on a month-to-month basis. As of the date of this filing, the
Manager has not resumed distributions to shareholders.




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.




ITEM
      7A.
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK




Not
required.




15
 Table of Contents




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 all 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.
                OTHER
INFORMATION


None.




16
 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:




Ridgewood
      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 August 2,
2004, 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.




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.




17
 Table of Contents




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 535.6818 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, Chief Executive Officer (1)
            7.3333
            1.37%Executive
      officers as a group (1)
            7.3333
            1.37%





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




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




In
accordance with the LLC Agreement, the Manager is entitled to an annual
management fee, equal to 2.5% of the total shareholder
capital.  During 2007, the Manager waived its management fee for the
remaining life of the Fund.  Upon the waiver of the management fee,
the Fund began recording costs relating to services provided by the Manager for
accounting and investor relations.  Such costs totaled $80 thousand
for each of the years ended December 31, 2009 and 2008, which were included in
general and administrative expenses.




18
 Table of Contents




The
Manager is entitled to receive a 15% interest in the cash distributions made by
the Fund.  For the years ended December 31, 2009 and 2008, the Manager
was paid distributions totaling $0.1 million and $37 thousand,
respectively.  Effective July 1, 2009, the Manager elected to
permanently waive its distributions.





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)
              
              $
              105
              
              
              $
              105Audit-related
      fees(2)
              
              
              3
              
              
              
              -$
              108
              
              
              $
              105






(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.




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.




19
 Table of Contents




(a)
      (3)Exhibit
      Number
              
              Title of
      Exhibit
              
              Method of
      Filing3.1
              
              Articles
      of Formation of Ridgewood Energy M Fund, LLC dated August 2,
      2004
              
              Incorporated
      by reference to the Fund's Form 10 filed on April 29,
  20053.2
              
              Limited
      Liability Company Agreement between Ridgewood Energy Corporation and
      Investors of Ridgewood Energy M Fund, LLC dated September 7,
      2004
              
              Incorporated
      by reference to the Fund's Form 10 filed on April 29,
  200531.1
              
              Certification
      of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to
      Securities Exchange Act Rule 13a-14(a)
              
              Filed
      herewith31.2
              
              Certification
      of Kathleen P. McSherry, Chief Financial Officer of the Fund, pursuant to
      Securities Exchange Act Rule 13a-14(a)
              
              Filed
      herewith32
              
              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








20
 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 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
OFINDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





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





We have
audited the accompanying balance sheets of Ridgewood Energy M Fund, LLC (the
“Fund”) as of December 31, 2009 and 2008, and the related statements of
operations, 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 M 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 M FUND, LLC


BALANCE
SHEETS


(in
thousands, except share data)




December
      31,2009
              
              
              2008ASSETSCurrent
      assets:Cash
      and cash equivalents
              
              $
              1,304
              
              
              $
              3,687Production
      receivable
              
              
              51
              
              
              
              110Other
      current assets
              
              
              29
              
              
              
              87Total
      current assets
              
              
              1,384
              
              
              
              3,884Salvage
      fund
              
              
              2,025
              
              
              
              1,139Oil
      and gas properties:Unproved
      properties
              
              
              -
              
              
              
              1,882Proved
      properties
              
              
              9,982
              
              
              
              20,346Less:
      accumulated depletion and amortization
              
              
              (3,503
              )
              
              
              (7,537
              )Total
      oil and gas properties, net
              
              
              6,479
              
              
              
              14,691Total
      assets
              
              $
              9,888
              
              
              $
              19,714LIABILITIES
      AND MEMBERS' CAPITALCurrent
      liabilities:Due
      to operators
              
              $
              799
              
              
              $
              1,337Accrued
      expenses
              
              
              235
              
              
              
              50Total
      current liabilities
              
              
              1,034
              
              
              
              1,387Asset
      retirement obligations
              
              
              1,910
              
              
              
              1,651Total
      liabilities
              
              
              2,944
              
              
              
              3,038Commitments
      and contingencies (Note 8)Members'
      capital:Manager:Distributions
              
              
              (1,551
              )
              
              
              (1,439
              )Retained
      earnings (accumulated deficit)
              
              
              60
              
              
              
              (28
              )Manager's
      total
              
              
              (1,491
              )
              
              
              (1,467
              )Shareholders:Capital
      contributions (834 shares authorized;
                535.6818
      issued and outstanding)
              
              
              78,887
              
              
              
              78,887Syndication
      costs
              
              
              (8,597
              )
              
              
              (8,597
              )Distributions
              
              
              (8,789
              )
              
              
              (8,152
              )Accumulated
      deficit
              
              
              (53,066
              )
              
              
              (43,995
              )Shareholders'
      total
              
              
              8,435
              
              
              
              18,143Total
      members' capital
              
              
              6,944
              
              
              
              16,676Total
      liabilities and members' capital
              
              $
              9,888
              
              
              $
              19,714






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




F-3
 Table of Contents




RIDGEWOOD
ENERGY M FUND, LLC


STATEMENTS
OFOPERATIONS


(in
thousands, except per share data)




Year
      ended December 31,2009
              
              
              2008RevenueOil
      and gas revenue
              
              $
              2,004
              
              
              $
              1,369ExpensesDepletion
      and amortization
              
              
              2,675
              
              
              
              732Dry-hole
      costs
              
              
              (99
              )
              
              
              1,700Impairment
      of proved properties, net
              
              
              7,688
              
              
              
              7,688Workover
      expenses
              
              
              25
              
              
              
              909Operating
      expenses
              
              
              427
              
              
              
              246General
      and administrative expenses
              
              
              300
              
              
              
              489Total
      expenses
              
              
              11,016
              
              
              
              11,764Loss
      from operations
              
              
              (9,012
              )
              
              
              (10,395
              )Other
      incomeInterest
      income
              
              
              29
              
              
              
              181Net
      loss
              
              $
              (8,983
              )
              
              $
              (10,214
              )Manager
      InterestNet
      income (loss)
              
              $
              88
              
              
              $
              (125
              )Shareholder
      InterestNet
      loss
              
              $
              (9,071
              )
              
              $
              (10,089
              )Net
      loss per share
              
              $
              (16,934
              )
              
              $
              (18,834
              )








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




F-4
 Table of Contents




RIDGEWOOD
ENERGY M FUND, LLC


STATEMENTS
OF CHANGES IN MEMBERS’ CAPITAL


(in
thousands, except share data)




#
      of Shares
              
              
              Manager
              
              
              Shareholders
              
              
              TotalBalances,
      December 31, 2007
              
              
              535.6818
              
              
              $
              (1,305
              )
              
              $
              28,439
              
              
              $
              27,134Distributions
              
              
              -
              
              
              
              (37
              )
              
              
              (207
              )
              
              
              (244
              )Net
      loss
              
              
              -
              
              
              
              (125
              )
              
              
              (10,089
              )
              
              
              (10,214
              )Balances,
      December 31, 2008
              
              
              535.6818
              
              
              $
              (1,467
              )
              
              $
              18,143
              
              
              $
              16,676Distributions
              
              
              -
              
              
              
              (112
              )
              
              
              (637
              )
              
              
              (749
              )Net
      income (loss)
              
              
              -
              
              
              
              88
              
              
              
              (9,071
              )
              
              
              (8,983
              )Balances,
      December 31, 2009
              
              
              535.6818
              
              
              $
              (1,491
              )
              
              $
              8,435
              
              
              $
              6,944






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




F-5
 Table of Contents




RIDGEWOOD
ENERGY M FUND, LLC


STATEMENTS
OF CASH FLOWS


(in
thousands)




Year
      ended December 31,2009
              
              
              2008Cash
      flows from operating activitiesNet
      loss
              
              $
              (8,983
              )
              
              $
              (10,214
              )Adjustments
      to reconcile net loss to net cash
                provided
      by (used in) operating activities:Depletion
      and amortization
              
              
              2,675
              
              
              
              732Dry-hole
      costs
              
              
              (99
              )
              
              
              1,700Impairment
      of proved properties
              
              
              7,688
              
              
              
              7,688Settlement
      of asset retirement obligations
              
              
              -
              
              
              
              (35
              )Accretion
      expense
              
              
              20
              
              
              
              16Interest
      earned on marketable securities
              
              
              -
              
              
              
              (36
              )Changes
      in assets and liabilities:Decrease
      in production receivable
              
              
              59
              
              
              
              9Decrease
      in other current assets
              
              
              58
              
              
              
              9Increase
      in due to operators
              
              
              3
              
              
              
              27Decrease
      in accrued expenses
              
              
              (35
              )
              
              
              (87
              )Net
      cash provided by (used in) operating activities
              
              
              1,386
              
              
              
              (191
              )Cash
      flows from investing activitiesCapital
      expenditures for oil and gas properties
              
              
              (2,134
              )
              
              
              (9,124
              )Proceeds
      from the maturity of marketable securities
              
              
              -
              
              
              
              5,111Investments
      in salvage fund
              
              
              (886
              )
              
              
              (28
              )Net
      cash used in investing activities
              
              
              (3,020
              )
              
              
              (4,041
              )Cash
      flows from financing activitiesDistributions
              
              
              (749
              )
              
              
              (244
              )Net
      cash used in financing activities
              
              
              (749
              )
              
              
              (244
              )Net
      decrease in cash and cash equivalents
              
              
              (2,383
              )
              
              
              (4,476
              )Cash
      and cash equivalents, beginning of year
              
              
              3,687
              
              
              
              8,163Cash
      and cash equivalents, end of year
              
              $
              1,304
              
              
              $
              3,687Supplemental
      schedule of non-cash investing activitiesAdvances
      used for capital expenditures in oil and gas
                properties
      reclassified to proved properties
              
              $
              -
              
              
              $
              66






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




F-6
 Table of Contents




RIDGEWOOD
ENERGY M FUND, LLC


NOTES
TOFINANCIAL STATEMENTS






1.  Organization
and Purpose




The
Ridgewood Energy M Fund, LLC (the “Fund”), a Delaware limited liability company,
was formed on August 2, 2004 and operates  pursuant to a limited
liability company agreement (the “LLC Agreement”) dated September 7, 2004 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 $0.9
million, of which $0.6 million was invested in money market accounts that invest
solely in U.S. Treasury bills and notes.




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, of $0.7 million, $0.2 million and $1.1 million, which mature
in November 2010, December 2010 and February 2012, respectively, that are
classified as held-to-maturity investments.  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.




F-7
 Table of Contents




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.




At
December 31, 2009 and 2008 amounts recorded in due to operators totaling $0.8
million and $1.3 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.




2009
              
              
              2008(in
      thousands)Balance,
      beginning of year
              
              $
              1,651
              
              
              $
              476Liabilities
      incurred
              
              
              285
              
              
              
              770Liabilities
      settled
              
              
              -
              
              
              
              (35
              )Accretion
      expense
              
              
              20
              
              
              
              16Revision
      to prior estimate
              
              
              (46
              )
              
              
              424Balance,
      end of year
              
              $
              1,910
              
              
              $
              1,651




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.





F-8
 Table of Contents




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 to its proved properties totaling $7.7 million,
primarily the result of three of the Fund’s wells being fully depleted, lower
oil and gas commodity prices and increased project costs.  During the
year ended December 31, 2008, the Fund recorded impairments to proved properties
totaling $7.7 million, primarily the result of one well being fully depleted and
lower oil and gas commodity prices, partially offset by a credit received a $0.5
million related to a previously impaired well.   The fair value
of the impaired wells 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.





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.




F-9
 Table of Contents




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.





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.    The following table
reflects the net changes in unproved properties for the years ended December 31,
2009 and 2008.


2009
              
              
              2008(in
      thousands)Balance,
      beginning of year
              
              $
              1,882
              
              
              $
              7,357Additions
      to capitalized exploratory well costs pending the
                determination
      of proved reserves
              
              
              546
              
              
              
              6,940Reclassification
      to proved properties based on the
                determination
      of proved reserves
              
              
              (2,428
              )
              
              
              (12,415
              )Capitalized
      exploratory well costs charged to dry-hole costs
              
              
              -
              
              
              
              -Balance,
      end of year
              
              $
              -
              
              
              $
              1,882





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.




F-10
 Table of Contents


Year
      ended December 31,Lease
      Block
              
              2009
              
              
              2008South
      Marsh Island 213
              
              $
              (43
              )
              
              $
              1,688Other
      wells
              
              
              (56
              )
              
              
              12$
              (99
              )
              
              $
              1,700




5.  Distributions




Distributions
to shareholders are allocated in proportion to the number of shares
held.  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.   Effective July 1, 2009, the Manager elected to
permanently waive its right to distributions from the Fund.





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




Effective
October 1, 2007, and continuing for the remaining life of the Fund, the Manager
elected to waive its management fee.  Upon the waiver of the
management fee, the Fund began recording costs relating to services provided by
the Manager for accounting and investor relations.  Such costs,
totaling $80 thousand for each of the years ended December 31, 2009 and 2008,
respectively, were included in general and administrative expenses.





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.




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. The Fund has reached the end of its investment cycle.  At
December 31, 2009, the Fund has capital commitments of $1.4 million that exceed,
by $1.0 million, its current available working capital of $0.4
million.  Based upon its current reserve estimates, the Fund expects
cash flow from operations to be sufficient to cover these
deficiencies.




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.




F-11
 Table of Contents




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.




9.  Subsequent
Events




The Fund
has assessed the impact of subsequent events through the date of 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 M 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
                
                $
                -
                
                
                $
                1,882Proved
      properties
                
                
                9,982
                
                
                
                20,346Total
      oil and gas properties
                
                
                9,982
                
                
                
                22,228Accumulated
      depletion and amortization
                
                
                (3,503
                )
                
                
                (7,537
                )Oil
      and gas properties, net
                
                $
                6,479
                
                
                $
                14,691
  Table
      II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and
      DevelopmentYear
      ended December 31,2009
                
                
                
                2008(in
      thousands)Exploration
      costs
                
                $
                1,682
                
                
                $
                8,097Development
      costs
                
                
                196
                
                
                
                2,713$
                1,878
                
                
                $
                10,810








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. ("Ryder Scott") at December
      31, 2009 and 2008.  At December 31, 2008, the Fund had one
      non-producing property for which reserve data is based upon internal
      estimates.  These reserve disclosures have been prepared in
      compliance with the Securities and Exchange Commission rules 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.  Ryder Scott's report included remaining
      reserves and projected income associated with Eugene Island
      337.  Subsequent to their study, production at Eugene Island 337
      ceased with no current plans to restore. Accordingly, Eugene Island 337
      reserves have been excluded from this filing.
   December
      31, 2009
                
                
                December
      31, 2008United
      StatesOil
      (BBLS)
                
                
                Gas
      (MCF)
                
                
                Oil
      (BBLS)
                
                
                Gas
      (MCF)Proved
      developed and undeveloped reserves:Beginning
      of year
                
                
                61,910
                
                
                
                1,401,583
                
                
                
                36,699
                
                
                
                2,718,400Extensions
      and discoveries
                
                
                3,516
                
                
                
                837,000
                
                
                
                66,053
                
                
                
                1,392,012Revisions
      of previous estimates (a)
                
                
                (10,293
                )
                
                
                (393,128
                )
                
                
                (36,443
                )
                
                
                (2,597,673
                )Production
                
                
                (5,994
                )
                
                
                (438,469
                )
                
                
                (4,399
                )
                
                
                (111,156
                )End
      of year
                
                
                49,139
                
                
                
                1,406,986
                
                
                
                61,910
                
                
                
                1,401,583Proved
      developed reserves:Beginning
      of year
                
                
                61,910
                
                
                
                845,583
                
                
                
                26,848
                
                
                
                1,960,400End
      of year
                
                
                48,205
                
                
                
                664,653
                
                
                
                61,910
                
                
                
                845,583Proved
      undeveloped reserves:Beginning
      of year
                
                
                -
                
                
                
                556,000
                
                
                
                9,851
                
                
                
                758,000End
      of year
                
                
                934
                
                
                
                742,333
                
                
                
                -
                
                
                
                556,000
  (a)
              Revisions
      of previous estimates are primarily attributable to the year-end
      determination that three of the Fund's wells were fully depleted at
      December 31, 2009 and one of the Fund's wells at December 31, 2008,
      coupled with revisions due to well
performance.




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
      cash inflows
                
                $
                8,534
                
                
                $
                10,825Future
      production costs
                
                
                (1,352
                )
                
                
                (1,038
                )Future
      development costs
                
                
                (1,251
                )
                
                
                (1,985
                )Future
      net cash flows
                
                
                5,931
                
                
                
                7,80210%
      annual discount for estimated timing of cash flows
                
                
                (1,090
                )
                
                
                (1,063
                )Standardized
      measure of discounted future estimated net cash flows
                
                $
                4,841
                
                
                $
                6,739




F-14
 Table of Contents




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)Net
      change in sales and transfer prices and in production costs
                  related
      to future production
                
                $
                (1,503
                )
                
                $
                3,200Sales
      and transfer of oil and gas produced during the period
                
                
                (1,597
                )
                
                
                (1,214
                )Net
      change due to extensions, discoveries, and improved
    recovery
                
                
                1,798
                
                
                
                7,113Changes
      in estimated future development costs
                
                
                1,618
                
                
                
                -Net
      change due to revisions in quantity estimates
                
                
                (2,398
                )
                
                
                (18,571
                )Accretion
      of discount
                
                
                674
                
                
                
                1,555Other
                
                
                (490
                )
                
                
                (893
                )Aggregate
      change in the standardized measure of discounted future net
                  cash
      flows for the year
                
                $
                (1,898
                )
                
                $
                (8,810
                )





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 M FUND, LLCDate:  March
      16, 2010
            By:
            /s/ ROBERT E.
      SWANSONRobert
      E. Swanson
              Chief
      Executive Officer
              (Principal
      Executive Officer)





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




Signature
            
            Capacity
            Date/s/
      ROBERT E. SWANSON
            
            Chief Executive
      Officer (Principal
            March
      16, 2010Robert
      E. Swanson
            
            Executive
      Officer)/s/
      KATHLEEN P. MCSHERRY
            
            Executive
      Vice President and Chief Financial Officer
            March
      16, 2010Kathleen
      P. McSherry
            
            (Principal
      Accounting Officer)RIDGEWOOD
      ENERGY CORPORATIONBY:  /s/
      ROBERT E. SWANSON
            
            Chief
      Executive Officer of Manager
            March
      16, 2010Robert
      E. Swanson