UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION




WASHINGTON,
D.C. 20549




FORM
10-K




x   ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)


OF
THE SECURITIES EXCHANGE ACT OF 1934


For
the fiscal year ended December 31, 2007




or




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


SECURITIES
EXCHANGE ACT OF 1934




For
the transition period from _____ to _____




Commission
File No. 000-51268





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.)




1314
King Street, Wilmington, Delaware 19801


(Address
of principal executive offices) (Zip code)




(302)
888-7444


(Registrant’s
telephone number, including area code)




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


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




Shares of
LLC Membership Interest




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




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




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




Indicate
by check mark if the disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained herein, to the
best of the registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.   x




Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
definitions of “large accelerated filer,” “accelerated filer,” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check one):





Large
      accelerated filer
            o
            Accelerated
      filer
            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. As of March 31, 2008 there are 535.6818 Shares
outstanding.













RIDGEWOOD ENERGY M FUND,
LLC


2007
ANNUAL REPORT ON FORM 10-K


TABLE
OF CONTENTS




PAGEPART
      IITEM 1
            BUSINESS
            4ITEM 1A
            RISK FACTORS
            12ITEM 1B
            UNRESOLVED STAFF COMMENTS
            12ITEM 2
            PROPERTIES
            12ITEM 3
            LEGAL PROCEEDINGS
            12ITEM 4
            SUBMISSION OF MATTERS TO A VOTE OF SECURITY
      HOLDERS
            12PART
      IIITEM 5
            MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER
      MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
            12ITEM 6
            SELECTED FINANCIAL DATA
            14ITEM 7
            MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
      RESULTS OF OPERATIONS
            14ITEM 7A
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
            18ITEM 8
            FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
            19ITEM 9
            CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
      FINANCIAL DISCLOSURE
            19ITEM 9A
            CONTROLS AND PROCEDURES
            19ITEM 9B
            OTHER INFORMATION
            20PART
      IIIITEM 10
            DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE
            20ITEM 11
            EXECUTIVE COMPENSATION
            21ITEM 12
            SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
      AND RELATED SECURITY HOLDER MATTERS
            21ITEM 13
            CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
      INDEPENDENCE
            22ITEM 14
            PRINCIPAL ACCOUNTANT FEES AND SERVICES
            22PART
      IVITEM 15
            EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
            23








2
 Table of Contents




FORWARD-LOOKING
STATEMENTS
  Certain
statements in this Annual Report on Form 10-K (“Annual Report”) of the
Ridgewood Energy M Fund, LLC (the “Fund”) and the documents that are
incorporated by reference into this Annual Report, other than purely historical
information, including estimates, projections, statements relating to the Fund’s
business plans, strategies, objectives and expected operating results, and the
assumptions upon which those statements are based, are “forward-looking
statements” within the meaning of the Private Securities Litigation Reform Act
of 1995, Section 27A of the Securities Act of 1933, as amended (the
“Securities Act”) and Section 21E of the Securities Exchange Act of 1934
(the “Exchange Act”). These forward-looking statements generally are identified
by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,”
“strategy,” “plan,” “target,” “pursue,” “may,” “will,” “would,” “will be,” “will
continue,” “will likely result,” and similar expressions. Forward-looking
statements are based on current expectations and assumptions that are subject to
risks and uncertainties that may cause actual results to differ materially from
the forward-looking statements. Examples of such events that could cause actual
results to differ materially from historical results or those anticipated
include weather conditions, such as hurricanes, changes in market conditions
affecting the pricing of oil and natural gas, the cost and availability of
equipment, and changes in governmental regulations.  The Fund
undertakes no obligation to update or revise publicly any forward-looking
statements, whether as a result of new information, future events or
otherwise.
  AVAILABLE
INFORMATION
  The
Fund’s shares of LLC membership interest (the “Shares”) are registered under
Section 12(g) of the Exchange Act.  The Fund must therefore comply with,
among other things, the periodic reporting requirements of Section 13(a) of the
Exchange Act. As a result, the Fund prepares and files annual reports with the
United States Securities and Exchange Commission (the “SEC”) on Form 10-K,
quarterly reports on Form 10-Q and, from time to time, current reports on Form
8-K. Moreover, Ridgewood Energy Corporation (“Ridgewood Energy” or the
“Manager”) maintains a website at http://www.ridgewoodenergy.com that contains
important information about the Manager, including biographies of key management
personnel, as well as information about the oil and natural gas investments made
by the Fund and the other investment programs managed by the Manager.  Such
information includes, without limitation, a map of the Gulf of Mexico that
provides the location of every well and project managed by the Manager along
with information as to whether the project is exploratory, drilling or
producing. This information is publicly available (i.e., not password protected)
and is updated regularly.
  REPORTS
TO SHAREHOLDERS
  The Fund
does not anticipate providing annual reports to shareholders but will make
available, upon request, copies of the Fund’s periodic reports filed with the
SEC on Form 10-K and on Form 10-Q.
  WHERE
YOU CAN GET MORE INFORMATION
  The Fund
files annual, quarterly and current reports and certain other information with
the SEC. Persons may read and copy any documents the Fund files at the SEC’s
public reference room at 100 F Street, NE, Washington D.C. 20549. Information
may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an
internet site that contains reports, proxy and information statements, and other
information regarding issuers that file electronically with the SEC at
http://www.sec.gov. A copy of any such filings will be provided free of charge
to any shareholder upon written request to the Fund at its business address 947
Linwood Avenue, Ridgewood, New Jersey 07450, ATTN: General Counsel.
 
 3
 Table of Contents
  PART
I
  ITEM
1.        BUSINESS
  Overview
  The Fund
is a Delaware limited liability company and was formed on August 2, 2004 to
acquire interests primarily in oil and natural gas projects located in the U.S.
waters of the Gulf of Mexico. Ridgewood Energy, a Delaware corporation, is the
Manager.  As the Manager, Ridgewood Energy has direct and exclusive
control over the management and control of Fund operations, as manager of the
Fund.
  The Fund
initiated its private placement offering on September 7, 2004, selling whole and
fractional shares of membership interests (the “Shares”) primarily at $150
thousand per share. There is no public market for these shares and one is not
likely to develop. In addition, the shares are subject to severe restrictions on
transfer and resale and cannot be transferred or resold except in accordance
with the Fund's limited liability company agreement (the “LLC Agreement”) and
applicable federal and state securities laws.  The offering was
terminated on November 4, 2004. The Fund raised $78.9 million, and after
payment of approximately $12.2 million in offering fees, commissions and
investment fees,  had approximately $66.7 million for investments and
operating expenses. As of March 31, 2008, the Fund had 946
shareholders.
  Manager
  Ridgewood
Energy was founded in 1982 by Robert E. Swanson. As the Manager, Ridgewood
Energy has direct and exclusive control over the management of the Fund’s
operations. With respect to project investment, Ridgewood Energy locates
potential projects, conducts appropriate due diligence and negotiates and
completes the transactions in which the investments are made. This includes not
only review of existing title documents, reserve information, and other
technical specifications regarding a project, but also the review and
preparation of participation agreements and other agreements relating to an
investment.
  In
addition, Ridgewood Energy performs (or arranges for the performance of) the
management and administrative services required for Fund operations. Among other
services, Ridgewood Energy administers the accounts and handles relations with
the shareholders, including tax and other financial information. In addition,
Ridgewood Energy provides the Fund with office space, equipment and facilities
and other services necessary for its operation. Finally, Ridgewood Energy
manages and conducts the Fund’s relations with custodians, depositories,
accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks
and others, as required.
  The Fund
is required to pay all other expenses it incurs, including expenses of preparing
and printing periodic reports for shareholders and the SEC, commission fees,
taxes, outside legal, accounting and consulting fees, litigation expenses and
other expenses, if any, properly payable by the Fund. The Fund is required to
reimburse the Manager for all such Fund expenses paid by them.
  In
accordance with the Fund’s LLC Agreement, the Manager is entitled to an annual
management fee, equal to 2.5% of the total shareholder
capital.  During the years ended December 31, 2007 and 2006, the
Manager has revised its policy, thereby reducing the management fee calculation
as follows:
 
 Effective
      Date
                
                Management
      Fee CalculationAugust
      2, 2004, Inception
                
                2.5%
      of capital contributionsSeptember
      1, 2006
                
                2.5%
      of capital contributions, net of cumulative dry-hole
  costsJanuary
      1, 2007
                
                2.0%
      of capital contributions, net of cumulative dry-hole
  costsSeptember
      1, 2007
                
                1.0%
      of capital contributions, net of cumulative dry-hole
  costsOctober
      1, 2007
                
                Waived
  Management
fees for the years ended December 31, 2007 and 2006, were $0.9 million and $1.9
million, respectively.  In addition, the Manager is also entitled to a
15% interest in the cash distributions.  For the years ended December
31, 2007 and 2006, the Manager was paid distributions totaling $0.6 million and
$0.8 million, respectively.
 
 4
 Table of Contents
 
 Business
Strategy
  The
Fund’s primary investment objective is to generate cash flow from the
acquisition, exploration, production and sale of crude oil and natural gas from
oil and natural gas projects. The Fund has invested and participates in
exploration and production projects located in the waters of the Gulf of Mexico
offshore Texas, Louisiana and Alabama on the Outer Continental Shelf (the
“OCS”). These activities are governed by the Outer Continental Shelf Lands Act
(the “OCSLA”) enacted in 1953 and administered by the Mineral Management
Services (the “MMS”).  The Fund generally looks to invest in projects
that have been proposed by larger independent oil and natural gas companies
seeking to minimize their risks by selling a portion of their interest in a
project. These investments may require the Fund to pay a disproportionate part
of the drilling costs on the exploratory well of a project than its ownership
interest would otherwise require. This is called a promote and is common in
the oil and natural gas exploration industry. In addition, notwithstanding the
sale of an interest to the Fund, the seller may retain a right for some period
of time to payments from sales of oil and natural gas production from a well or
project. This is called an overriding interest which is also relatively common
in this industry. Notwithstanding any such promote or overriding interest, the
Fund has tried to invest in projects that it believes contain sufficient
commercial quantities of oil or natural gas and which are near (i) existing oil
or natural gas gathering and processing infrastructure and (ii) developed
markets where the Fund can sell its oil or natural gas.
  The Fund
tries to focus on projects that have significant reserve potential and which are
projected to have the shortest time period from investment to first production.
The Fund does not operate these projects, and although it has a vote, it is not
in control of the schedule pursuant to which its projects are developed and
completed. Moreover, when performing due diligence with respect to a project,
the Fund must rely on the independent reservoir engineers who are hired and
paid, in most cases, by the operator. The Fund does engage certain consultants
to examine and review such reserve estimates and seismic information on its
behalf.
  Manager’s
Investment Committee and Investment Criteria
  The New
Jersey office has five executives on the investment committee, three of whom
have been working together at Ridgewood Energy for over twenty years.  The
Houston office, which opened in 2003, has four executives on the investment
committee who provide operational, scientific and technical oil and gas
expertise.  In considering projects, the Manager and investment
committee investigates each such project against a list of factors that it
believes will result in the selection of projects that have the highest
probability of success.  These factors, in no particular order, include,
but are not limited to, the following (i) targeting projects that have or are
expected to have operators with significant resources and experience in oil and
gas exploration; (ii) targeting projects that have or are expected to have
partners that also have significant resources and experience in oil and gas
exploration; (iii) technical quality of the project including its geology,
seismic profile, locational trends, and whether the project has potential for
multiple prospects; (iv) oil or gas reserve potential; (v) whether and the
extent to which the operator participates as a working interest owner in the
project; (vi) economic factors, such as potential revenues from the project, the
rate of return, and estimated time to first production; (vii) risk factors
associated with exploration, as more fully described in this filing; (viii)
existence of drilling rigs, platforms and other infrastructure, at or nearby the
project; (ix) proposed drilling schedule; (x) terms of the proposed transaction,
including contractual restrictions and obligations and lease term; and
(xi)  overall cost of the project.
  Properties
  The
following table is a summary of the Fund’s active properties for the years ended
December 31, 2007 and 2006.
 
 5
 Table of Contents
 
 Working
                
                
                
                Gulf
      of
                
                Target
      Depth
                
                Total
      Spent ThroughLease
      Block
                
                Interest
                
                Operator
                
                Mexico
                
                (Feet)
                
                December
      31, 2007
                
                StatusSuccessful
      Projects
                
                
                
                
                
                
                
                
                
                (in
      thousands)South
      Marsh Island 111
                
                8.75%
                
                LLOG
                
                LA
                
                18,000
                
                $                    1,028
                
                Successful
      - production expected
                  2nd
      quarter 2008Vermilion
      344
                
                8.75%
                
                LLOG
                
                LA
                
                8,900
                
                $                    1,062
                
                Successful
      - production expected
                  2nd
      quarter 2008West
      Delta 68
                
                8.75%
                
                LLOG
                
                LA
                
                14,000
                
                $                    1,602
                
                Successful
      - production expected
                  2nd
      quarter 2008West
      Delta 67
                
                8.75%
                
                LLOG
                
                LA
                
                14,000
                
                $                       669
                
                Successful
      - production expected
                  2nd
      quarter 2008Eugene
      Island 337 A-10
                
                20.00%
                
                Devon
                
                LA
                
                16,300
                
                $                    6,072
                *
                Successful
      - production began
                  November
      2007West
      Cameron 57
                
                12.50%
                
                Chevron
                
                LA
                
                15,500
                
                $                    2,996
                
                Successful
      - production expected
                  3rd
      quarter 2008West
      Cameron 77 #2
                
                14.54%
                
                BHP
                
                LA
                
                15,000
                
                $                    8,784
                
                Shut-in
      September 2007; production resumed February 2008Dry
      holes/Abandonment (a)Eugene
      Island 364
                
                50.00%
                
                El
      Paso
                
                LA
                
                N/A
                
                $                  13,281
                **
                Abandoned
      - December 2007Ship
      Shoal 81
                
                8.75%
                
                LLOG
                
                LA
                
                N/A
                
                $                       615
                
                Dry
      Hole - October 2007East
      Break 157
                
                18.00%
                
                Woodside
                
                TX
                
                N/A
                
                $                    4,632
                
                Dry
      Hole - March 2006Eugene
      Island 357
                
                7.00%
                
                Newfield
                
                LA
                
                N/A
                
                $                    1,702
                
                Dry
      Hole - March 2006
  (a)
                Dry-hole
      costs represent wells that have been drilled but do not have commercially
      productive oil and/or natural gas reservoirsand
      have been plugged and abandoned.  Abandoned wells represent
      those that had proved reserves, for which the Fund will no longer
      participate.*
                Excludes
      impact of cumulative impairments of $4.9 million.**
                Property
      was abandoned in December 2007 resulting in an $11.4 million
      impairment.
  Properties
  Successful
Projects
 
 LLOG
Projects
 In
October 2006, the Fund acquired an 8.75% working interest in six exploratory
wells to be drilled by LLOG Exploration Company (“LLOG”) off the coast of
Louisiana.  During the first quarter of 2007, the Fund elected not to
participate in the Galveston 248 project with LLOG, which it considered no
longer economical.  On October 15, 2007, the Fund
was informed by LLOG that the exploratory well being drilled by LLOG
in the Ship Shoal 81 lease block did not have commercially productive quantities
of either oil or natural gas and has therefore been deemed an unsuccessful well
or dry hole.  The Fund has spent $0.6 million on this well through
December 31, 2007, which is included in
dry-hole costs.
 
 The
remaining four LLOG wells have been determined to be successful, are undergoing
completion, and production is expected during the second quarter of
2008.  The total budget for these projects is approximately $8.4
million, of which $4.4 million has been spent at December 31, 2007.
 
 Eugene Island
337
 The
Fund’s 20% ownership in Eugene Island 337, operated by Devon Energy
Corporation (“Devon”), was determined to be a commercial success in July
2006.  When the well began producing in November 2007, the flow rate
at production was lower than originally expected, resulting in an impairment at
September 30, 2007 in the amount of $2.9 million, based on internal reserve
estimates.  At December 31, 2007, the Fund received reserve estimates
from Ryder Scott Company, L.P., which indicated fewer reserves than internal
estimates resulting in an additional impairment of $2.0 million.  The
Fund has spent $6.1 million on this property.  The Fund has recorded
impairments totaling $4.9 million related to this property during the year ended
December 31, 2007.  No impairment was recorded during the year ended
December 31, 2006.
 
 
 West
Cameron 57
 In
September 2007, the Fund acquired a 12.5% working interest in the West Cameron
57 project operated by Chevron U.S.A., Inc. (“Chevron”).  Drilling
began in October 2007, and the well was determined to be a success in February
2008.  Completion efforts are currently in process, and production is
expected in August 2008.  As of December 31, 2007, the Fund has spent
$3.0 million on this well and has an additional $2.2 million budgeted for
completion.
 
 6
 Table of Contents
 
 West
Cameron 77 #2 (Mustang)
 The Fund
has a 14.54% working interest in the West Cameron 77 #2 project operated by BHP
Billiton Petroleum (“BHP”).  The well began production in May
2006.  Due to excessive sand and solids production in the lower zone,
production began to decline, and the zone was fully produced by September
2007.  During the fourth quarter of 2007, the Operator recompleted the
upper reservoir zone and production resumed in February 2008. The Fund has spent
$8.8 million through December 31, 2007 on this well.
 
 Dry
Holes / Abandonment
 
 Eugene Island
364
 The Fund
has a 50% working interest in Eugene Island 364 operated by El Paso E&P
Company (“El Paso”).  The well produced for a short time in 2006 but
had been shut-in since August 2006 due to mechanical problems.
 
 While
independent petroleum engineering reports from Ryder Scott Company, L.P.
indicated that Eugene Island 364 does have proved reserves, the complex
geological and stratigraphic nature of the area posed an engineering challenge
to access the reserves.  During 2006 and the early part of 2007,
expenses of approximately $0.9 million were incurred related to work over
activities on this property.  Throughout 2007, the Fund and El Paso
conducted further seismic analysis and engineering studies and determined that
the estimated additional costs to sidetrack the well were approximately $6.0
million.  However, based on the Fund’s internal interpretation of the
3-D seismic data covering the property, completed in December 2007, and its
assessment of the associated drilling risk, the Fund has concluded that the only
way to access the reserves would be to drill a new well at substantially higher
costs than the originally planned sidetrack.  As a result, the Fund
concluded that it was no longer economical to proceed with recovery efforts and
the well was abandoned.  During the fourth quarter of 2007, the
decision to abandon the well resulted in an $11.4 million impairment, inclusive
of estimated future plug and abandonment costs. The Fund maintains the
rights to the lease block through 2012.  The Fund spent $13.3 million
through December 31, 2007 on this well.
 
 East
Breaks 157
 In 2005,
the Fund acquired an 18% working interest in East Breaks 157 from ENI Petroleum
(now Woodside). The well was deemed a dry-hole and was plugged and abandoned in
March 2006.  Dry-hole costs for this property totaled $4.6
million.
 
 Eugene
Island 357
 In 2005,
the Fund acquired a 7% working interest in Eugene Island 357 from Newfield. The
well was deemed a dry-hole and was plugged and abandoned in March
2006.  Dry-hole costs for this property totaled $1.7
million.
  Working
Interest in Oil and Natural Gas Leases
  Existing
projects, and future projects, if any, are expected to be located in the waters
of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The
OCSLA, which was enacted in 1953, governs certain activities with respect to
working interests and the exploration of oil and natural gas in the
OCS.  See further discussion under the heading
“Regulation”.
  As part
of the leasing activity and as required by the OCSLA, the leases auctioned
include specified lease terms such as the length of the lease, the amount of
royalty to be paid, lease cancellation and suspension, and, to a degree, the
planned activities of exploration and production to be conducted by the lessee.
In addition, the OCSLA grants the Secretary of the Interior continuing oversight
and approval authority over exploration plans throughout the term of the
lease.
  The
winning bidder(s) at the lease sale, or the lessee(s), are given a lease by the
MMS that grants such lessee(s) the exclusive right to conduct oil and natural
gas exploration and production activities within a specific lease block. Leases
in the OCS are generally issued for a primary lease term of 5, 8 or 10 years
depending on the water depth of the lease block. The 5-year lease term is for
blocks in water depths generally less than 400 meters, 8 years for depths
between 400 meters to 800 meters and 10 years for depths in excess of 800
meters. During this primary lease term, except in limited circumstances, lessees
are not subject to any particular requirements to conduct exploratory or
development activities. However, once a lessee drills a well and begins
production, the lease term is extended for the duration of commercial
production.
  The
lessee of a particular block, for the term of the lease, has the right to drill
and develop exploratory wells and conduct other activities throughout the block.
If the initial well on the block is successful, a lessee (or third-party
operator for a project) may conduct additional geological studies and may
determine to drill additional or development wells. If a development well is to
be drilled in the block, each lessee owning working interests in the block must
be offered the opportunity to participate in, and cover the costs of, the
development well up to that particular lessee’s working interest ownership
percentage.
 
 7
 Table of Contents
 
 Generally,
working interests in an offshore gas lease under the OCSLA pay a 16.67% royalty
to the MMS. Therefore, the net revenue interest of the holders of 100% of the
working interest in the projects in which the Fund will invest is approximately
83.33% of the total revenue of the project, and, is further reduced by any other
royalty burdens that apply to a lease block. However, as described below, the
MMS has adopted royalty relief for existing OCS leases for those who drill deep
oil and natural gas projects.
  Mineral
Management Services Deep Natural Gas Royalty Incentive
  On
January 26, 2004, the MMS promulgated a rule providing incentives for companies
to increase deep oil and natural gas production in the Gulf of Mexico (the
“Royalty Relief Rule”). Under the Royalty Relief Rule, lessees will be eligible
for royalty relief on their existing leases if they drill and perforate wells
for new and deeper reserves at depths greater than 15,000 feet subsea. In
addition, an even larger royalty relief would be available for wells drilled and
perforated deeper than 18,000 feet subsea. It should be noted that the Royalty
Relief Rule does not extend to deep waters of the Gulf of Mexico off the
continental shelf nor does it apply if the price of natural gas exceeds
approximately $10.19 Million British Thermal Units (“mmbtu”) adjusted annually
for inflation. The Royalty Relief Rule is limited to leases in a water depth
less than 656 feet, or 200 meters.
  In
addition to the Royalty Relief Rule promulgated by the MMS, the Deep Water
Royalty Relief Act of 1995 (the “Deepwater Relief Act”) was enacted to promote
exploration and production of natural gas and oil in the deepwater of the Gulf
of Mexico and relieves eligible leases from paying royalties to the U.S.
Government on certain defined amounts of deepwater production.  The
Deepwater Relief Act expired in the year 2000 but was extended by the MMS to
promote continued interest in deepwater. For purposes of royalty relief, the MMS
defines deepwater as depths in excess of 656 feet (200 meters).  In
order for a lease to be eligible for royalty relief, it must be located in the
Gulf of Mexico and west of 87 degrees and 30 minutes West longitude (essentially
the Florida-Alabama boundary).
 
 Currently,
for leases entered into after November 2000, the MMS assigns a lease a specific
volume of royalty suspension based on how the suspension amount would affect the
economics of the lease’s development.   Any such royalty
suspension applicable to a particular lease is generally set forth in the lease
auction materials prepared by the MMS.  The amount of the suspension,
if any, is not determined by water depth levels (as it had in the past) but
rather based upon the MMS’ view of the characteristics and economics of the
project.  For example, projects deemed relatively secure and safe such
as those near existing transportation infrastructure may receive no royalty
relief while a similar project far away from any such infrastructure or in an
area deemed more risky may receive significant royalty
relief.   As a result, unlike the royalty relief associated with
deep drilling in shallow waters, there is no formulaic or predictable means of
determining in advance whether and to what extent royalty relief would be
available for a potential deepwater project.
  Oil
and Natural Gas Agreements
  The Fund
has entered into a short-term month to month agreement with a third-party
marketer, who is currently marketing and selling the Fund’s proportionate share
of natural gas to the public market.  The Fund is receiving market prices
for such natural gas. All of the Fund’s current projects are near existing
transportation infrastructure and pipelines.   The Manager
believes that it is likely that oil and natural gas from the Fund’s other
projects will also have access to pipeline transportation and can be marketed in
a similar fashion.  As mentioned above in Manager’s Investment Committee
and Investment Criteria, as part of the Manager’s review of a potential project,
access to existing transportation infrastructure is an extremely important
factor as the existence of such infrastructure enables production from a
successful well to get to market quickly.
  Operator
  The
projects in which the Fund has invested are operated and controlled by
unaffiliated third-party entities acting as operators (the “Operators”). The
Operators are responsible for drilling, administration and production activities
for leases jointly owned by working interest owners and acts on behalf of all
working interest owners under the terms of the applicable offshore operating
agreements. In certain circumstances, Operators will enter into agreements with
independent third-party subcontractors and suppliers to provide the various
services required for operating leases. Currently, the Fund’s projects are
operated by BHP, Chevron, Devon and LLOG.
  Because
the Fund does not operate any of the projects in which it has acquired an
interest, shareholders must not only bear the risk that the Manager will be able
to select suitable projects, but also that, once selected, such projects will be
managed prudently, efficiently and fairly by the Operators.
  Insurance
  The Manager has obtained
hazard, property, general liability and other insurance in commercially
reasonable amounts to cover the projects, as well as general liability and
similar coverage for its business operations. However, there is no assurance
that such insurance will be adequate to protect the Fund from material losses
related to the projects. In addition, the Manager’s past practice has been to
obtain insurance as a package that is intended to cover most, if not all, of the
funds under its management. These projects are owned by affiliates of the
Fund.  While the Manager believes it has obtained adequate insurance in
accordance with customary industry
practices, the possibility exists, depending on the extent of the incident, that
insurance coverage may not be sufficient to cover all losses.  In addition,
depending on the extent, nature, and payment of any claims to the Fund’s
affiliates, yearly insurance limits may become exhausted and be insufficient to
cover a claim made by the Fund in that year.
 
 8
 Table of Contents
  Salvage
Fund
  As to
projects in which the Fund owns a working interest, the Fund deposits in a
separate interest-bearing account, or a salvage fund, which is in the nature of
a sinking fund, money to help provide for the Fund’s proportionate share of the
cost of dismantling production platforms and facilities, plugging and abandoning
the projects, and removing the platforms, facilities and projects in respect of
each of such projects after their useful life, in accordance with applicable
federal and state laws and regulations.  There is no assurance that the
salvage fund will have sufficient assets to meet these requirements and any
unfunded expenses, and the Fund may be liable for such expenses. The Fund
deposited $1.0 million from capital contributions into a salvage fund, which the
Fund estimates to be sufficient to meet its potential requirements. If
management later determines the deposit and earned interest is not enough to
cover the Fund’s proportionate share of expense, the Fund will deposit payments
from operating income to make up any differences. Any portion of a salvage fund
that remains after the Fund pays its share of the actual salvage cost will be
distributed to the shareholders. There are no legal restrictions on the
withdrawal of the salvage fund.
  Seasonality
  Generally,
the Fund’s business operations are not subject to seasonal fluctuations in the
demand for oil and natural gas that would result in more of the Fund’s oil and
natural gas being sold, or likely to be sold, during one or more particular
months or seasons. Once a project is drilled and reserves of oil and natural gas
are determined to exist, the Operator of the project extracts such reserves
throughout the year. Oil and natural gas, once extracted, can be sold at any
time during the year.
  However,
the Fund’s drilling, production and transportation operations are subject to
seasonal risks, such as hurricanes, that may affect the Fund’s ability to bring
such oil or natural gas to the market and, consequently, affect the price for
such oil and natural gas. The National Hurricane Center defines hurricane season
in the Atlantic Region, Caribbean, and Gulf of Mexico to be from June 1 through
November 30. During hurricane season, the number and intensity of and resulting
damage from hurricanes in the Gulf of Mexico region could affect the gathering
and processing infrastructure, drilling platforms or the availability and price
of repair or replacement equipment. As a result, these factors may affect the
supply and, consequently, the price of oil and natural gas resulting in an
increase in price if supplies are reduced. However, even if commodity prices
increase because of weather related shortages, the Fund may not be in a position
to take immediate advantage of any such price increase if, as a result of such
weather related incident, damage occurred to its projects, the gathering
infrastructure or in the transportation network.
  The
Manager has had past experiences that indicate the typical interruption in
operations resulting from a hurricane that does not result in significant damage
may be approximately three to seven days.  The Manager has experienced
the range of possible interruptions in operations due to hurricanes from as
little as no damage and insignificant or no interruptions to significant damage
and extended interruptions. However, it is impossible to predict whether and to
what extent hurricanes and damage may occur and to what projects.
  Customers
  All of
the oil and natural gas production from the Fund’s producing properties is sold
by a third party on the Fund’s behalf.  As a result, the Fund did not
contract to sell oil and natural gas to third parties.  Therefore, the
Fund had no customers or any one customer upon which the Fund depends for more
than ten percent (10%) of its revenues.
  Energy
Prices
 
 Historically,
the markets for crude oil and natural gas have been extremely volatile, and they
are likely to continue to be volatile in the future. This volatility is caused
by numerous factors and market conditions that the Fund cannot control or
influence. Therefore, it is impossible to predict the future price of crude oil
and natural gas with any certainty. Low commodity prices could have an adverse
affect on the Fund’s future profitability. Also, the Fund has not engaged in any
price risk management programs or hedges to date.
  Competition
  Strong
competition exists in the acquisition of oil and natural gas leases and in all
sectors of the oil and natural gas exploration and production industry. Although
the Fund does not compete for the lease acquisition from the MMS, it does
compete with other companies for the acquisition of percentage ownership
interests in oil and natural gas working interests in the secondary
market.
 
 9
 Table of Contents
  In many instances, the
Fund competes for projects with large independent oil and natural gas producers
who generally have significantly greater access to capital resources, have a
larger staff, and more experience in oil and natural gas exploration and
production than the Fund. As a result, these larger companies are in a position
that they could outbid the Fund for a project. However, because
these companies are so large and have such significant resources, they tend to
focus more on projects that are larger, have greater reserve potential, but cost
significantly more to explore and develop. These larger projects increasingly
tend to be projects in the deepwater areas of the Gulf of Mexico and the North
Sea off the coast of Great Britain. However, the focus of these companies on
larger projects does not necessarily mean that they will not investigate and/or
acquire smaller projects in shallow waters for which the Fund typically
competes. Many of these larger companies have participated in the auctions for
lease blocks directly from the U.S. Government. In such cases, these companies
obtain from the U.S. Government 100% of the leasehold of a particular lease
block in the Gulf of Mexico. In order to obtain even more resources to invest in
other larger and more expensive projects, they diversify current holdings,
including projects they own in the shallow waters of the Gulf of Mexico, by
selling off percentage interests in these lease blocks. As a result, very good
projects in the shallow waters of the Gulf of Mexico become available. The Fund,
therefore, has opportunities to acquire interests in these smaller, yet
economically attractive projects.
  Employees
  The Fund
has no employees as the Manager operates and manages the Fund.
  Offices
  The
Manager’s principal executive offices are located at 947 Linwood Avenue,
Ridgewood, NJ 07450, and its phone number is 800-942-5550.  The Manager
also leases additional office space at 11700 Old Katy Road, Houston, TX
77079.  In addition, the Manager also maintains leases for other
offices that are used for administrative purposes.
  Regulation
  Oil and
natural gas exploration, development and production activities are subject to
extensive federal and state laws and regulations. Regulations governing
exploration and development activities require, among other things, the Fund’s
operators to obtain permits to drill projects and to meet bonding, insurance and
environmental requirements in order to drill, own or operate projects. In
addition, the location of projects, the method of drilling and casing projects,
the restoration of properties upon which projects are drilled and the plugging
and abandoning of projects are also subject to regulations.
  Outer
Continental Shelf Lands Act
  The
Fund’s projects are located in the offshore waters of the Gulf of Mexico on the
OCS. The Fund’s operations and activities, therefore, are governed by, among
other things, the OCSLA.
  Under
OCSLA, the United States federal government has jurisdiction over oil and
natural gas development on the OCS. As a result, the United States Secretary of
the Interior is empowered to sell exploration, development and production leases
of a defined submerged area of the OCS, or a block, through a competitive
bidding process. Such activity is conducted by the MMS, an agency of the United
States Department of Interior. The MMS administers federal offshore leases
pursuant to regulations promulgated under the OCSLA. Lessees must obtain MMS
approval for exploration, development and production plans prior to the
commencement of offshore operations. In addition, approvals and permits are
required from other agencies such as the US Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency. Offshore operations are
subject to numerous regulatory requirements, including stringent engineering and
construction specifications related to offshore production facilities and
pipelines and safety-related regulations concerning the design and operating
procedures of these facilities and pipelines. MMS regulations also restrict the
flaring or venting of production and proposed regulations would prohibit the
flaring of liquid hydrocarbons and oil without prior authorization.
  The MMS
has also imposed regulations governing the plugging and abandonment of wells
located offshore and the installation and removal of all production facilities.
Under certain circumstances, the MMS may require operations on federal leases to
be suspended or terminated. Any such suspension or termination could adversely
affect the Fund’s operations and interests.
  The MMS
conducts auctions for lease blocks of submerged areas offshore. As part of the
leasing activity and as required by the OCSLA, the leases auctioned include
specified lease terms such as the length of the lease, the amount of royalty to
be paid, lease cancellation and suspension, and, to a degree, the planned
activities of exploration and production to be conducted by the lessee. In
addition, the OCSLA grants the Secretary of the Interior continuing oversight
and approval authority over exploration plans throughout the term of the
lease.
  10
 Table of Contents
  Sales and Transportation of Natural
Gas/Oil
  The Fund
sells the Fund’s proportionate share of oil and natural gas to the market and
receives market prices from such sales. These sales are not currently subject to
regulation by any federal or state agency. However, in order for the Fund to
make such sales the Fund is dependent upon unaffiliated pipeline companies whose
rates, terms and conditions of transport are subject to regulation by theFederal
Energy Regulatory Commission (the “FERC”). The rates, terms and conditions are
regulated by FERC pursuant to a variety of statutes including the OSCLA, the
Natural Gas Policy Act and the Energy Policy Act of 1992. Generally, depending
on certain factors, pipelines can charge rates that are either market-based or
cost-of-service. In some circumstances, rates can be agreed upon pursuant to
settlement. Thus, the rates that pipelines charge us, although regulated, are
beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all
transporters on that pipeline and, as a result, management does not anticipate
that the impact to the Fund of any changes in such rates, terms or conditions
would be materially different than the impact upon other oil or natural gas
producers and marketers.
  Environmental
Matters and Regulation
  The
Fund’s operations are subject to pervasive environmental laws and regulations
governing the discharge of materials into the air and water and the protection
of aquatic species and habitats. However, although it shares the liability along
with its other working interest owners for any environmental damage, most of the
activities to which these environmental laws and regulations apply are conducted
by the Operator on the Fund’s behalf. Nevertheless, environmental laws and
regulations to which its operations are subject may require the Fund, or the
Operator, to acquire permits to commence drilling operations, restrict or
prohibit the release of certain materials or substances into the environment,
impose the installation of certain environmental control devices, require
certain remedial measures to prevent pollution and other discharges such as the
plugging of abandoned projects and, finally, impose in some instances severe
penalties, fines and liabilities for the environmental damage that is caused by
the Fund’s projects.
  Some of
the environmental laws that apply to oil and natural gas exploration and
production are:
  The
Oil Pollution Act
  The Oil
Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal
Water Pollution Control Act of 1972 (the “Clean Water Act”) and was enacted in
response to the numerous tanker spills, including the Exxon Valdez that occurred
in the 1980s. Among other things, the OPA clarifies the federal response
authority to, and increases penalties for, spills. The OPA establishes a new
liability regime for oil pollution incidents in the aquatic environment.
Essentially, the OPA provides that a responsible party for a vessel or facility
from which oil is discharged or which poses a substantial threat of a discharge
could be liable for certain specified damages resulting from a discharge of oil,
including clean-up and remediation, loss of subsistence use of natural
resources, real or personal property damages, as well as certain public and
private damages. A responsible party includes a lessee of an offshore
facility.
  The OPA
also requires a responsible party to submit proof of its financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill. Under the OPA, parties responsible
for offshore facilities must provide financial assurance of at least $35 million
to address oil spills and associated damages.
  In
certain limited circumstances, that amount may be increased to $150 million. As
indicated earlier, the Fund has not been required to make any such showing to
the MMS, as the Operators are responsible for such compliance. However,
notwithstanding the Operators’ responsibility for compliance, in the event of an
oil spill, the Fund, along with the Operators and other working interest owners,
could be liable under the OPA for the resulting environmental
damage.
  Clean
Water Act
  Generally,
the Clean Water Act imposes liability for the unauthorized discharge of
pollutants including petroleum products into the surface and coastal U.S. waters
except in strict conformance with discharge permits issued by the federal (or
state if applicable) agency. Regulations governing water discharges also impose
other requirements, such as the obligation to prepare spill response plans. The
Operators are responsible for compliance with the Clean Water Act although the
Fund may be liable for any failure of the Operators to do so.
  Federal
Clean Air Act
  The
Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), restricts the
emission of certain air pollutants. Prior to constructing new facilities,
permits may be required before work can commence and existing facilities may be
required to incur additional capital costs to add equipment to ensure and
maintain compliance. As a result, the Fund’s operations may be required to incur
additional costs to comply with the Clean Air Act.
 
 11
 Table of Contents
 
 Other
Environmental Laws
  In
addition to the above, the Fund’s operations may be subject to the Resource
Conservation and Recovery Act, which regulates the generation,
transportation, treatment, storage, disposal and cleanup of certain hazardous
wastes, as well as the ComprehensiveEnvironmental
Response, Compensation and Liability Act which imposes joint and several
liability without regard to fault or legality of conduct on classes of persons
who are considered responsible for the release of a hazardous substance into the
environment.
  The above
represents a brief outline of the major environmental laws that may apply to the
Fund’s operations. The Fund believes that its operators are in compliance with
each of these environmental laws and the regulations promulgated
thereunder.  The Fund does not believe that the costs of complying
with environmental laws (federal, state and local) will have a material adverse
impact on the financial condition and/or operations of the Fund.
  ITEM
1A.     RISK FACTORS
  Not
required.
  ITEM
1B.     UNRESOLVED STAFF COMMENTS
  Not
applicable.
  ITEM
2.        PROPERTIES
  The
information regarding the Fund’s properties that is contained under heading
“Properties” in Item 1. “Business”of
this Annual Report is incorporated herein by reference.
  ITEM
3.        LEGAL
PROCEEDINGS
  On August
16, 2006, the Manager of the Fund filed a lawsuit against the former independent
registered public accounting firm for the Fund, Perelson Weiner (“PW”), in New
Jersey Superior Court, captioned Ridgewood Energy Corporation v. Perelson
Weiner, LLP, Docket No. L-6092-06.  The suit alleged professional
malpractice and breach of contract in connection with audit and accounting
services performed for the Fund by PW. Thereafter, PW filed a counterclaim
against the Manager on October 20, 2006, alleging breach of contract due to
unpaid invoices in the amount of $326,554. Discovery is ongoing and no trial
date has been set.
  Legal
costs related to this claim are borne by the Manager.
  ITEM
4.        SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
  None.
  PART
II
  ITEM
      5.
              MARKET
      FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER MATTERS, AND
      ISSUER PURCHASES OF EQUITY
SECURITIES
  Market
Price of Common Units, Distributions and Related Shareholder
Matters
  There is
currently no established public trading market for the Shares.  As of
the date of this filing, there were approximately 946 holders of record of the
Fund.    During the years ended December 31, 2007 and 2006,
the Fund has paid distributions totaling $3.8 million and $5.6 million,
respectively.
  Participation
in Costs and Revenues
  The
Fund’s investment objective is primarily to generate current cash flow for
distribution to shareholders from the operation of the Fund projects to the
extent that such distributions are consistent with the reserve requirements and
operational needs of those projects.  If the Fund does make distributions,
this section describes how the Fund will:
  •
              determine
      what cash flow will be available for distributions to
      shareholders,
 •
              distribute
      available cash flow,
 •
              give
      the Manager a share of cash flow, if
available,
 •
              handle
      returns of capital contributions,
 •
              allocate
      income and deductions for tax purposes,
and
 •
              maintain
      capital accounts for shareholders.
  12
 Table of Contents
  Available
cash determines what amounts in cash the Fund will be able to distribute in cash
to shareholders.   There are three types of available cash as
follows:
  “Available
Cash from Capital Transactions” is total cash received by the Fund from the
proceeds of the sale or other disposition of the Fund’s property (including
items such as insurance proceeds and other amounts received out of the ordinary
course of business), but excluding dispositions of temporary investments of the
Fund.
  “Available
Cash from Temporary Investments” is cash from short-term investments (i.e. U.S.
Treasury securities, certificates of deposits) and other interest bearing cash
accounts.
  “Available
Cash from Operations” is all other available cash.
  There is
no fixed requirement to distribute available cash; instead, it will be
distributed to shareholders to the extent and at such times as the Manager
believes is advisable. Once the amount and timing of a distribution is
determined, it shall be made to shareholders as described below.
  Distributions
from Operations
  At
various times during a calendar year, the Fund will determine whether there is
enough Available Cash from Operations for a distribution to shareholders. The
amount of Available Cash from Operations determined to be available, if any,
will be distributed to the shareholders. At all times, the Manager will be
entitled to 15% and shareholders will be entitled to 85% of the Available Cash
from Operations distributed.
  Distributions
of Available Cash from Capital Transactions
  Available
Cash from Capital Transactions that the Fund decides to distribute will be paid
as follows:
  •
              Before
      shareholders have received total distributions equal to their capital
      contributions, 99% of Available Cash from Capital Transactions will be
      distributed to shareholders and 1% to the
  Manager.
 •
              After
      shareholders have received total distributions equal to their capital
      contributions, 85% of Available Cash from Capital Transactions will be
      distributed to shareholders and 15% to the
  Manager.
  General
Distribution Provisions
  Distributions
to shareholders under the foregoing provisions will be apportioned among them in
proportion to their ownership of their shares.  The Manager has the sole
discretion to determine the amount and frequency of any distributions; provided,
however, that a distribution may not be made selectively to one shareholder or
group of shareholders but must be made ratably to all shareholders entitled to
that type of distribution at that time.  The Manager in its discretion
nevertheless may credit select persons with a portion of its compensation from
the Fund or distributions otherwise payable to the Manager.
  Because
distributions will be dependent upon the earnings and financial condition of the
Fund, its anticipated obligations, the Manager’s discretion and other factors,
there can be no assurance as to the frequency or amounts of any distributions
that the Fund may make.
  Return
of Capital Contributions
  If the
Fund for any reason at any time does not find it necessary or appropriate to
retain or expend all capital contributions, in its sole discretion it may return
any or all of such excess capital contributions ratably to shareholders.  A
return of capital contributions is not treated as a distribution.  The Fund
and the Manager will not be required to return any fees deducted from the
original capital contribution or any costs and expenses incurred and paid by the
Fund.  Any such return of capital will decrease the shareholders’ capital
contributions.
  Capital
Accounts and Allocations
  The tax
consequences of an investment in the Fund to a shareholder in the event of
dissolution depend on the shareholder’s capital account and on the allocations
of profits and losses to that account.  The Fund’s taxable profits or
losses are allocated among the shareholders as described below and profits or
losses are added to or subtracted from the shareholders’ capital accounts. 
The amounts allocated to each shareholder will generally not be equal to the
distributions the shareholder receives until final liquidating distributions are
made to shareholders.
 
 13
 Table of Contents
 
 The
Fund does not currently anticipate that any contributions or distributions of
property will be made.  Certain additional adjustments to capital accounts
will be made if necessary to account for the effects of non-recourse debt
incurred by the Fund, if any, or contributions of property, if any, to the Fund.
  ITEM
6.        SELECTED FINANCIAL
DATA
  Not
required.
  ITEM
7. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
  Overview
of the Fund’s Business
  The Fund
is an independent oil and natural gas producer. The Fund’s primary investment
objective is to generate cash flow for distribution to its shareholders through
participation in oil and natural gas exploration and development projects in the
Gulf of Mexico. See also Item 1. “Business”.
  The
Manager performs certain duties on the Fund’s behalf including the evaluation of
potential projects for investment and ongoing administrative and advisory
services associated with these projects.  The Fund does not currently, nor
is there any plan to operate any project in which the Fund participates. The
Manager enters into operating agreements with third-party operators for the
management of all exploration, development and producing operations, as
appropriate.  See also Item 1. “Business”.
  Revenues
are subject to the markets for crude oil and natural gas, which have been
extremely volatile, and are likely to continue to be volatile in the future.
This volatility is caused by numerous factors and market conditions that the
Fund cannot control or influence. Therefore, it is impossible to predict the
future price of crude oil and natural gas with any certainty. Low commodity
prices could have an adverse affect on the Fund’s future
profitability.
  Critical
Accounting Estimates
 The
discussion and analysis of the Fund’s financial condition and results of
operations are based upon its financial statements, which have been prepared in
conformity with U.S. generally accepted accounting principles, or GAAP. In
preparing these financial statements, the Fund is required to make certain
estimates, judgments and assumptions. These estimates, judgments and assumptions
affect the reported amounts of the Fund’s assets and liabilities, including the
disclosure of contingent assets and liabilities, at the date of the financial
statements and the reported amounts of the Fund’s revenues and expenses during
the periods presented.  The Fund evaluates these estimates and assumptions
on an ongoing basis. The Fund bases its estimates and assumptions on historical
experience and on various other factors that the Fund believes to be reasonable
at the time the estimates and assumptions are made. However, future events and
actual results may differ from these estimates and such differences may have a
material impact on the results of operations, financial position, or cash
flows.  See Note 2 – Summary of Significant Accounting Policies
of Item 8. “Financial Statements and Supplementary Data” contained in this
Annual Report for a discussion of the Fund’s significant accounting
policies.
  Accounting
for Exploration and Development Costs
  Exploration
and production activities are accounted for using the successful efforts method.
Costs of acquiring unproved and proved oil and gas leasehold acreage, including
lease bonuses, brokers’ fees and other related costs, are capitalized. Annual
lease rentals, exploration expenses and exploratory dry-hole costs are expensed
as incurred. Costs of drilling and equipping productive wells, including
development dry holes, and related production facilities are
capitalized.
  The costs
of exploratory wells that find oil and gas reserves are capitalized pending
determination of whether proved reserves have been found. Exploratory drilling
costs remain capitalized after drilling is completed if (1) the well has
found a sufficient quantity of reserves to justify completion as a producing
well and (2) sufficient progress is being made in assessing the reserves
and the economic and operating viability of the project. If either of those
criteria is not met, or if there is substantial doubt about the economic or
operational viability of the project, the capitalized well costs are charged to
expense. Indicators of sufficient progress in assessing reserves and the
economic and operating viability of a project include: commitment of project
personnel, active negotiations for sales contracts with customers, negotiations
with governments, operators and contractors and firm plans for additional
drilling and other factors.
  Proved
Reserves
  Annually,
the Fund engages an independent petroleum engineer, Ryder Scott Company, L.P.,
to perform a comprehensive study of the Fund’s producing properties and
dependent upon timing of discoveries, certain successful properties, to
determine the quantities of reserves and the period over which such reserves
will be recoverable. The Fund’s estimates of proved reserves are based on
the quantities of natural gas and oil that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from
known reservoirs under existing economic and operating conditions. However,
there are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future revenues, rates of production and timing of
development expenditures, including many factors beyond the Fund’s control. The
estimation process is very complex and relies on assumptions and subjective
interpretations of available geologic, geophysical, engineering and production
data and the accuracy of reserve estimates is a function of the quality and
quantity of available data, engineering and geological interpretation, and
judgment. In addition,
as a result of volatility and changing market conditions, commodity prices and
future development costs will change from period to period, causing estimates of
proved reserves and future net revenue to change.  Estimates of proved
reserves are key components of the Fund’s most significant financial estimates
involving its rate for recording depreciation, depletion and
amortization.
 
 14
 Table of Contents
 
 Unproved
Properties
  Unproved
properties is comprised of capital costs incurred for undeveloped acreage, wells
and production facilities in progress, wells pending determination and related
capitalized interest. These costs are initially excluded from the depletion base
until the outcome of the project has been determined, or generally, until it is
known whether proved reserves will or will not be assigned to the
property.  The Fund assesses all items in its unproved property balance on
an ongoing basis for possible impairment or reduction in value. 
Substantially all of the costs included in its unproved property balances are
evaluated within two years.
  Asset
Retirement Obligations
 For oil
and natural gas properties, there are obligations to perform removal and
remediation activities when the properties are retired.  When a project
reaches drilling depth and is determined to be either proved or dry, a liability
is recognized for the fair value of legally required asset retirement
obligations once it can be reasonably estimated.  The Fund capitalizes the
associated asset retirement costs as part of the carrying amount of the
long-lived assets. Plug and abandonment costs associated with unsuccessful
projects are expensed as dry-hole costs.
  Impairment
of Long-Lived Assets
  The Fund
reviews long-lived assets, including oil and natural gas fields, for impairment
whenever events or changes in circumstances indicate that the carrying amounts
may not be recovered.  Long-lived assets are tested based on identifiable
cash flows (the field level for oil and natural gas assets) and are largely
independent of the cash flows of other assets and liabilities. If the carrying
amounts of the long-lived assets are not expected to be recovered by
undiscounted future net cash flow estimates, the assets are impaired and an
impairment loss is recorded.  The amount of impairment is based on the
estimated fair value of the assets determined by discounting anticipated future
net cash flows.
  In the
case of oil and natural gas fields, the present value of future net cash flows
is based on management’s best estimate of future prices, which is determined
with reference to recent historical prices and published forward prices, applied
to projected production volumes of individual fields and discounted at a rate
commensurate with the risks involved. The projected production volumes represent
reserves, including probable reserves, expected to be produced based on a
stipulated amount of capital expenditures. The production volumes, prices and
timing of production are consistent with internal projections and other
externally reported information. Oil and natural gas prices used for determining
asset impairments will generally differ from those used in the standardized
measure of discounted future net cash flows, since the standardized measure
requires the use of actual prices on the last day of the year.
  Results
of Operations
  The
following table summarizes the Fund’s results of operations, and should be read
in conjunction with the Fund’s financial statements and the notes thereto
included within Item 8. “Financial Statements and Supplementary Data” contained
in this Annual Report.
 
 15
 Table of Contents
 
 Year
      ended December 31,2007
                
                
                2006(in
      thousands)RevenueOil
      and gas revenue
                
                $
                3,389
                
                
                $
                7,780ExpensesDepletion
      and amortization
                
                
                1,086
                
                
                
                4,100Dry-hole
      costs
                
                
                705
                
                
                
                6,416Impairment
      of proved property
                
                
                16,282
                
                
                
                -Lease
      operating expenses
                
                
                754
                
                
                
                867Management
      fees to affiliate
                
                
                914
                
                
                
                1,854Other
      operating expenses
                
                
                87
                
                
                
                12General
      and administrative expenses
                
                
                652
                
                
                
                605Total
      expenses
                
                
                20,480
                
                
                
                13,854Loss
      from operations
                
                
                (17,091
                )
                
                
                (6,074
                )Other
      incomeInterest
      income
                
                
                933
                
                
                
                1,647Net
      loss
                
                $
                (16,158
                )
                
                $
                (4,427
                )
  Year
ended December 31, 2007 compared to Year ended December 31,
2006
  Operating
Revenue.The
Fund currently has two producing wells, West Cameron 77 and Eugene Island
337, which came onto production in May 2006 and November 2007,
respectively.  Oil and gas revenue for the year ended December 31,
2007 was $3.4 million, a $4.4 million decrease from the year ended December 31,
2006.  Natural gas production was approximately 0.4 million mcf in
2007 compared to 0.9 million mcf in 2006.  Oil production for the year
ended December 31, 2007 was approximately 5 thousand barrels compared to 29
thousand barrels for the year ended December 31, 2006. Production volumes
for both oil and natural gas decreased significantly due to declining production
from the lower zone of the West Cameron 77 well.  By September 2007,
the lower zone was fully produced and the well was shut in as recompletion
efforts began for the upper reservoir zone.  Revenues were also
negatively impacted by the Eugene Island 364 well, which generated revenues
of $2.1 million in 2006 and did not produce in 2007.  See Item 1.
“Business”.
 
 Natural
gas prices for the year ended December 31, 2007 averaged $7.42 per mcf, as
compared to the year ended December 31, 2006 when prices were $6.47 per
mcf.  Oil prices during the year ended December 31, 2007 averaged
approximately $65 per barrel as compared to approximately $69 per barrel for the
year ended December 31, 2006.  Although oil prices have been rising in
2007, the majority of oil production took place during the early part of the
2007 and thus, the Fund did not benefit from the rising prices.
 
 Depletion and
Amortization.  Depletion and amortization for the years ended
December 31, 2007 and 2006, were $1.1 million and $4.1 million,
respectively.  The decrease in depletion and amortization is a result
of an overall decline in West Cameron 77 production volumes and the shut-in of
the Eugene Island 364 property, which did not produce during the year ended
December 31, 2007, partially offset by onset of production of Eugene Island 337
in November 2007.
 
 Dry-hole
Costs.Dry-hole costs are those
costs incurred to drill and develop a well that is ultimately found to be
incapable of producing either oil or natural gas in sufficient quantities to
justify completion of the well. The following table summarizes dry-hole costs
inclusive of plug and abandonment costs.
 
 Year
      ended December 31,Lease
      Block
                
                2007
                
                
                2006(in
      thousands)Ship
      Shoal 81
                
                $
                615
                
                
                $
                -Main
      Pass 155
                
                
                96
                
                
                
                77East
      Breaks 157
                
                
                -
                
                
                
                4,632Eugene
      Island 357
                
                
                (6
                )
                
                
                1,707$
                705
                
                
                $
                6,416
 
 16
 Table of Contents
 
 Impairment of
Proved Property.Impairment of proved properties for the year ended
December 31, 2007 was $16.3 million relating to the Fund’s investments in the
Eugene Island 337 lease block of $4.9 million, and Eugene Island 364 lease block
of $11.4 million.  There were no impairments during the year ended
December 31, 2006.  Under successful efforts accounting, reserve
estimates are used to calculate cash flows as well as depletion
rates.  Proved reserves and future net cash flows are estimated using
sales prices estimated to be in effect as of the date of the reserve
estimate calculation.  Oil and natural gas prices, which have
fluctuated widely in recent years, affect the future revenues. Any
estimates of natural gas and oil reserves and their values are inherently
uncertain, including many factors beyond the Fund’s control.  See
additional discussion in Item 1. “Business”.
 
 Lease Operating
Expenses. Lease operating expenses represent the day to day cost of
operating and maintaining wells and related facilities. For the years ended
December 31, 2007 and 2006, lease operating expenses were $0.8 million and $0.9
million, respectively.  The decrease is a result of declining
production volumes at West Cameron 77 and the shut-in of the Eugene Island 364
well throughout 2007, and then the abandonment of the Eugene Island 364 well in
December 2007.  These decreases were slightly offset by lease
operating expenses for the Eugene Island 337 well, which began production in
November 2007.
 
 Management
Fee.Management fees
for the years ended December 31, 2007 and 2006 were $0.9 million and $1.9
million, respectively. Management fees are charged to cover expenses
associated with overhead incurred by the Manager for its ongoing management,
administrative and advisory services.  Such overhead expenses include
but are not limited to rent, payroll and benefits for employees of the Manager,
and other administrative costs.  The decrease of $1.0 million in 2007
was attributable to a policy change by the Manager, reducing the calculation of
the fee for the amount of cumulative dry-hole costs incurred.  In
addition, on October 1, 2007, the Manager elected to waive the management fee
for the remaining life of the Fund. See additional discussion in Item 1.
"Business".
 
 Other Operating
Expense. Other operating expenses for the year ended December 31,
2007 were $87 thousand related to geological costs incurred of $74 thousand,
mainly relating to the new LLOG properties, and an analysis for Eugene Island
364, and accretion expense totaling $13 thousand.  Other operating
expenses were $12 thousand for the year ended December 31, 2006 related to
accretion expense.
 
 General and
Administrative Expenses.General and administrative expenses
represent costs specifically identifiable or allocable to the Fund as detailed
in the schedule below.
 
 Year
      ended December 31,2007
                
                
                2006(in
      thousands)Insurance
                
                $
                417
                
                
                $
                409Accounting
      and legal fees
                
                
                202
                
                
                
                166Trust
      fees and other
                
                
                33
                
                
                
                30$
                652
                
                
                $
                605
  Insurance
expense represents premiums related to well control insurance, which increases
as drilling activity increases, and directors and officers liability policy,
which is allocated by the Manager to the Fund based on capital raised by the
Fund to total capital raised by all oil and natural gas funds managed by the
Manager. Accounting and legal fees represent annual audit and tax preparation
fees, quarterly reviews and filing fees of the Fund.  Trust fees
represent bank fees associated with the management of the Fund’s short-term
investment portfolio in US Treasury securities.
  Interest
Income.  Interest income for the years ended December 31, 2007
and 2006 was $0.9 million and $1.6 million, respectively.  Interest
income decreased as a result of a reduction in investment balances in 2007,
partially offset by increased interest rates for the year ended December 31,
2007.
 
 Capital
Resources and Liquidity
 
 Operating Cash
Flows
  Cash
flows provided by operating activities for the year ended December 31, 2007 were
$1.7 million, primarily related to cash receipts from oil and natural gas
production of $3.8 million and interest income received of $0.5 million,
partially offset by
payments for management fees of $0.9 million, general and administrative
expenses of $0.7 million, operating expenses of $0.8 million and
unfavorable working capital of $0.2 million.
  Cash
flows provided by operating activities for the year ended December 31, 2006 were
$5.2 million, primarily related to cash receipts from oil and natural gas
production of $7.3 million and interest income received of $1.6 million,
partially offset by payments for management fees of $1.9 million, operating
expenses of $0.9 million, general and administrative expenses of $0.6 million
and unfavorable working capital of $0.3 million.
 
 17
 Table of Contents
  Investing
Cash Flows
  Cash
flows provided by investing activities for the year ended December 31, 2007 were
$2.7 million, primarily related to proceeds from the maturity of marketable
securities of $24.7 million and insurance proceeds of $0.2 million, partially
offset by capital expenditures for oil and gas properties of $8.4 million and
investments in marketable securities $13.8 million, inclusive of salvage
fund.
 
 Cash
flows used in investing activities for the year ended December 31, 2006 were
$35.5 million, primarily related to capital expenditures for oil and gas
properties of $21.7 million and investments in marketable securities, inclusive
of salvage fund,  of $30.4 million, partially offset by the proceeds
from the sale of marketable securities of $15.3 million and insurance proceeds
of $1.2 million.
 
 Financing
Cash Flows
 Cash
flows used in financing activities were $3.8 million for the year ended December
31, 2007, consisting of distributions to shareholders and the
Manager.
 
 Cash
flows used in financing activities were $5.6 million for the year ended December
31, 2006, consisting of distributions to shareholders and the
Manager.
  Estimated
Capital Expenditures
  The Fund
has entered into multiple offshore operating agreements for the drilling and
development of its investment properties.  The estimated capital
expenditures associated with these agreements can vary depending on the stage of
development on a property-by-property basis.  As of December 31, 2007,
the Fund had commitments related to authorizations for expenditures totaling
$1.5 million for properties.   If the properties were to be
successful, the Fund would make additional expenditures totaling $5.1 million
related to the completion of these properties.
  Liquidity
Needs
  The
Fund’s primary short-term liquidity needs are to fund its 2008 operations and
capital expenditures with existing cash on-hand and income earned from its
short-term investments and cash and cash equivalents.
  Distributions,
if any, are funded from cash flow from operations, and the frequency and amount
are within the Manager’s discretion subject to available cash from operations,
reserve requirements and Fund operations.
  The
capital raised by the Fund in its private placement is more than likely all the
capital it will be able to obtain for investments in projects. The number of
projects in which the Fund can invest will naturally be limited and each
unsuccessful project the Fund experiences, if any, will not only reduce its
ability to generate revenue, but also exhaust its limited supply of capital.
Typically the Manager seeks an investment portfolio that combines high and low
risk exploratory projects.
  When the
Manager makes a decision for participation in a particular project, it assumes
that the well will be successful and allocates enough capital to budget for the
completion of that well and the additional development wells that are
anticipated to be drilled. If the exploratory well is deemed a dry hole or if it
is un-economical, the capital allocated to the completion of that well and to
the development of additional wells is then reallocated to a new project or used
to make additional investments.
  Off-Balance
Sheet Arrangements
  The Fund
had no off-balance sheet arrangements as of December 31, 2007 and 2006 and does
not anticipate the use of such arrangements in the future.
  Contractual
Obligations
  The Fund
enters into operating agreements with operators.  On behalf of the Fund, an
operator enters into various contractual commitments pertaining to exploration,
development and production activities.  The Fund does not discuss or
negotiate any such contracts. No contractual obligations exist at December 31,
2007 and 2006 other than those discussed in “Estimated Capital Expenditures”
above.
  ITEM
7A. QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
  Not
required.
 18
 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 and filed as part of this
report.
  ITEM
9. CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
  As
reported on a Form 8-K filed with the SEC on June 14, 2006, the Manager of the
Fund dismissed Perelson Weiner, LLP as the Fund’s independent registered public
accountants effective June 8, 2006.
  The Fund
was formed on August 2, 2004 and filed its Registration Statement on Form 10 in
April 2005; thus, the period beginning August 2, 2004 and ended December 31,
2004 was the Fund's first audited reporting period. Perelson Weiner's audit
report on the financial statements of the Fund for the period August 2, 2004
(Inception) through December 31, 2004 did not contain an adverse opinion or
disclaimer of opinion, nor was such report qualified or modified as to
uncertainty, audit scope or accounting principles.
  From the
date of inception of the Fund through June 8, 2006, there were no disagreements
with Perelson Weiner on any matter of accounting principles or practices,
financial statement disclosure or auditing scope or procedure, which
disagreements, if not resolved to the satisfaction of Perelson Weiner, would
have caused Perelson Weiner to make reference to the subject matter of the
disagreements in their report on the Fund's financial statements for such
period.
  From the
date of inception of the Fund through June 8, 2006, there were no “reportable
events” as defined in Item 304(a)(1)(v) of Regulation S-K.
  As
reported on a Form 8-K filed with the SEC on July 13, 2006, the Manager of the
Fund appointed Deloitte & Touche LLP (“D&T”) as the Fund’s independent
registered public accountants effective July 12, 2006.
  ITEM
9A. CONTROLS
AND PROCEDURES
  Disclosure
Controls and Procedures
  Under the
supervision and with the participation of the Chief Executive Officer and Chief
Financial Officer of the Fund, management of the Fund and the Manager carried
out an evaluation of the effectiveness of the design and operation of the Fund’s
disclosure controls and procedures pursuant to the Exchange Act Rule 13a-15(e)
as of December 31, 2007.  Based upon the evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the Fund’s
disclosure controls and procedures are effective as of the end of the period
covered by this report.
  Management's
Report on Internal Control over Financial Reporting
  Management
of the Fund is responsible for establishing and maintaining adequate internal
control over financial reporting (as defined in Exchange Act Rule 13a-15(f)).
 The Fund’s internal control over financial reporting is designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.
 
 Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements.  Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
 
 Management
of the Fund, including its Chief Executive Officer and Chief Financial Officer,
assessed the effectiveness of the Fund’s internal control over financial
reporting as of December 31, 2007.  In making this assessment,
management of the Fund used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal
Control — Integrated Framework.
 
 Based on
their assessment using those criteria, management of the Fund concluded that, as
of December 31, 2007, the Fund’s internal control over financial reporting
is effective.
  This
annual report does not include an attestation report of the Fund’s registered
public accounting firm regarding internal control over financial reporting. The
Fund’s report was not subject to attestation by the Fund’s registered public
accounting firm pursuant to temporary rules of the Securities and Exchange
Commission that permit the Fund to provide only management’s report in this
annual report.
  19
 Table of Contents
  Changes
in Internal Control over Financial Reporting
  The Chief
Executive Officer and Chief Financial Officer of the Fund have concluded that
there have not been any changes in the Fund’s internal control over financial
reporting during the quarter ended December 31, 2007 that have materially
affected, or are reasonably likely to materially affect, the Fund’s internal
control over financial reporting.
  ITEM
9B. OTHER
INFORMATION
  None.
  PART
III
  ITEM
10. DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
  The Fund
has engaged Ridgewood Energy Corporation as Manager. The Manager has very broad
authority, including the authority to appoint the executive officers of the
Fund.
  Executive
officers of Ridgewood Energy and the Fund and their ages at December 31, 2007
are as follows:
   Name,
      Age and Position with Registrant
              
              Officer
      SinceRobert
      E. Swanson, 60President
      and Chief Executive Officer
              
              1982W.
      Greg Tabor, 47Executive
      Vice President andDirector
      of Business Development
              
              2004Robert
      L. Gold, 49Executive
      Vice President
              
              
              1987Kathleen
      P. McSherry, 42Executive
      Vice President andChief
      Financial Officer
              
              
              2000Daniel
      V. Gulino, 47Senior
      Vice President and General Counsel
              2003Adrien
      Doherty, 55
              
              
              
              2006Executive
      Vice President
  Set forth
below is the name of and certain biographical information regarding, the
executive officers of Ridgewood Energy and the Fund:
  Robert E. Swanson has served
as the President, Chief Executive Officer, sole director, and sole stockholder
of Ridgewood Energy since its inception. Mr. Swanson is also the controlling
member of Ridgewood Renewable Power, LLC (“Ridgewood Power”) and Ridgewood
Capital Corporation (“Ridgewood Capital”), affiliates of Ridgewood Energy. Mr.
Swanson has been President and registered principal of Ridgewood Securities
Management, LLC and has served as the Chairman of the Board of Ridgewood Capital
since its organization in 1998. Mr. Swanson is a member of the New York State
and New Jersey State Bars, the Association of the Bar of the City of New York
and the New York State Bar Association. He is a graduate of Amherst College and
Fordham University Law School.
  Greg Tabor has served as the
Executive Vice President and Director of Business Development for Ridgewood
Energy since January 2004. Mr. Tabor was senior business development manager for
El Paso Production Company from December 2001 to December 2003.
From April 2000 to December 2001, Mr. Tabor was Vice President, Business
Development for Madison Energy Advisors. Mr. Tabor is a graduate of the
University of Houston.
 
 20
 Table of Contents
  Robert L. Gold has served as
the Executive Vice President of Ridgewood Energy since 1987. Mr. Gold has also
served as the President and Chief Executive Officer of Ridgewood Capital since
its inception in 1998. Mr. Gold is a member of the New York State Bar. He is a
graduate of Colgate University and New York University School of
Law.
  Kathleen P. McSherry has
served as the Executive Vice President and Chief Financial Officer of Ridgewood
Energy since 2000. Ms. McSherry has been employed by Ridgewood Energy since
1987, first as the Assistant Controller and then as the Controller before being
promoted to Chief Financial Officer in 2000. Ms. McSherry also serves as Vice
President of Systems and Administration of Ridgewood Power. Ms. McSherry holds a
Bachelor of Science degree in Accounting.
  Daniel V. Gulino has served as
Senior Vice President and General Counsel of Ridgewood Energy since August 2003.
Mr. Gulino also serves as Senior Vice President and General Counsel of Ridgewood
Power Management, Ridgewood Power, and Ridgewood Capital and has done so since
2000. Mr. Gulino is a member of the New Jersey State and Pennsylvania State
Bars. He is a graduate of Fairleigh Dickinson University and Rutgers School of
Law.
  Adrien Doherty has served as
Executive Vice President of Ridgewood Energy since 2006.  Mr. Doherty
joined Ridgewood Energy after a thirty year career in investment banking, most
recently as Head of Barclay’s Capital’s oil and gas banking effort.  Mr.
Doherty is a graduate of Amherst College and the Wharton Graduate Division of
the University of Pennsylvania.
  Code
of Ethics
 
 The
Manager of the Fund has adopted a code of ethics for all employees, including
the Manager’s principal executive officer and principal financial and accounting
officer. If any amendments are made to the code of ethics or the Manager of the
Fund grants any waiver, including any implicit waiver, from a provision of the
code to any the Manager’s executive officers, the Fund will disclose the nature
of such amendment or waiver on our website or in a current report on Form
8-K.  Copies of the code of ethics are available, without charge, on
the Manager’s website at www.ridgewoodenergy.com and in print upon written
request to the business address of the Manager at 947 Linwood Avenue, Ridgewood,
New Jersey 07450, ATTN:  General Counsel.
  Board
of Directors and Board Committees
  The Fund
does not have its own board of directors or any board committees. The Fund
relies upon the Manager to provide recommendations regarding dispositions and
financial disclosure.  Officers of the Fund are not compensated by the
Fund, and all compensation matters are addressed by the Manager, as described in
Item 11. “Executive Compensation” of this Annual Report.  Because the Fund
does not maintain a board of directors and because officers of the Fund are
compensated by the Manager, the Manager believes that it is appropriate for the
Fund to not have a nominating or compensation committee.
  Section
16(a) Beneficial Ownership Reporting Compliance
  Section
16(a) of the Exchange Act, as amended, requires the Fund’s executive officers
and directors, and persons who own more than 10% of a registered class of the
Fund’s equity securities, to file reports of ownership and changes in ownership
with the SEC. Based on a review of the copies of reports furnished or otherwise
available to the Fund, the Fund believes that during the year ended December 31,
2007, all filing requirements applicable to its officers, directors and 10%
beneficial owners were met.
  ITEM
11. EXECUTIVE
COMPENSATION
  The
executive officers of the Fund do not receive compensation from the Fund. The
Manager, or its affiliates, compensates the officers without additional payments
by the Fund. See Item 13. “Certain Relationships and Related Transactions and
Director Independence” for more information regarding Manager compensation and
payments to affiliated entities.
  ITEM
12. SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY
HOLDER MATTERS
  The
following table sets forth information with respect to beneficial ownership of
the shares as of March 31, 2008 (no person owns more than 5% of the shares)
by:
  •
              each
      executive officer (there are no directors);
and
 •
              all
      of the executive officers as a
group.
 
 21
 Table of Contents
 
 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 December 31, 2007. Other
than the below, no officer and director owns any of the Fund’s
shares.
 Name of beneficial
      owner
              
              Number
                of
      shares
              
              
              PercentRobert
      E. Swanson (1), President and Chief Executive Officer
              
              
              5.0000
              
              
              
              *Executive
      officers as a group (1)
              
              
              5.0000
              
              
              
              *
  ___________________
 *
Represents less than one percent.
 (1)
Includes shares owned by Mr. Swanson’s family members and trusts, which he
controls.
  ITEM
13. CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
  In
accordance with the Fund’s LLC Agreement, the Manager is entitled to an annual
management fee, equal to 2.5% of the total shareholder
capital.  During the years ended December 31, 2007 and 2006, the
Manager has revised its policy, thereby reducing the management fee calculation
as follows:
 
 Effective
      Date
                
                Management
      Fee CalculationAugust
      2, 2004, Inception
                
                2.5%
      of capital contributionsSeptember
      1, 2006
                
                2.5%
      of capital contributions, net of cumulative dry-hole
  costsJanuary
      1, 2007
                
                2.0%
      of capital contributions, net of cumulative dry-hole
  costsSeptember
      1, 2007
                
                1.0%
      of capital contributions, net of cumulative dry-hole
  costsOctober
      1, 2007
                
                Waived
 
 Management
fees paid for the years ended December 31, 2007 and 2006, $0.9 million and $1.9
million, respectively.  In addition, the Manager is also entitled to a
15% interest in the cash distributions.  For the years ended December
31, 2007 and 2006, the Manager was paid distributions totaling $0.6 million and
$0.8 million, respectively.
 
 Profits
and losses are allocated in accordance with the LLC Agreement. In general,
profits and losses in any year are allocated 85% to shareholders and 15% to the
Manager. The primary exception to this treatment is that all items of expense,
loss, deduction and credit attributable to the expenditure of shareholders’
capital contributions are allocated 99% to shareholders and 1% to the
Manager.
 
 From time
to time, short-term payables and receivables, which do not bear interest, arise
from transactions with affiliates in the ordinary course of
business.  At December 31, 2007, the Fund owed the Manager $6 thousand
relating to revenue allocations.  As of December 31, 2006 there were
no balances due to or from affiliates.
 
  ITEM
14. PRINCIPAL
ACCOUNTANT FEES AND SERVICES
  The
following table presents fees for services rendered by Deloitte & Touche
LLP.
  22
 Table of Contents
  Year
      ended December 31,2007
                
                
                2006(in
      thousands)Audit
      Fees (1)
                
                $
                125
                
                
                $
                125Tax
      fees (2)
                
                
                -
                
                
                
                24Total
                
                $
                125
                
                
                $
                149
 __________________
 (1)
                Fees
      for audit of annual financial statements, reviews of the related quarterly
      financial statements, and reviews of documents filed with the
      SEC.
  (2)
                Fees
      related to professional services for tax compliance, tax advice and tax
      planning.
  PART
IV
  ITEM
15. EXHIBITS
AND FINANCIAL STATEMENT SCHEDULES
  (a)
      (1)
              Financial
      Statements
  See
“Index to Financial Statements” set forth on page F-1.
  (a)
      (2)
              Financial
      Statement Schedules
  None.
  Exhibit
      No.
                
                Description10.1
                
                
                Participation
      Agreement between LLOG Exploration Offshore, Inc. and Ridgewood Energy
      Corporation as Manager for the LLOG properties dated November 1, 2006
      (incorporated by reference to Exhibit 10.1 to the Fund's Quarterly Report
      on Form 10-Q filed with the SEC on May 5, 2007).10.2
                
                
                Participation
      Agreement between Newfield Exploration Company and Ridgewood Energy
      Corporation as Manager for Eugene Island Block 364 dated February 8, 2006
      (incorporated by reference to Exhibit 10.2 to the Fund's Quarterly Report
      on Form 10-Q filed with the SEC on May 5, 2007).10.3
                
                
                Participation
      Agreement between Chevron Midcontinent, L.P. and Ridgewood Energy
      Corporation as Manager for West Cameron 57 dated September 5, 2007
      (incorporated by reference to Exhibit 10.1 to the Fund's Quarterly Report
      on Form 10-Q filed with the SEC on November 14, 2007).23.1
                
                
                Consent
      of Ryder Scott Company, L.P.31.1
                
                
                Certification
      of Robert E. Swanson, Chief Executive Officer, pursuant to Securities
      Exchange Act Rule 13a-14(a).31.2
                
                
                Certification
      of Kathleen P. McSherry, Chief Financial Officer, pursuant to Securities
      Exchange Act Rule 13a-14(a).32
                
                
                Certifications
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
      The Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief
      Executive Officer of the Company and Kathleen P. McSherry, Chief Financial
      Officer of the Company.
  
 23
  INDEX TO FINANCIAL
      STATEMENTS
                PAGEReport of Independent Registered Public Accounting
      Firm
                F-2Balance Sheets as of December 31, 2007 and
    2006
                F-3Statements of Operations for the years ended December 31, 2007
      and 2006
                F-4Statements of Changes in Members’ Capital for the years ended
      December 31, 2007 and 2006
                F-5Statements of Cash Flows for the years ended December 31, 2007
      and 2006
                F-6Notes to Financial Statements
                F-7Supplementary Financial Information - Information about Oil
      and Natural Gas Producing Activities - Unaudited
                F-14
 F-1
 Table of Contents
  REPORT OF INDEPENDENT
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, 2007 and 2006, the related statements of operations,
changes in members’ capital, and cash flows for the years ended December 31,
2007 and 2006.  These financial statements are the responsibility of the
Fund’s management.  Our responsibility is to express an opinion on these
financial statements based on our audits.
  We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  The Fund is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting.  Our audits included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Fund's internal control over
financial reporting.  Accordingly, we express no such opinion.  An
audit also includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation.  We believe that our audits
provide a reasonable basis for our opinion.
  In our
opinion, such financial statements present fairly, in all material respects, the
financial position of Ridgewood Energy M Fund, LLC as of December 31, 2007 and
2006, and the results of its operations and its cash flows for the years ended
December 31, 2007 and 2006, in conformity with accounting principles generally
accepted in the United States of America.
  /s/
Deloitte & Touche LLP
  March 31,
2008
 Parsippany,
New Jersey
 
   
  
 F-2
 Table of Contents
 
 RIDGEWOOD ENERGY M FUND,
LLC
 BALANCE
SHEETS
 (in
thousands, except share amounts)
   December
      31,2007
                
                
                2006ASSETSCurrent
      assets:Cash
      and cash equivalents
                
                $
                8,163
                
                
                $
                7,508Short-term
      investment in marketable securities
                
                
                5,075
                
                
                
                15,656Production
      receivable
                
                
                119
                
                
                
                493Other
      current assets
                
                
                99
                
                
                
                22Total
      current assets
                
                
                13,456
                
                
                
                23,679Salvage
      fund
                
                
                1,111
                
                
                
                1,060Oil
      and gas properties:Advances
      to operators for working interests and expenditures
                
                
                66
                
                
                
                -Proved
      properties
                
                
                15,033
                
                
                
                22,163Unproved
      properties
                
                
                7,357
                
                
                
                5,355Less:
      accumulated depletion and amortization
                
                
                (7,909
                )
                
                
                (4,100
                )Total
      oil and gas properties
                
                
                14,547
                
                
                
                23,418Total
      assets
                
                $
                29,114
                
                
                $
                48,157LIABILITIES
      AND MEMBERS' CAPITALCurrent
      liabilities:Due
      to operators
                
                $
                1,367
                
                
                $
                717Due
      to affiliates (Note 6)
                
                
                6
                
                
                
                -Accrued
      expenses payable
                
                
                131
                
                
                
                155Total
      current liabilities
                
                
                1,504
                
                
                
                872Asset
      retirement obligations
                
                
                476
                
                
                
                225Total
      liabilities
                
                
                1,980
                
                
                
                1,097Commitments
      and contingencies (Note 8)Members'
      capital:Manager:Distributions
                
                
                (1,402
                )
                
                
                (837
                )Retained earnings
                
                
                97
                
                
                
                105Manager's
      total
                
                
                (1,305
                )
                
                
                (732
                )Shareholders:Capital
      contributions (834 shares authorized;  535.6818 issued
      and
                  outstanding)
                
                
                78,887
                
                
                
                78,887Syndication
      costs
                
                
                (8,597
                )
                
                
                (8,597
                )Distributions
                
                
                (7,945
                )
                
                
                (4,742
                )Accumulated
      deficit
                
                
                (33,906
                )
                
                
                (17,756
                )Shareholders'
      total
                
                
                28,439
                
                
                
                47,792Total
      members' capital
                
                
                27,134
                
                
                
                47,060Total
      liabilities and members' capital
                
                $
                29,114
                
                
                $
                48,157
  The
accompanying notes are an integral part of these financial
statements.
 
 F-3
 Table of Contents
  RIDGEWOOD ENERGY M FUND,
LLC
 STATEMENTS
OF OPERATIONS
 (in
thousands, except share amounts)
   Year
      ended December 31,2007
                
                
                2006RevenueOil
      and gas revenue
                
                $
                3,389
                
                
                $
                7,780ExpensesDepletion
      and amortization
                
                
                1,086
                
                
                
                4,100Dry-hole
      costs
                
                
                705
                
                
                
                6,416Impairment
      of proved property
                
                
                16,282
                
                
                
                -Lease
      operating expenses
                
                
                754
                
                
                
                867Management
      fees to affiliate (Note 6)
                
                
                914
                
                
                
                1,854Other
      operating expenses
                
                
                87
                
                
                
                12General
      and administrative expenses
                
                
                652
                
                
                
                605Total
      expenses
                
                
                20,480
                
                
                
                13,854Loss
      from operations
                
                
                (17,091
                )
                
                
                (6,074
                )Other
      incomeInterest
      income
                
                
                933
                
                
                
                1,647Net
      loss
                
                $
                (16,158
                )
                
                $
                (4,427
                )Manager
      InterestNet
      (loss) income
                
                $
                (8
                )
                
                $
                583Shareholder
      InterestNet
      loss
                
                $
                (16,150
                )
                
                $
                (5,010
                )Net
      loss per share
                
                $
                (30,148
                )
                
                $
                (9,353
                )
  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 amounts)
  #
      of Shares
                
                
                Manager
                
                
                Shareholders
                
                
                TotalBalances,
      December 31, 2005
                
                
                535.6818
                
                
                $
                (478
                )
                
                $
                57,544
                
                
                $
                57,066Distributions
                
                
                -
                
                
                
                (837
                )
                
                
                (4,742
                )
                
                
                (5,579
                )Net
      income (loss)
                
                
                -
                
                
                
                583
                
                
                
                (5,010
                )
                
                
                (4,427
                )Balances,
      December 31, 2006
                
                
                535.6818
                
                
                
                (732
                )
                
                
                47,792
                
                
                
                47,060Distributions
                
                
                -
                
                
                
                (565
                )
                
                
                (3,203
                )
                
                
                (3,768
                )Net
      loss
                
                
                -
                
                
                
                (8
                )
                
                
                (16,150
                )
                
                
                (16,158
                )Balances,
      December 31, 2007
                
                
                535.6818
                
                
                $
                (1,305
                )
                
                $
                28,439
                
                
                $
                27,134
  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 31,2007
                  
                  
                  2006Cash
      flows from operating activitiesNet
      loss
                  
                  $
                  (16,158
                  )
                  
                  $
                  (4,427
                  )Adjustments
      to reconcile net loss to net cash
                    provided
      by operating activities:Depletion
      and amortization
                  
                  
                  1,086
                  
                  
                  
                  4,100Dry-hole
      costs
                  
                  
                  705
                  
                  
                  
                  6,416Impairment
      of proved property
                  
                  
                  16,282
                  
                  
                  
                  -Accretion
      expense
                  
                  
                  13
                  
                  
                  
                  8Interest
      earned on marketable securities
                  
                  
                  (384
                  )
                  
                  
                  (656
                  )Changes
      in assets and liabilities:Decrease
      (increase) in production receivable
                  
                  
                  374
                  
                  
                  
                  (493
                  )(Increase)
      decrease in other current assets
                  
                  
                  (74
                  )
                  
                  
                  3(Decrease)
      increase in due to operators
                  
                  
                  (101
                  )
                  
                  
                  114Increase
      in due to affiliates
                  
                  
                  6
                  
                  
                  
                  -(Decrease)
      increase in accrued expenses payable
                  
                  
                  (24
                  )
                  
                  
                  111Net
      cash provided by operating activities
                  
                  
                  1,725
                  
                  
                  
                  5,176Cash
      flows from investing activitiesPayments
      to operators for working interests and expenditures
                  
                  
                  (66
                  )
                  
                  
                  -Capital
      expenditures for oil and gas properties
                  
                  
                  (8,358
                  )
                  
                  
                  (21,732
                  )Proceeds
      from insurance receivable
                  
                  
                  208
                  
                  
                  
                  1,235Salvage
      fund investments
                  
                  
                  (51
                  )
                  
                  
                  (46
                  )Proceeds
      from the maturity of marketable securities
                  
                  
                  24,704
                  
                  
                  
                  15,346Investment
      in marketable securities
                  
                  
                  (13,739
                  )
                  
                  
                  (30,346
                  )Net
      cash provided by (used in) investing activities
                  
                  
                  2,698
                  
                  
                  
                  (35,543
                  )Cash
      flows from financing activitiesDistributions
      paid
                  
                  
                  (3,768
                  )
                  
                  
                  (5,579
                  )Net
      cash used in financing activities
                  
                  
                  (3,768
                  )
                  
                  
                  (5,579
                  )Net
      increase (decrease) in cash and cash equivalents
                  
                  
                  655
                  
                  
                  
                  (35,946
                  )Cash
      and cash equivalents, beginning of period
                  
                  
                  7,508
                  
                  
                  
                  43,454Cash
      and cash equivalents, end of period
                  
                  $
                  8,163
                  
                  
                  $
                  7,508Supplemental
      schedule of non-cash investing activitiesAdvances
      used for capital expenditures in oil and gas
                    properties
      reclassified to proved properties
                  
                  $
                  -
                  
                  
                  $
                  4,366
  The
accompanying notes are an integral part of these financial
statements.
 
 F-6
 Table of Contents
  RIDGEWOOD ENERGY M FUND,
LLC
 NOTES
TO FINANCIAL 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 as of September 7, 2004
by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders
of the Fund.  Although the date of formation is August 2, 2004, the
Fund did not begin operations until September 7, 2004 when it began its private
offering of shares of LLC member interest (the “Shares”). There were no business
activities prior to September 7, 2004.
 
 The Fund
was organized to acquire, drill, construct and develop oil and natural gas
properties located in the United States offshore waters of Texas, Louisiana, and
Alabama in the Gulf of Mexico.  The Fund has devoted most of its
efforts to raising capital and oil and natural gas exploration
activities.  The Fund began earning revenues in May 2006 from these
operations.
  The
Manager performs (or arranges for the performance of) the management,
administrative and advisory services required for Fund operations. Such services
include, without limitation, the administration of shareholder accounts,
shareholder relations and the preparation, review and dissemination of tax and
other financial information.  In addition, the Manager provides office
space, equipment and facilities and other services necessary for Fund
operations.  The Manager also engages and manages the contractual
relations with outside custodians, depositories, accountants, attorneys,
broker-dealers, corporate fiduciaries, insurers, banks and others as required
(Notes 2, 6 and 8).
  2.  Summary
of Significant Accounting Policies
  Use
of Estimates
 The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. On an ongoing basis, the Manager reviews its
estimates, including those related to amounts advanced to and billed by
operators, determination of proved reserves, impairments and asset retirement
obligations.  Actual results may differ from those
estimates.
  Cash
and Cash Equivalents
 All
highly liquid investments with maturities when purchased of three months or less
are considered as cash and cash equivalents. At times, bank deposits may be in
excess of federal insured limits. The Fund maintains bank deposits with
accredited financial institutions.  At December 31, 2007 and 2006,
bank balances exceeded federally insured limits by approximately $8.0 million
and $7.3 million, respectively.
  Investments
in Marketable Securities
 At times
the Fund may invest in United States Treasury Bills and Notes. These investments
are considered short-term when their maturities are greater than three months
and less than one year and long-term when their maturities are in excess of
twelve months.  The Fund currently has short-term investments that are
classified as held-to-maturity.  Held-to-maturity securities are those
investments that the Fund has the ability and intent to hold until maturity, and
are recorded at cost plus accrued income, adjusted for the amortization of
premiums and discounts, which approximate fair value.  At December 31,
2007, the Fund had short-term held-to-maturity investments, inclusive of the
salvage fund, totaling $6.2 million which matured in January and February
2008.
  Salvage
Fund
 Pursuant
to the Fund’s LLC Agreement, the Fund deposits in a separate interest-bearing
account, or a salvage fund, money to provide for dismantling production
platforms and facilities, plugging and abandoning the wells and removing the
platforms, facilities and wells after their useful lives, in accordance with
applicable federal and state laws and regulations.
  Interest
earned on the account will become part of the salvage fund; there are no legal
restrictions on withdrawals from the salvage fund.
 
 F-7
 Table of Contents
 
 Oil
and Natural Gas Properties
 Investments
in oil and natural gas properties are operated by unaffiliated entities (the
“Operators”) who are responsible for drilling, administering and producing
activities pursuant to the terms of the applicable Operating Agreements with
working interest owners. The Fund’s portion of exploration, drilling, operating
and capital equipment expenditures relating to the wells are advanced and billed
by Operators through authorization for expenditures.
  The
successful efforts method of accounting for oil and gas producing activities is
followed. Acquisition costs are capitalized when incurred. Other oil and natural
gas exploration costs, excluding the costs of drilling exploratory wells, are
charged to expense as incurred. The costs of drilling exploratory wells are
capitalized pending the determination of whether the wells have discovered
proved commercial reserves. If proved commercial reserves have not been found,
exploratory drilling costs are expensed to dry-hole expense. Costs to develop
proved reserves, including the costs of all development wells and related
facilities and equipment used in the production of natural crude oil and natural
gas, are capitalized. Expenditures for ongoing repairs and maintenance of
producing properties are expensed as incurred.
  Upon the
sale or retirement of a proved property, the cost and related accumulated
depletion and amortization will be eliminated from the property accounts, and
the resultant gain or loss is recognized. On the sale or retirement of an
unproved property, gain or loss on the sale is recognized. The Manager does not
currently intend to sell any of the Fund’s property interests.
  Capitalized
acquisition costs of producing oil and natural gas properties are depleted by
the unit-of-production method.
  As of
December 31, 2007 amounts recorded in due to operators totaling approximately
$1.4 million, related to capital expenditures for oil and natural gas
properties. The December 31, 2007 balance was paid during the first quarter of
2008.
  Advances
to Operators for Working Interests and Expenditures
 The
Fund’s acquisition of a working interest in a well or a project requires it to
make a payment to the seller for the Fund’s rights, title and interest. The Fund
is required to advance its share of estimated cash outlay for the succeeding
month’s operation. The Fund accounts for such payments as advances to Operators
for working interests and expenditures. As drilling costs are incurred, the
advances are transferred to unproved properties.
  Asset
Retirement Obligations
 For oil
and natural gas properties, there are obligations to perform removal and
remediation activities when the properties are retired. When a project reaches
drilling depth and is determined to be either proved or dry, an asset retirement
obligation is recorded. Plug and abandonment costs associated with unsuccessful
projects are expensed as dry-hole costs.  The following table presents
changes to the asset retirement obligations.
  2007
                
                
                2006(in
      thousands)Balance,
      January 1,
                
                $
                225
                
                
                $
                23Liabilities
      incurred
                
                
                291
                
                
                
                501Revision
      to prior estimate
                
                
                16
                
                
                
                -Liabilities
      settled
                
                
                (69
                )
                
                
                (307
                )Accretion
      expense
                
                
                13
                
                
                
                8Balance,
      December 31,
                
                $
                476
                
                
                $
                225
 
 As
indicated above, the Fund maintains a salvage fund to provide for the funding of
future asset retirement obligations.
 
 Syndication
Costs
 Direct
costs associated with offering the Fund’s Shares including professional fees,
selling expenses and administrative costs payable to the Manager, an affiliate
of the Manager and outside brokers are reflected as a reduction of shareholders’
capital.
 
 F-8
 Table of Contents
 Revenue
Recognition and Production Receivable
 Oil and
natural gas sales are recognized when delivery is made and production is
recorded by the Operator to the purchaser and title is transferred (i.e.,
production has been delivered to a pipeline or transport
vehicle).
  The
volume of oil and natural gas sold on the Fund’s behalf may differ from the
volume of oil and natural gas to which the Fund is entitled. The Fund will
account for such oil and natural gas production imbalances by the entitlements
method. Under the entitlements method, the Fund will recognize a receivable from
other working interest owners for volumes oversold by other working interest
owners, and a payable to other working interest owners for volumes oversold by
the Fund. As of December 31, 2007 and 2006, there were no material oil or
natural gas balancing arrangements between the Fund and other working interest
owners.
  Impairment
of Long-Lived Assets
 In
accordance with the provisions of Statement of Financial Accounting Standards
No. 144, “Accounting for the Impairment of Long-Lived Assets”, long-lived
assets, such as oil and natural gas properties, are evaluated when events or
changes in circumstances indicate the carrying value of such assets may not be
recoverable. The determination of whether impairment has occurred is made by
comparing the carrying values of long-lived assets to the estimated future
undiscounted cash flows attributable to the asset. The impairment loss
recognized is the excess of the carrying value over the future discounted cash
flows attributable to the asset or the estimated fair value of the asset.
 
 Eugene Island
364
 The Fund
has a 50% working interest in Eugene Island 364 operated by El Paso E&P
Company (“El Paso”).  The well produced for a short time in 2006 but
had been shut-in since August 2006 due to mechanical problems. While
independent petroleum engineering reports from Ryder Scott Company, L.P.
indicated that Eugene Island 364 does have proved reserves, the complex
geological and stratigraphic nature of the area posed an engineering challenge
to access the reserves.  During 2006 and the early part of 2007,
expenses of approximately $0.9 million were incurred related to work over
activities on this property.  Throughout 2007, the Fund and the
Operator conducted further seismic analysis and engineering studies and
determined that the estimated additional costs to sidetrack the well were
approximately $6.0 million.  However, based on the Fund’s internal
interpretation of the 3-D seismic data covering the property, completed in
December 2007, and its assessment of the associated drilling risk, the Fund has
concluded that the only way to access the reserves would be to drill a new well
at substantially higher costs than the originally planned
sidetrack.  As a result, the Fund concluded that it was no longer
economic to proceed with recovery efforts and the well was
abandoned.  During the fourth quarter of 2007, the decision to abandon
the property resulted in an $11.4 million impairment, inclusive of estimated
future plug and abandonment costs. The Fund maintains the rights to the lease
block through 2012.
 
 Eugene
Island 337
 During
2007, the Fund recorded an impairment of $4.9 million related to Eugene Island
337 lease block.  When the well began producing in November 2007, the
flow rate at production was lower than originally expected, as such, internal
engineering estimates of the proved reserves were prepared, and an impairment of
$2.9 million was recorded during the third quarter of 2007.  At year
end, reserves were received from third-party engineers, and those reserves were
lower than internal estimates.  An additional impairment was recorded
during the fourth quarter of 2007, in the amount of $2.0 million.  The
Fund has spent $6.1 million on this property.  The Fund has recorded
impairments totaling $4.9 million related to this property during the year ended
December 31, 2007.  No impairment  was recorded during the
year ended December 31, 2006.
 
 Under successful
efforts accounting, reserve estimates are used to calculate cash flows
as well as depletion rates.  Proved reserves and future net cash flows
are estimated using sales prices estimated to be in effect as of the date
of the reserve estimate calculation.  Oil and natural gas prices,
which have fluctuated widely in recent years, affect the future
revenues. Any estimates of natural gas and oil reserves and their values are
inherently uncertain, including many factors beyond the Fund’s
control.
 
 Reservoir
engineering is a subjective process of estimating underground accumulations of
natural gas and oil that cannot be measured in an exact manner. The reserve
estimates are based upon the quality of available data and engineering and
geological interpretation and judgment.  Revisions to estimated
reserves may result from actual production, results of future development and
exploration activities, prevailing oil and natural gas prices, operating costs
and other factors.  Revisions to estimated reserves could have a
material affect on balances recorded as proved properties.
 
 F-9
 Table of Contents
 Depletion
and Amortization
 Depletion
and amortization of the cost of proved oil and natural gas properties are
calculated using the units-of-production method.  Proved developed
reserves are used as the base for depleting the cost of successful exploratory
drilling and development costs.  The sum of proved developed and
proved undeveloped reserves is used as the base for depleting (or amortizing)
leasehold acquisition costs, the costs to acquire proved properties and platform
and pipeline costs.
 
 Income
Taxes
 No
provision is made for income taxes in the financial statements.  The
Fund is a limited liability company, and as such the Fund’s income or loss is
passed through and included in the tax returns of the Fund’s
shareholders.
 
 Income
and Expense Allocation
 Profits
and losses are allocated 85% to shareholders in proportion to their relative
capital contributions and 15% to the Manager, except for items of expense, loss,
deduction and credit that are attributable to the expenditure of shareholders’
capital contributions, which are allocated 99% to shareholders and 1% to the
Manager.
  3.  Recent
Accounting Standards
  In
February 2007, the Financial Accounting Standards Board (the “FASB”) issued SFAS
No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”
(“SFAS No. 159”), which permits entities to measure many financial instruments
and certain other items at fair value that are not currently required to be
measured at fair value. An entity would report unrealized gains and losses on
items for which the fair value option has been elected in earnings at each
subsequent reporting date. The objective is to improve financial reporting by
providing entities with the opportunity to mitigate volatility in reported
earnings caused by measuring related assets and liabilities differently without
having to apply complex hedge accounting provisions. The decision about whether
to elect the fair value option is applied instrument by instrument, with a few
exceptions; the decision is irrevocable; and it is applied only to entire
instruments and not to portions of instruments.  The statement
requires disclosures that facilitate comparisons (a) between entities that
choose different measurement attributes for similar assets and liabilities and
(b) between assets and liabilities in the financial statements of an entity that
selects different measurement attributes for similar assets and liabilities.
SFAS No. 159 is effective for financial statements issued for fiscal years
beginning after November 15, 2007.  The adoption of SFAS No. 159 will
not have a material impact on its financials.  The Fund did not elect
to measure existing assets and liabilities at fair value on the date of
adoption.
  In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS
No.157”), which applies under most other accounting pronouncements that require
or permit fair value measurements. SFAS No. 157 provides a common definition of
fair value as the price that would be received to sell an asset or paid to
transfer a liability in a transaction between market participants. The new
standard also provides guidance on the methods used to measure fair value and
requires expanded disclosures related to fair value
measurements.  SFAS No. 157 had originally been effective for
financial statements issued for fiscal years beginning after November 15, 2007,
however the FASB has agreed on a one year deferral for all nonfinancial assets
and liabilities. The Fund believes that this guidance will not have a material
impact on the financial statements.
  4.  Unproved
Properties - Capitalized Exploratory Well Costs
  Leasehold
acquisition and exploratory drilling costs are capitalized pending determination
of whether the well has found proved reserves.  Unproved properties
are assessed on a quarterly basis by evaluating and monitoring if sufficient
progress is made on accessing the reserves.    The Fund had
one property, Vermilion 344, with capitalized costs greater than one
year.  Capitalized costs related to this project at December 31, 2007
and 2006 were $1.1 million and $0.2 million, respectively.  This
project has been deemed a success, and production facilities are being
completed, with production expected during the second quarter of 2008. At
December 31, 2006, the Fund had no capitalized exploratory well costs greater
than one year.  The following table reflects the net changes in
unproved properties.
 
 F-10
 Table of Contents
 
 2007
                
                
                2006(in
      thousands)Balance,
      January 1,
                
                $
                5,355
                
                
                $
                465Additions
      to capitalized exploratory well costs pending the
                  determination
      of proved reserves
                
                
                7,960
                
                
                
                5,162Reclassification
      to proved properties based on the
                  determination
      of proved reserves
                
                
                (5,958
                )
                
                
                -Capitalized
      exploratory well costs charged to dry-hole costs
                
                
                -
                
                
                
                (272
                )Balance,
      December 31,
                
                $
                7,357
                
                
                $
                5,355
  Capitalized
costs are expensed as dry-hole costs in the event that reserves are not found or
are not in sufficient quantities to complete the well and develop the
field.  Dry-hole costs are detailed in the table below.
 
 Year
      ended December 31,Lease
      Block
                  
                  2007
                  
                  
                  2006(in
      thousands)Ship
      Shoal 81
                  
                  $
                  615
                  
                  
                  $
                  -Main
      Pass 155
                  
                  
                  96
                  
                  
                  
                  77East
      Breaks 157
                  
                  
                  -
                  
                  
                  
                  4,632Eugene
      Island 357
                  
                  
                  (6
                  )
                  
                  
                  1,707$
                  705
                  
                  
                  $
                  6,416
  5.  Distributions
  Distributions
to shareholders are allocated in proportion to the number of Shares
held.
 
 The
Manager will determine whether available cash from operations, as defined in the
Fund's LLC Agreement, is to be distributed. Such distributions are allocated 85%
to the shareholders and 15% to the Manager, as defined in the Fund's LLC
Agreement.
 
 Available
cash from dispositions, as defined in the Fund's LLC Agreement, is paid 99% to
shareholders and 1% to the Manager until the shareholders have received total
distributions equal to their capital contributions. After shareholders have
received distributions equal to their capital contributions, 85% of available
cash from dispositions will be distributed to shareholders and 15% to the
Manager.
 
 During
the years ended December 31, 2007 and 2006, the Fund made distributions of $3.2
million and $4.7 million, respectively to shareholders and $0.6 million and $0.8
million, respectively to the Manager.
  6.  Related
Parties
  In
accordance with the Fund’s LLC Agreement, the Manager is entitled to an annual
management fee, equal to 2.5% of the total shareholder
capital.  During the years ended December 31, 2007 and 2006, the
Manager has revised its policy, thereby reducing the management fee calculation
as follows:
 
 F-11
 Table of Contents
 
 Effective
      Date
                
                Management
      Fee CalculationAugust
      2, 2004, Inception
                
                2.5%
      of capital contributionsSeptember
      1, 2006
                
                2.5%
      of capital contributions, net of cumulative dry-hole
  costsJanuary
      1, 2007
                
                2.0%
      of capital contributions, net of cumulative dry-hole
  costsSeptember
      1, 2007
                
                1.0%
      of capital contributions, net of cumulative dry-hole
  costsOctober
      1, 2007
                
                Waived
 
 Management
fees paid for the years ended December 31, 2007 and 2006, $0.9 million and $1.9
million, respectively.  In addition, the Manager is also entitled to a
15% interest in the cash distributions.  For the years ended December
31, 2007 and 2006, the Manager was paid distributions totaling $0.6 million and
$0.8 million, respectively.
 
 Profits
and losses are allocated in accordance with the LLC Agreement. In general,
profits and losses in any year are allocated 85% to shareholders and 15% to the
Manager. The primary exception to this treatment is that all items of expense,
loss, deduction and credit attributable to the expenditure of shareholders’
capital contributions are allocated 99% to shareholders and 1% to the
Manager.
 
 From time
to time, short-term payables and receivables, which do not bear interest, arise
from transactions with affiliates in the ordinary course of
business.  At December 31, 2007, the Fund owed the Manager $6 thousand
relating to revenue allocations.  As of December 31, 2006 there were
no balances due to or from affiliates.
 
 None of
the compensation to be received by the Manager has been derived as a result of
arm’s length negotiations.
 
 The Fund
has working interest ownership in certain projects to acquire and develop oil
and natural gas projects with other entities that are likewise managed by the
Manager.
  7.  Fair
Value of Financial Instruments
  At
December 31, 2007 and 2006, the carrying values of cash and cash equivalents,
production receivable, short-term investments in marketable securities, salvage
fund, and accrued expenses approximate fair value.
  8.  Commitments
and Contingencies
  Capital
Commitments
 The Fund
has entered into multiple offshore operating agreements for the drilling and
development of its investment properties. The estimated capital expenditures
associated with these agreements vary depending on the stage of development on a
property-by-property basis. As of December 31, 2007, the Fund had committed to
spend an additional $1.5 million relating to the completion of a number of its
wells.  No other firm commitments have been entered, however it is
expected that the Fund will invest all of its unspent capital on either current
or future projects.
  Environmental
Considerations
 The
exploration for and development of oil and natural gas involves the extraction,
production and transportation of materials which, under certain conditions, can
be hazardous or cause environmental pollution problems.  The Manager
and the Operators are continually taking action they believe appropriate to
satisfy applicable federal, state and local environmental regulations and do not
currently anticipate that compliance with federal, state and local environmental
regulations will have a material adverse effect upon capital expenditures,
results of operations or the competitive position of the Fund in the oil and
natural gas industry.  However, due to the significant public and
governmental interest in environmental matters related to those activities, the
Manager cannot predict the effects of possible future legislation, rule changes,
or governmental or private claims.  At December 31, 2007 and 2006,
there were no known environmental issues that required the Fund to record a
liability.
  Insurance
Coverage
 The Fund
is subject to all risks inherent in the exploration for and development of oil
and natural gas. Insurance coverage as is customary for entities engaged in
similar operations is maintained, but losses may occur from uninsurable risks or
amounts in excess of existing insurance coverage. The occurrence of an event
which is not insured or not fully insured could have an adverse impact upon
earnings and financial position.  Moreover, insurance is obtained as a
package covering all of the Manager’s investment programs and is allocated to
the Fund. Claims made by other such programs can reduce or eliminate insurance
for the Fund.
 
 F-12
 Table of Contents
  During
March 2005 while drilling the West Cameron 77 # 2 well, BHP Billiton Petroleum
(“BHP”), the operator, encountered mechanical problems. BHP was able to
successfully shut-in the well and subsequently completed sidetrack operations
such that the well was preserved. In accordance with the Fund's control of well
insurance, the Fund filed a claim for the recovery of costs related to the
incident. The Fund received insurance proceeds of $0.2 million and $1.2 million
for the years ended December 31, 2007 and 2006, respectively.
       
  
 F-13
 Table of Contents
 
 Ridgewood Energy M Fund,
LLC
 Supplementary
Financial Information
 Information
about Oil and Natural Gas Producing Activities - Unaudited
 
 In
accordance with Statement of Financial Accounting Standards No. 69, “Disclosures
about Oil and Gas Producing Activities,” this section provides supplemental
information on oil and natural gas exploration and producing activities of the
Fund.
  The Fund
is engaged solely in oil and natural gas activities, all of which are located in
the United States offshore waters of Louisiana in the Gulf of
Mexico.
  Table
I - Capitalized Costs Related to Oil and Gas Producing Activities
 
 December
      31,2007
                
                
                2006(in
      thousands)Proved
      oil and gas properties
                
                $
                15,033
                
                
                $
                22,163Unproved
      oil and gas properties
                
                
                7,357
                
                
                
                5,355Advances
      to operator for working interests and expenditures
                
                
                66
                
                
                
                -Total
      oil and gas properties
                
                
                22,456
                
                
                
                27,518Accumulated
      depletion and amortization
                
                
                (7,909
                )
                
                
                (4,100
                )Oil
      and gas properties, net
                
                $
                14,547
                
                
                $
                23,418
 
 Table
II - Costs Incurred in Exploration, Property Acquisitions and
Development
 
 Year
      ended December 31,2007
                
                
                2006(in
      thousands)Exploratory
      drilling costs - capitalized
                
                $
                8,513
                
                
                $
                20,273Exploratory
      drilling costs - expensed
                
                
                705
                
                
                
                1,778Geological
      costs
                
                
                67
                
                
                
                5$
                9,285
                
                
                $
                22,056
  
 F-14
 Table of Contents
 
 Table
III - Reserve Quantity Information
 Oil and
gas reserves of the Fund have been estimated by an independent petroleum
engineer, Ryder Scott Company, L.P., for the years ended December 31, 2007 and
2006.  The reserve estimates for December 31, 2007 and 2006 were based
on estimated future reserves as of December 31, 2007 and September 30, 2006,
respectively provided by Ryder Scott Company, L.P.  These reserve
disclosures have been prepared in compliance with the Securities and Exchange
Commission rules.
 
 Proved
reserves are classified as either developed or undeveloped.  Proved
developed reserves are the quantities expected to be recovered through existing
wells with existing equipment and operating methods.
  December
      31, 2007
                    
                    
                    December
      31, 2006United
      States
                    
                    
                    United
      StatesOil
      (BBLS)
                    
                    
                    Gas
      (MCF)
                    
                    
                    Oil
      (BBLS)
                    
                    
                    Gas
      (MCF)Proved
      developed and undeveloped reserves:Beginning
      of year
                    
                    
                    597,253
                    
                    
                    
                    8,080,273
                    
                    
                    
                    38,890
                    
                    
                    
                    4,351,458Discoveries
                    
                    
                    32
                    
                    
                    
                    185,493
                    
                    
                    
                    542,991
                    
                    
                    
                    4,524,929Revisions
      of previous estimates
                    
                    
                    (555,720
                    )
                    
                    
                    (5,136,496
                    )
                    
                    
                    44,136
                    
                    
                    
                    94,226Production
                    
                    
                    (4,866
                    )
                    
                    
                    (410,870
                    )
                    
                    
                    (28,764
                    )
                    
                    
                    (890,340
                    )End
      of year
                    
                    
                    36,699
                    
                    
                    
                    2,718,400
                    
                    
                    
                    597,253
                    
                    
                    
                    8,080,273Proved
      developed reserves:Beginning
      of year
                    
                    
                    42,895
                    
                    
                    
                    2,797,567
                    
                    
                    
                    -
                    
                    
                    
                    -Discoveries
                    
                    
                    32
                    
                    
                    
                    185,493
                    
                    
                    
                    71,659
                    
                    
                    
                    3,687,907Revisions
      of previous estimates
                    
                    
                    (11,213
                    )
                    
                    
                    (611,790
                    )
                    
                    
                    -
                    
                    
                    
                    -Production
                    
                    
                    (4,866
                    )
                    
                    
                    (410,870
                    )
                    
                    
                    (28,764
                    )
                    
                    
                    (890,340
                    )End
      of year
                    
                    
                    26,848
                    
                    
                    
                    1,960,400
                    
                    
                    
                    42,895
                    
                    
                    
                    2,797,567
 
 Due to
the inherent uncertainties and the limited nature of recovery data, estimates of
reserve information are subject to change as additional information becomes
available.
 
 Table
IV - Standardized Measure of Discounted Future Net Cash Flows Related to Proved
Oil and Gas Reserves
 
 Summarized
in the following table is information for the Fund with respect to the
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves.  Future cash inflows are computed by applying
year-end prices of oil and gas relating to the Fund's proved reserves to the
year-end quantities of those reserves.  Future production,
development, site restoration and abandonment costs are derived based on current
costs assuming continuation of existing economic conditions.
  December
      31,2007
                  
                  
                  2006(in
      thousands)Future
      estimated revenues
                  
                  $
                  23,691
                  
                  
                  $
                  82,054Future
      estimated production costs
                  
                  
                  (1,860
                  )
                  
                  
                  (2,670
                  )Future
      estimated development costs
                  
                  
                  (2,944
                  )
                  
                  
                  (7,217
                  )Future
      net cash flows
                  
                  
                  18,887
                  
                  
                  
                  72,16710%
      annual discount for estimated timing of cash flows
                  
                  
                  (3,338
                  )
                  
                  
                  (22,509
                  )Standardized
      measure of discounted future estimated net cash flows
                  
                  $
                  15,549
                  
                  
                  $
                  49,658
  
 F-15
 Table of Contents
  Table
V - Changes in the Standardized Measure of Discounted Future Net Cash Flows
Related to Proved Oil and Gas Reserves
 
 The
changes in present values between years, which can be significant, reflect
changes in estimated proved reserve quantities and prices and assumptions used
in forecasting production volumes and costs.
 
 Year
      ended December 31,2007
                
                
                2006Standardized
      measure beginning of the year
                
                $
                49,658
                
                
                $
                27,140Sales
      of oil and gas production, net of production costs
                
                
                (2,635
                )
                
                
                (6,913
                )Net
      changes in prices and production costs
                
                
                7,453
                
                
                
                (12,656
                )Extensions,
      discoveries, and improved recovery and techniques, less related
      costs
                
                
                1,022
                
                
                
                34,819Revision
      of development costs
                
                
                4,273
                
                
                
                1,966Revisions
      of previous reserve quantities estimate
                
                
                (62,926
                )
                
                
                911Accretion
      of discount
                
                
                1,323
                
                
                
                2,878Other
      and timing
                
                
                17,381
                
                
                
                1,513Standardized
      measure end of the year
                
                $
                15,549
                
                
                $
                49,658
 
 It is
necessary to emphasize that the data presented should not be viewed as
representing the expected cash flow from, or current value of, existing proved
reserves as the computations are based on a large number of
estimates.  Reserve quantities cannot be measured with precision and
their estimation requires many judgmental determinations and frequent
revisions.  The required projection of production and related
expenditures over time requires further estimates with respect to pipeline
availability, rates and governmental control.  Actual future prices
and costs are likely to be substantially different from the current price and
cost estimates utilized in the computation of reported amounts.  Any
analysis or evaluation of the reported amounts should give specific recognition
to the computational methods utilized and the limitation inherent
therein.
  
 F-16
 Table of Contents
  SIGNATURES
  Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant has
duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
  RIDGEWOOD
      ENERGY M FUND, LLCDate:
      March 31, 2008
              By:
              /s/
      ROBERT E. SWANSONRobert
      E. SwansonChief
      Executive Officer(Principal
      Executive Officer)
  Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
  Signature
              Capacity
              Date/s/
      ROBERT E. SWANSON
              Chief
      Executive Officer (Principal Executive Officer)
              Date:
      March 31, 2008Robert
      E. Swanson/s/
      KATHLEEN P. MCSHERRY
              Executive
      Vice President and Chief Financial Officer (Principal Accounting
      Officer)
              Date:
      March 31, 2008Kathleen
      P. McSherry/s/
      ROBERT E. SWANSON
              Chief
      Executive Officer of the Manager
              Date:
      March 31, 2008Robert
      E. Swanson