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. 000-51267





RIDGEWOOD
ENERGY L FUND, LLC


(Exact
name of registrant as specified in its charter)





Delaware
              (State
      or other jurisdiction of
              incorporation
      or organization)
            11-3719724
              (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 350.1081 Shares
outstanding.







Table of Contents




RIDGEWOOD
ENERGY L FUND, LLC


2007
ANNUAL REPORT ON FORM 10-K


TABLE OF CONTENTS




PAGEPART
      IITEM 1
            BUSINESS
            4ITEM 1A
            RISK FACTORS
            11ITEM 1B
            UNRESOLVED STAFF COMMENTS
            11ITEM 2
            PROPERTIES
            11ITEM 3
            LEGAL PROCEEDINGS
            11ITEM 4
            SUBMISSION OF MATTERS TO A VOTE OF SECURITY
      HOLDERS
            11PART
      IIITEM 5
            MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER
      MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
            12ITEM 6
            SELECTED FINANCIAL DATA
            13ITEM 7
            MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
      RESULTS OF OPERATIONS
            13ITEM 7A
            QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
      RISK
            18ITEM 8
            FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
            18ITEM 9
            CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
      FINANCIAL DISCLOSURE
            18ITEM 9A
            CONTROLS AND PROCEDURES
            18ITEM 9B
            OTHER INFORMATION
            19PART
      IIIITEM 10
            DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
      GOVERNANCE
            19ITEM 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
            22


2
 Table of Contents




FORWARD-LOOKING
STATEMENTS




Certain
statements in this Annual Report on Form 10-K (“Annual Report”) of the
Ridgewood Energy L 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 formed on May 27, 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 July 6, 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 September 30, 2004. The Fund raised approximately $51.4 million.
After payment of approximately $7.8 million in offering fees, commissions and
investment fees, the Fund had approximately $43.6 million for investments and
operating expenses. As of March 31, 2008, the Fund had 555
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, which was equal to 2.5% of the total shareholder
capital.  Beginning September 1, 2006, the Manager changed its policy
regarding the annual management fee whereby the management fee was equal to 2.5%
of the total shareholder capital contributions, net of cumulative dry-hole costs
incurred by the Fund.  On September 1, 2007, the Manager elected to
forgo its annual management fee for the remaining life of the
Fund.  Management fees for the years ended December 31, 2007 and 2006,
were $0.6 million and $1.1 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 $0.2 million and $1.4 million, respectively, of cash
distributions.




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.


4
 Table of Contents




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.




Working
              
              
              
              Gulf
      of
              
              Target
                Depth
              
              Total
      Spent ThroughLease
      Block
              
              Interest
              
              Operator
              
              Mexico
              
              (Feet)
              
              December
      31, 2007
              
              StatusSuccessful
      Projects
              
              
              
              
              
              
              
              
              
              
              (in
      thousands)South
      Marsh Island 111
              
              
              7.50
              %
              LLOG
              
              LA
              
              
              18,000
              
              
              $
              881
              
              Successful
      - production expected 2nd quarter 2008Vermilion
      344
              
              
              7.50
              %
              LLOG
              
              LA
              
              
              8,900
              
              
              $
              910
              
              Successful
      - production expected 2nd quarter 2008West
      Delta 68
              
              
              7.50
              %
              LLOG
              
              LA
              
              
              14,000
              
              
              $
              1,373
              
              Successful
      - production expected 2nd quarter 2008West
      Delta 67
              
              
              7.50
              %
              LLOG
              
              LA
              
              
              14,000
              
              
              $
              573
              
              Successful
      - production expected 2nd quarter 2008South
      Timbalier 77
              
              
              20.00
              %
              ATP
              
              LA
              
              
              18,500
              
              
              $
              9,089
              
              Successful
      - production began
                August
      2005Eugene
      Island 337 A-10
              
              
              13.33
              %
              Devon
              
              LA
              
              
              16,300
              
              
              $
              4,048
              *
              Successful
      - production began
                November
      2007Main
      Pass 275 A-3
              
              
              10.00
              %
              McMoRan
              
              LA
              
              
              11,200
              
              
              $
              1,933
              
              Successful
      - production began April 2007Dry
      holes (a)Ship
      Shoal 81
              
              
              7.50
              %
              LLOG
              
              LA
              
              
              N/A
              
              
              $
              527
              
              Dry
      Hole - October 2007East
      Break 157
              
              
              7.00
              %
              Woodside
              
              TX
              
              
              N/A
              
              
              $
              1,801
              
              Dry
      Hole - March 2006West
      Cameron 78/95
              
              
              20.00
              %
              El
      Paso
              
              LA
              
              
              N/A
              
              
              $
              2,895
              
              Dry
      Hole - July 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.*
              Excludes
      impact of cumulative impairments of $3.3 million.




5
 Table of Contents




Projects





Successful
Project


LLOG
Projects


In
October 2006, the Fund acquired a 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 decided not to
participate in the Galveston 248 project with LLOG which was 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 owns a 7.5% working interest in Ship Shoal
81 and has spent $0.5 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 successes, are undergoing
completion, and production is expected during the second quarter of
2008.  The total budget for these projects is approximately $7.2
million, of which $3.7 million has been spent at December 31, 2007.





Eugene Island
337


The
Fund’s 13.33% 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 $2.0 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 $1.3 million.  The
Fund has spent $4.0 million on this property.  The Fund has recorded
impairment costs totaling $3.3 million related to this property during the year
ended December 31, 2007.  No impairment costs had been recorded during
the year ended December 31, 2006.





Main Pass
275


In late
2006, the Fund acquired a 10% interest in the Main Pass 275 project from
Newfield, Inc. (“Newfield”).  In August 2007, Newfield sold its
interest in this property to McMoRan Exploration Co. (“McMoRan”).  At
that time, McMoRan assumed Newfield’s responsibilities as the operator of this
property.  The well was declared a commercial success in February 2007
and completed in March 2007.  An existing production platform, gas
processing equipment and pipeline expedited the onset of production, which
began  in late April 2007.  The Fund has spent $1.9 million
on this property.





South
Timbalier 77


In 2004,
the Fund acquired from Millennium Offshore Group (“MOGI”) a 20% working interest
in the South Timbalier 77 (“ST77”) field of which two wells were drilled, wells
#4 and #5.  MOGI sold its interest to ATP Oil and Gas Corporation
(“ATP”), who is the current operator.    Production from the
#4 well began to decline at the end of 2006.  Although production
increased for the first four months of 2007, it began to decline again in the
later half of the second quarter and stopped producing in June
2007.  ATP has indicated that the cause for the decline in production
is a build-up of minerals on the walls of the production tubing that is
preventing the flow of gas.  A workover was performed during the first
quarter of 2008, and production has resumed.  ST77 well #5 ceased
production after depleting the first two intermediate depth reservoirs at 13,000
feet.  An attempt to recomplete well #5 was unsuccessful and the Fund
does not anticipate any future revenues from well #5.





As of
December 31, 2007 total unamortized costs related to the ST77 project are
approximately $0.2 million.  The Fund anticipates to fully recover
these costs, as well as the costs of the well #4 workover based upon current
reserve estimates and prevailing market prices.  It is expected that
the ST77 field will be fully depleted in 2008.





Dry
Holes





West
Cameron 78/95


The Fund
acquired a 20% working interest from the Operator, El Paso Production Company
(“El Paso”). The well began drilling on April 21, 2006.  Drilling went
according to plan until the well reached a depth of 10,781 feet on May 17, 2006
when the drill string became stuck.  The smaller drill pipe was
recovered and the well was sidetracked (re-drilled) at a depth of 4,880
feet.   Drilling continued to 14,500 feet, at which point the
well was determined to be a dry-hole.  On July 6, 2006 the decision
was made to plug and abandon the well.  Dry-hole costs including plug
and abandonment expenses incurred by the Fund for the year ended December 31,
2006, totaled $2.9 million, net of insurance recovery amounts.  The
Fund recorded casualty losses totaling $1.2 million related to the deductible,
changes in estimates to, and the ultimate settlement of this insurance
claim. The Fund received proceeds of $1.0 million for the settlement of
this claim during the fourth quarter of 2007, and the additional $0.5 million in
2008 as a transfer from the Manager.





6
 Table of Contents




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.




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.


7
 Table of Contents




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 ATP, Devon, LLOG and McMoRan.




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




Insurance




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




Salvage
Fund




As to
projects in which the Fund owns a working interest, the Fund deposits in a
separate interest-bearing account, or a salvage fund, which is in the nature of
a sinking fund, money to help provide for the Fund’s proportionate share of the
cost of dismantling production platforms and facilities, plugging and abandoning
the projects, and removing the platforms, facilities and projects in respect of
each of such projects after their useful life, in accordance with applicable
federal and state laws and regulations.  There is no assurance that the
salvage fund will have sufficient assets to meet these requirements and any
unfunded expenses, and the Fund may be liable for such expenses. The Fund
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.




8
 Table of Contents




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.




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.




9
 Table of Contents




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.




Sales and Transportation of Natural
Gas/Oil




The Fund
sells the Fund’s proportionate share of oil and natural gas to the market and
receives market prices from such sales. These sales are not currently subject to
regulation by any federal or state agency. However, in order for the Fund to
make such sales the Fund is dependent upon unaffiliated pipeline companies whose
rates, terms and conditions of transport are subject to regulation by the
Federal Energy Regulatory Commission (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.




10
 Table of Contents




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.




Other
Environmental Laws




In
addition to the above, the Fund’s operations may be subject to the Resource
Conservation and Recovery Act, which regulates the generation,
transportation, treatment, storage, disposal and cleanup of certain hazardous
wastes, as well as the Comprehensive
Environmental Response, Compensation and Liability 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.


11
 Table of Contents




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 555 shareholders of record of
the Fund.  The Fund may make distributions from available cash from
operations as defined in the LLC Agreement.  As of the years ended
December 31, 2007 and 2006, $1.0 million and $7.7 million, respectively, have
been paid to the Fund shareholders, and $0.2 million and $1.4 million,
respectively, to the Manager.




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.




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.


12
 Table of Contents




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.




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.




13
 Table of Contents




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 revenues to change. Estimates of
proved reserves are key components of the Fund’s most significant financial
estimates involving its rate for recording depreciation, depletion and
amortization.




Unproved
Properties




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




Asset
Retirement Obligations




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




Impairment
of Long-Lived Assets




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




In the
case of oil and natural gas fields, the present value of future net cash flows
is based on management’s best estimate of future prices, which is determined
with reference to recent historical prices and published forward prices, applied
to projected production volumes of individual fields and discounted at a rate
commensurate with the risks involved. The projected production volumes represent
reserves, including probable reserves, expected to be produced based on a
stipulated amount of capital expenditures. The production volumes, prices and
timing of production are consistent with internal projections and other
externally reported information.




14
 Table of Contents




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.




Year
      ended December 31,2007
              
              
              2006(in
      thousands)RevenueOil
      and gas revenue
              
              $
              2,109
              
              
              $
              5,522ExpensesDepletion
      and amortization
              
              
              771
              
              
              
              4,202Dry-hole
      costs
              
              
              525
              
              
              
              4,863Impairment
      of proved property
              
              
              3,255
              
              
              
              -Casualty
      loss
              
              
              1,023
              
              
              
              133Lease
      operating expenses
              
              
              332
              
              
              
              535Management
      fees to affiliate
              
              
              612
              
              
              
              1,149Other
      operating expenses
              
              
              37
              
              
              
              20General
      and administrative expenses
              
              
              432
              
              
              
              280Total
      expenses
              
              
              6,987
              
              
              
              11,182Loss
      from operations
              
              
              (4,878
              )
              
              
              (5,660
              )Other
      IncomeInterest
      income
              
              
              502
              
              
              
              860Net
      loss
              
              $
              (4,376
              )
              
              $
              (4,800
              )




Year
ended December 31, 2007 compared to year ended December 31,
2006




Oil and Gas
Revenue.Oil
and gas revenue for the year ended December 31, 2007 was approximately $2.1
million, a decrease of  $3.4 million  from  the
year ended December 31, 2006.  The decrease in oil and gas revenue is
due to a decline in the production from the ST77 property.  The ST77
wells had production during the first half of 2007 but did not produce in the
second half of 2007 as a result of mechanical problems.  See Item 1.
“Business” for further discussion.  Declining production volumes for the
ST77 wells were partially offset by production of the Main Pass 275 well, which
began producing in April 2007, and Eugene Island 337, which began producing
in November 2007.





Natural
gas prices for the year ended December 31, 2007 averaged $8.10 per thousand
cubic feet (“mcf”), a slight increase compared to the average rate of $7.67
per mcf, for the year ended December 31, 2006.  Oil prices for the
years ended December 31, 2007 and 2006 averaged $66 per
barrel.





Depletion and
Amortization.  Depletion and amortization for the years ended
December 31, 2007 and 2006 were $0.8 million and $4.2 million,
respectively.  The decrease is the result of decreased production
volumes for the ST77 wells in 2007 compared to 2006, partially offset by the
commencement of production of the Main Pass 275 and Eugene Island 337 wells, in
April 2007 and November 2007, respectively.




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.


15
 Table of Contents


Year
      ended December 31,Lease
      Block
              
              2007
              
              
              2006(in
      thousands)Ship
      Shoal 81
              
              $
              527
              
              
              $
              -Main
      Pass 155
              
              
              25
              
              
              
              30East
      Breaks 157
              
              
              8
              
              
              
              1,793West
      Cameron 103
              
              
              -
              
              
              
              3East
      Cameron 48
              
              
              -
              
              
              
              107West
      Cameron 78/95
              
              
              (35
              )
              
              
              2,930$
              525
              
              
              $
              4,863





Impairment of
Proved Property.Impairment of proved properties for the year
ended December 31, 2007 was $3.3 million relating to the Fund’s investment in
the Eugene Island 337 lease block.  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.





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 effect on balances recorded as proved properties. In accordance with
Statement of Financial Accounting Standards No. 144 "Accounting for the
Impairment of Long-Lived Assets”, the Fund recorded an impairment loss based
upon the current reserve estimates.





Casualty
Loss.For the years ended December 31, 2007 and 2006 the Fund
recorded a casualty loss of $1.0 million and $0.1 million, respectively, related
to the Fund’s portion of the insurance deductible for the West Cameron 78/95
damage claim.   See Item 1. “Business” for further discussion of
the events giving rise to the loss.





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 $0.3 million and
$0.5 million, respectively.  The decrease is a result of the shut-in
ST 77 during 2007.  These decreases were slightly offset by lease
operating expenses for the Main Pass 275 and Eugene Island 337 wells, which both
began production in 2007.





Management
Fee.Management fees
for the years ended December 31, 2007 and 2006 were $0.6 million and $1.1
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 $0.5 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. Additionally,
effective September 1, 2007, the Manager has elected to waive the management fee
for the remaining life of the Fund.





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
            
            $
            257
            
            
            $
            119Accounting
      and legal fees
            
            
            170
            
            
            $
            158Other
      general and administrative expenses
            
            
            5
            
            
            
            3$
            432
            
            
            $
            280


16
 Table of Contents




Accounting
and legal fees represent annual audit and tax preparation fees, quarterly
reviews and filing fees of the Fund.  Insurance expense represents
premiums related to well control insurance, which increases as drilling activity
increases, and directors and officers liability policy, which is allocated by
the Manager to the Fund based on capital raised by the Fund to total capital
raised by all oil and natural gas funds managed by the Manager.  The
increase in the insurance expenses relates to the timing of the drilling of the
Fund’s wells.




Other
Income.  Interest income for the years ended December 31, 2007
and 2006 was $0.5 million and $0.9 million, respectively.  The
decrease was a result of declining cash balances in 2007, which was used to fund
investments in properties, 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
$1.3 million, primarily related to cash receipts from oil and natural gas
production of $2.1 million, interest received of $0.5 million, favorable working
capital of $0.1 million, offset by payments for
management fees of $0.6 million, general and administrative expenses of $0.4
million and payment for operating expenses of $0.4 million.




Cash
flows provided by operating activities for the year ended December 31, 2006 were
$9.9 million, primarily related to cash receipts from oil and natural gas
production of $11.3 million, interest received of $0.9 million, offset by
payments for management fees of $1.1 million, operating expenses of $0.5
million, general and administrative expenses of $0.3 million and unfavorable
working capital of $0.4 million.




Investing
Cash Flows




Cash
flows used in investing activities for the year ended December 31, 2007 were
$4.9 million, primarily related to capital expenditures for oil and gas
properties of $5.9 million, partially offset by insurance proceeds of $1.0
million.




Cash
flows used in investing activities for the year ended December 31, 2006 was $9.7
million, primarily related to capital expenditures for oil and gas
properties.




Financing
Cash Flows




Cash
flows used in financing activities for the year ended December 31, 2007 were
$1.2 million, related to distributions to shareholders and the
Manager.




Cash
flows used in financing activities for the year ended December 31, 2006 were
$9.0 million, related to 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
$1.1 million for properties.   If the properties were to be
successful, the Fund would make additional expenditures totaling $2.8 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 for a fund, the Manager seeks an investment portfolio that combines
high and low risk exploratory projects.




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




17
 Table of Contents




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.




ITEM7A. QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK




Not
required.




ITEM
8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA




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




ITEM9. 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 May 27, 2004 and filed its Registration Statement on Form 10 in
April 2005; thus, the period beginning May 27, 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 May 27, 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.




18
 Table of Contents





Management's
Report on Internal Control over Financial Reporting




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




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





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





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




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




Changes
in Internal 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




ITEM10. 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.


19
 Table of Contents




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.




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.




20
 Table of Contents




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.




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 350.1081 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
            
            
            7.000
            
            
            
            *Executive
      officers as a group (1)
            
            
            7.000
            
            
            
            *





*
Represents approximately two percent.


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


21
 Table of Contents




ITEM13.     
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
  The
Fund’s LLC agreement provides that the Manager render management, administrative
and advisory services. For such services, the Manager receives an annual
management fee, payable monthly, of 2.5% of total capital contributions.
Effective September 1, 2006, the Manager changed its policy regarding the annual
management fee whereby the management fee was equal to 2.5% of the total
shareholder capital contributions, net of cumulative dry-hole costs incurred by
the Fund.  On September 1, 2007, the Manager has elected to forego its
management fee for the remaining life of the Fund.  Management fees
incurred and paid for the years ended December 31, 2007 and 2006 were $0.6
million and $1.1 million, respectively.


From time
to time, short-term payables and receivables, which do not bear interest, arise
from transactions with affiliates in the ordinary course of business. At
December 31, 2007, the Fund was owed $0.5 million related to insurance proceeds
and revenue allocations.  At December 31, 2006, the Fund had a $0.2
million receivable due from the Manager.




ITEM14. PRINCIPAL
ACCOUNTANT FEES AND SERVICES




The
following table presents fees for services rendered by Deloitte & Touche
LLP.




Year
      ended December 31,2007
              
              
              2006(in
      thousands)Audit
      Fees (1)
              
              $
              125
              
              
              $
              144Tax
      fees (2)
              
              
              -
              
              
              
              14Total
              
              $
              125
              
              
              $
              158







(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.
              
              Description23.1
              
              
              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.
 
 22
 Table of Contents
  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-13
     F-1
 Table of Contents


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM




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




We have
audited the accompanying balance sheets of Ridgewood Energy L 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 L Fund, LLC as of December 31, 2007 and
2006, and the results of operations and 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 L FUND, LLCBALANCE
      SHEETS(in
      thousands, except share amounts)December
      31,2007
                
                
                2006ASSETSCurrent
      assets:Cash
      and cash equivalents
                
                $
                8,506
                
                
                $
                13,215Production
      receivable
                
                
                220
                
                
                
                251Insurance
      receivable
                
                
                -
                
                
                
                2,534Due
      from affiliates (Note 6)
                
                
                497
                
                
                
                196Other
      current assets
                
                
                189
                
                
                
                261Total
      current assets
                
                
                9,412
                
                
                
                16,457Salvage
      fund
                
                
                1,165
                
                
                
                1,112Oil
      and gas properties:Proved
      properties
                
                
                15,444
                
                
                
                9,379Unproved
      properties
                
                
                3,738
                
                
                
                3,670Less:
      accumulated depletion and amortization
                
                
                (13,108
                )
                
                
                (9,082
                )Total
      oil and gas properties
                
                
                6,074
                
                
                
                3,967Total
      assets
                
                $
                16,651
                
                
                $
                21,536LIABILITIES
      AND MEMBERS' CAPITALCurrent
      liabilities:Due
      to operators
                
                $
                1,184
                
                
                $
                540Accrued
      expenses payable
                
                
                80
                
                
                
                142Total
      current liabilities
                
                
                1,264
                
                
                
                682Asset
      retirement obligations
                
                
                417
                
                
                
                349Total
      liabilities
                
                
                1,681
                
                
                
                1,031Commitments
      and contingencies (Note 8)Members'
      capital:Manager:Distributions
                
                
                (1,651
                )
                
                
                (1,477
                )Retained
      earnings
                
                
                1,152
                
                
                
                1,092Manager's
      total
                
                
                (499
                )
                
                
                (385
                )Shareholders:Capital
      contributions (670 shares authorized;  350.1081issued
      and outstanding)
                
                
                51,401
                
                
                
                51,401Syndication
      costs
                
                
                (5,502
                )
                
                
                (5,502
                )Distributions
                
                
                (9,356
                )
                
                
                (8,371
                )Accumulated
      deficit
                
                
                (21,074
                )
                
                
                (16,638
                )Shareholders'
      total
                
                
                15,469
                
                
                
                20,890Total
      members' capital
                
                
                14,970
                
                
                
                20,505Total
      liabilities and members' capital
                
                $
                16,651
                
                
                $
                21,536




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


F-3
 Table of Contents




RIDGEWOOD ENERGY L FUND, LLCSTATEMENTS
      OF OPERATIONS(in
      thousands, except share amounts)Year
      ended December 31,2007
              
              
              2006RevenueOil
      and gas revenue
              
              $
              2,109
              
              
              $
              5,522ExpensesDepletion
      and amortization
              
              
              771
              
              
              
              4,202Dry-hole
      costs
              
              
              525
              
              
              
              4,863Impairment
      of proved property
              
              
              3,255
              
              
              
              -Casualty
      loss
              
              
              1,023
              
              
              
              133Lease
      operating expenses
              
              
              332
              
              
              
              535Management
      fees to affiliate (Note 6)
              
              
              612
              
              
              
              1,149Other
      operating expenses
              
              
              37
              
              
              
              20General
      and administrative expenses
              
              
              432
              
              
              
              280Total
      expenses
              
              
              6,987
              
              
              
              11,182Loss
      from operations
              
              
              (4,878
              )
              
              
              (5,660
              )Other
      incomeInterest
      income
              
              
              502
              
              
              
              860Net
      loss
              
              $
              (4,376
              )
              
              $
              (4,800
              )Manager
      InterestNet
      income
              
              $
              60
              
              
              $
              450Shareholder
      InterestNet
      loss
              
              $
              (4,436
              )
              
              $
              (5,250
              )Net
      loss per share
              
              $
              (12,670
              )
              
              $
              (14,995
              )




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


F-4
 Table of Contents




RIDGEWOOD
      ENERGY L FUND, LLCSTATEMENTS OF CHANGES IN MEMBERS' CAPITAL(in
      thousands, except share amounts)#
      of Shares
              
              
              Manager
              
              
              Shareholders
              
              
              TotalBalances,
      December 31, 2005
              
              
              350.1081
              
              
              $
              516
              
              
              $
              33,798
              
              
              $
              34,314Net
      income (loss)
              
              
              -
              
              
              
              450
              
              
              
              (5,250
              )
              
              
              (4,800
              )Distributions
              
              
              -
              
              
              
              (1,351
              )
              
              
              (7,658
              )
              
              
              (9,009
              )Balances,
      December 31, 2006
              
              
              350.1081
              
              
              
              (385
              )
              
              
              20,890
              
              
              
              20,505Net
      income (loss)
              
              
              -
              
              
              
              60
              
              
              
              (4,436
              )
              
              
              (4,376
              )Distributions
              
              
              -
              
              
              
              (174
              )
              
              
              (985
              )
              
              
              (1,159
              )Balances,
      December 31, 2007
              
              
              350.1081
              
              
              $
              (499
              )
              
              $
              15,469
              
              
              $
              14,970




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


F-5
 Table of Contents




RIDGEWOOD
      ENERGY L FUND, LLCSTATEMENTS
      OF CASH FLOWS(in
      thousands)Year
      endedDecember
      31,2007
              
              
              2006Cash
      flows from operating activitiesNet
      loss
              
              $
              (4,376
              )
              
              $
              (4,800
              )Adjustments
      to reconcile net loss to net cash
                provided
      by operating activities:Depletion
      and amortization
              
              
              771
              
              
              
              4,202Dry-hole
      costs
              
              
              525
              
              
              
              4,863Impairment
      of proved property
              
              
              3,255
              
              
              
              -Accretion
      expense
              
              
              18
              
              
              
              16Casualty
      loss
              
              
              1,023
              
              
              
              -Changes
      in assets and liabilities:Decrease
      in production receivable
              
              
              31
              
              
              
              5,816Increase
      in due from affiliate
              
              
              (6
              )
              
              
              (6
              )Decrease
      (increase) in other current assets
              
              
              184
              
              
              
              (244
              )Decrease
      in due to operators
              
              
              (23
              )
              
              
              (13
              )(Decrease)
      increase in accrued expenses payable
              
              
              (62
              )
              
              
              101Net
      cash provided by operating activities
              
              
              1,340
              
              
              
              9,935Cash
      flows from investing activitiesCapital
      expenditures for oil and gas properties
              
              
              (5,857
              )
              
              
              (9,596
              )Proceeds
      from insurance receivable
              
              
              1,020
              
              
              
              -Salvage
      fund investments
              
              
              (53
              )
              
              
              (79
              )Net
      cash used in investing activities
              
              
              (4,890
              )
              
              
              (9,675
              )Cash
      flows from financing activitiesDistributions
      paid
              
              
              (1,159
              )
              
              
              (9,009
              )Net
      cash used in financing activities
              
              
              (1,159
              )
              
              
              (9,009
              )Net
      decrease in cash and cash equivalents
              
              
              (4,709
              )
              
              
              (8,749
              )Cash
      and cash equivalents, beginning of period
              
              
              13,215
              
              
              
              21,964Cash
      and cash equivalents, end of period
              
              $
              8,506
              
              
              $
              13,215Supplemental
      schedule of non-cash investing activitiesAdvances
      used for capital expenditures in oil and
                gas
      properties reclassified to dry-hole costs
              
              $
              -
              
              
              $
              1,256




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


F-6
 Table of Contents




RIDGEWOOD
ENERGY L FUND, LLC


NOTES TO FINANCIAL STATEMENTS




1.  Organization
and Purpose




The
Ridgewood Energy L Fund, LLC (the “Fund”), a Delaware limited liability company,
was formed on May 27, 2004 and operates pursuant to a limited liability company
agreement (the “LLC agreement”) dated as of July 6, 2004 by and among Ridgewood
Energy Corporation (the “Manager”) and the shareholders of the
Fund.





The Fund
was organized to acquire, drill, construct and develop oil and natural gas
properties located in the United States offshore waters of Texas and Louisiana
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 September 2005 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 $5.3
million and $13.0 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 approximates fair value.  At
December 31, 2007, the Fund had short-term held-to-maturity investments,
inclusive of salvage fund of $1.1 million, which matured in January
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.




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.




F-7
 Table of Contents




The
successful efforts method of accounting for oil and gas producing activities is
followed. Acquisition costs are capitalized when incurred. Other oil and 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 $1.2 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,
              
              $
              349
              
              
              $
              333Liabilities
      incurred
              
              
              109
              
              
              
              237Liabilities
      settled
              
              
              (59
              )
              
              
              (237
              )Accretion
      expense
              
              
              18
              
              
              
              16Balance,
      December 31,
              
              $
              417
              
              
              $
              349




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.




Revenue
Recognition and Production Receivable


Oil and
natural gas sales are recognized when delivery is made and a production
receivable is recorded  when delivery is made by the Operator to the
purchaser and title is transferred (i.e., production has been delivered to a
pipeline or transport vehicle).




The
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.


F-8
 Table of Contents




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.





During
2007, the Fund recorded an impairment of $3.3 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
$2.0 million was recorded during the third quarter of 2007.  At year
end, reserve estimates were received from independent petroleum engineer, Ryder
Scott Company, L.P.  Those reserve estimates were lower than internal
estimates, and as a result, an additional impairment was recorded during the
fourth quarter of 2007, of $1.3 million.  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.  For the year ended December 31, 2006, no impairments were
recorded.





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 reserve
estimates 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 reserve estimates could have a
material effect on balances recorded as proved properties.





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.


F-9
 Table of Contents




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 $0.9 million and $0.1 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.




Year
      ended December 31,2007
              
              
              2006(in
      thousands)Balance,
      January 1,
              
              $
              3,670
              
              
              $
              197Additions
      to capitalized exploratory well costs pending the
                determination
      of proved reserves
              
              
              5,873
              
              
              
              3,542Reclassification
      to proved properties based on the
                determination
      of proved reserves
              
              
              (5,805
              )
              
              
              -Capitalized
      exploratory well costs charged to dry-hole costs
              
              
              -
              
              
              
              (69
              )Balance,
      December 31,
              
              $
              3,738
              
              
              $
              3,670




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
              
              $
              527
              
              
              $
              -Main
      Pass 155
              
              
              25
              
              
              
              30East
      Breaks 157
              
              
              8
              
              
              
              1,793West
      Cameron 103
              
              
              -
              
              
              
              3East
      Cameron 48
              
              
              -
              
              
              
              107West
      Cameron 78/95
              
              
              (35
              )
              
              
              2,930$
              525
              
              
              $
              4,863




5.  Distributions




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


F-10
 Table of Contents


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.




The
shareholders received distributions of $1.0 million and $7.7 million,
respectively, for the years ended December 31, 2007 and 2006.  The
Manager received distributions of $0.2 million and $1.4 million, respectively,
for the years ended December 31, 2007 and 2006.




6.  Related
Parties




The Fund’s LLC agreement
provides that the Manager render management, administrative and advisory
services. For such services, the Manager would receive an annual management fee,
payable monthly, of 2.5% of total capital contributions.Effective
September 1, 2006, the Manager changed its policy regarding the annual
management fee whereby the management fee would be equal to 2.5% of the total
shareholder capital contributions, net of cumulative dry-hole costs incurred by
the Fund.  On September 1, 2007, the Manager elected to forego its
management fee for the remaining life of the Fund.  Management fees
incurred for the years ended December 31, 2007 and 2006 were $0.6 million and
$1.1 million, respectively.




From time
to time, short-term payables and receivables, which do not bear interest, arise
from transactions with affiliates in the ordinary course of business. At
December 31, 2007, the Fund was owed $0.5 million related to insurance proceeds
and revenue allocations.  As of December 31, 2006, the Fund had a $0.2
million receivable due from the Manager.




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, 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 $1.1 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-11
 Table of Contents




West Cameron
78/95


In 2006,
the Fund acquired a 20% working interest in West Cameron 78/95.  The
well began drilling on April 21, 2006.  Drilling went according to
plan until the drill string became stuck.  The smaller drill pipe was
recovered and the well was sidetracked, or re-drilled.   Drilling
continued until the well was determined to be a dry-hole.  In July
2006 the decision was made to plug and abandon the well.   During
2006, the Fund recorded a casualty loss of $0.1 million related to the insurance
deductible for this claim.  During 2007, the Fund recorded an
additional casualty loss of $1.0 million as a result of changes in estimates to,
and the ultimate settlement of the insurance claim. The Fund received proceeds
of $1.0 million for the settlement of this claim during the fourth quarter of
2007, and the additional $0.5 million in 2008 as a transfer from the
Manager.











F-12
 Table of Contents


Ridgewood
Energy L 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 Texas and Louisiana in the Gulf of
Mexico.




Table
      I - Capitalized Costs Related to Oil and Gas Producing
      ActivitiesDecember
      31,2007
              
              
              2006(in
      thousands)Unproved
      oil and gas properties
              
              $
              3,738
              
              
              $
              9,379Proved
      oil and gas properties
              
              
              15,444
              
              
              
              3,670Total
      oil and gas properties
              
              
              19,182
              
              
              
              13,049Accumulated
      depletion and amortization
              
              
              (13,108
              )
              
              
              (9,082
              )Oil
      and gas properties, net
              
              $
              6,074
              
              
              $
              3,967Table
      II - Costs Incurred in Exploration, Property Acquisitions and
      DevelopmentYear
      ended December 31,2007
              
              
              2006(in
      thousands)Exploratory
      drilling costs - capitalized
              
              $
              6,083
              
              
              $
              3,492Exploratory
      drilling costs - expensed
              
              
              525
              
              
              
              3,607$
              6,608
              
              
              $
              7,099




F-13
 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 December 31,
2006 were based on estimated future reserves as of December 31, 2007 and
September 30, 2006, respectively provided by Ryder Scott Company,
L.P.  At December 31, 2007, internal estimates were used for one well,
South Timbalier 77 as it is nearing the end of its production life in
early-2008.  These reserve disclosures have been prepared in
compliance with the Securities and Exchange Commission rules.




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




December 31,
      2007

                  United
      States
              
              
              December
      31, 2006
                United
      StatesOil
      (BBLS)
              
              
              Gas
      (MCF)
              
              
              Oil
      (BBLS)
              
              
              Gas
      (MCF)Proved
      developed reserves:Beginning
      of year
              
              
              29,255
              
              
              
              217,278
              
              
              
              15,801
              
              
              
              325,496Discoveries
              
              
              7,886
              
              
              
              380,288
              
              
              
              -
              
              
              
              -Revisions
      of previous estimates
              
              
              (11,634
              )
              
              
              (123,572
              )
              
              
              38,934
              
              
              
              338,062Production
              
              
              (11,190
              )
              
              
              (170,394
              )
              
              
              (25,480
              )
              
              
              (446,280
              )End
      of year
              
              
              14,317
              
              
              
              303,600
              
              
              
              29,255
              
              
              
              217,278Due
      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 ReservesSummarized
      in the following table is information for the Fund with respect to the
      standardized measure of discounted future net cash flows relating to
      proved oil and natural gas reserves. Future cash inflows are computed by
      applying year-end prices of oil and natural gas relating to the Fund's
      proved reserves to the year-end quantities of those reserves. Future
      production, development, site restoration and abandonment costs are
      derived based on current costs assuming continuation of existing economic
      conditions.




Year
      ended December 31,2007
              
              
              2006(in
      thousands)Future
      estimated revenues
              
              $
              3,734
              
              
              $
              3,013Future
      estimated production costs
              
              
              (312
              )
              
              
              (542
              )Future
      estimated development costs
              
              
              (401
              )
              
              
              (160
              )Future
      net cash flows
              
              
              3,021
              
              
              
              2,31110%
      annual discount for estimated timing of cash flows
              
              
              (228
              )
              
              
              (485
              )Standardized
      measure of discounted future estimated net cash flows
              
              $
              2,793
              
              
              $
              1,826




F-14
 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
              
              
              2006(in
      thousands)Standardized
      measure beginning of the year
              
              $
              1,826
              
              
              $
              4,389Sales
      of oil and gas production, net of production costs
              
              
              (1,777
              )
              
              
              (4,988
              )Net
      changes in prices and production costs
              
              
              990
              
              
              
              -Extensions,
      discoveries, and improved recovery and techniques, less related
      costs
              
              
              2,818
              
              
              
              -Revision
      of development costs
              
              
              (196
              )
              
              
              (160
              )Revisions
      of previous reserve quantities estimate
              
              
              (1,408
              )
              
              
              2,763Accretion
      of discount
              
              
              228
              
              
              
              147Timing
      and other
              
              
              312
              
              
              
              (325
              )Standardized
      measure end of the year
              
              $
              2,793
              
              
              $
              1,826




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


F-15
 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 L 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