UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

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

                      For the Year Ended December 31, 2005
                          Commission File No. 000-51267

                          RIDGEWOOD ENERGY L FUND, LLC
                  1314 King Street, Wilmington, Delaware 19801
                                 (302) 888-7444

 Incorporated in the State of Delaware               Employer ID No. 11-3719724

        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 [_] 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 [_] 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 [_]

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]

Indicated by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Act. (Check one):

Large accelerated filer [_]    Accelerated filer [_]   Non-accelerated filer [X]

Indicated by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes [_] No [X]

There is no market for the Shares. The aggregate capital contributions made for
the Registrant's voting Shares held by non-affiliates of the Registrant at
February 28, 2006 was $51,400,840 and as of that date there are 350.1081 shares
outstanding.



<PAGE>

<TABLE>
<CAPTION>
                               Table of Contents
                               -----------------
<S>      <C>                                                                    <C>
Forward-Looking Statements
--------------------------

PART I
------

    Item 1        Business                                                      1
    Item 1A       Risks                                                         9
    Item 1B       Unresolved Staff Comments                                     14
    Item 2        Properties                                                    14
    Item 3        Legal Proceedings                                             16
    Item 4        Submission of Matters to a Vote of Security Holders           16

PART II
-------

    Item 5        Market for Registrant's Common Equity, Related Stockholder
                      Matters and Issuer Purchases of Equity Securities         16
    Item 6        Selected Financial Data                                       17
    Item 7        Management's Discussion and Analysis of Financial Condition
                      and Results of Operations                                 17
    Item 7A       Quantitative and Qualitative Disclosures about Market Risk    26
    Item 8        Financial Statements and Supplementary Data                   26
    Item 9        Changes in and Disagreements with Accountants on Accounting
                       And Financial Disclosure                                 26
    Item 9A       Controls and Procedures                                       26
    Item 9B       Other Information                                             27

PART III
--------

    Item 10       Directors and Executive Officers of the Registrant            27
    Item 11       Executive Compensation                                        29
    Item 12       Security Ownership of Certain Beneficial Owners and
                  Management and Related Stockholder Matters                    30
    Item 13       Certain Relationships and Related Transactions                30
    Item 14       Principal Accountant Fees and Services                        31

PART IV
-------

    Item 15       Exhibits, Financial Statement Schedules                       31

    Signatures                                                                  34
</TABLE>


<PAGE>


FORWARD LOOKING STATEMENTS

         This Annual Report on Form 10-K, including all documents incorporated
by reference, includes "forward-looking" statements within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and
Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), and the Private Securities Litigation Reform Act of 1995, and the "safe
harbor" provisions thereof. These forward-looking statements are usually
accompanied by the words "anticipates," "believes," "plan," "seeks," "expects,"
"intends," "estimates," "projects," "will likely result," "will continue,"
"future" and similar terms and expressions. All statements other than statements
of historical facts, including among others, statements regarding our future
financial position, business strategy, budgets, reserve information, and
projected plans and objectives of management for future operations, are
forward-looking statements. Forward-looking statements are not guarantees of
performance. Although, we believe the expectations reflected in forward-looking
statements are based on reasonable assumptions, no assurance can be given that
these expectations will be achieved. The forward-looking statements contained
herein reflect our current views with respect to future events and financial
performance. Important factors that could cause actual results to differ
materially from the expectations reflected include, among others: the timing and
extent of changes in commodity prices for oil and natural gas; the extent of our
success in discovering, developing and acquiring oil and gas properties; the
accuracy of reserve estimates, which by their nature involve the exercise of
professional judgment and may, therefore, be imprecise; the availability and
cost of drilling rigs; and those other risks and uncertainties discussed in Item
1A under "Risk Factors" and elsewhere in this Annual Report on Form 10-K that
could cause actual results to differ materially from historical results or those
anticipated. In light of these risks and uncertainties, there can be no
assurance that the forward-looking information contained in this Annual Report
on Form 10-K will in fact occur or prove to be accurate. Readers should not
place undue reliance on the forward-looking statements contained herein, which
speak only as of the date of filing. We undertake no obligation to publicly
revise these forward-looking statements to reflect events or circumstances that
may arise after the date of filing. All subsequent written or oral
forward-looking statements attributable to us or persons acting on our behalf
are expressly qualified in their entirety by this section.

PART I

Item 1.  Business

         General

         We were formed on May 27, 2004 as a Delaware limited liability company
and we operate pursuant to a limited liability company agreement (" LLC
Agreement"), dated as of July 1, 2004, that we executed with Ridgewood Energy
Corporation, our manager ("Manager") and our shareholders. We are engaged in the
acquisition, development and production of oil and natural gas properties in the
Gulf of Mexico. We have focused primarily on acquiring natural gas and oil
projects in the shallow waters of the Gulf of Mexico in locations with access to
existing gathering and processing infrastructure or where such infrastructure
can be constructed economically and efficiently.

         In many instances, we compete for projects with large independent oil
and natural gas producers who generally have significantly greater access to
capital resources, have larger staffs, and more experience in natural gas and
oil exploration and production than we have. As a result, these larger companies
are in a position that they could outbid us 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


                                       1
<PAGE>


tend to be projects in the deepwater areas of the Gulf of Mexico, the North Sea
off the coast of Great Britain or in other areas of the world. 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
we compete. 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.
We, therefore, have opportunities to acquire interests in these smaller, yet
economically attractive projects.

         We offered our securities to investors in a private placement beginning
on July 6, 2004 and sold whole and fractional shares of LLC membership interests
at $150,000 per share. There is no public market for these shares and one is not
likely to develop. In addition, the shares are subject to restrictions on
transfer and resale and cannot be transferred or resold except in accordance
with the LLC Agreement and applicable federal and state securities laws. The
offering was terminated on September 30, 2004. We raised approximately $51.4
million and, after payment of $7.8 million in offering fees, commissions and
investment fees, we retained approximately $43.6 million for investments and
operating expenses. As of December 31, 2005, approximately $19.5 has been spent
acquiring, drilling and completing our various oil and gas properties of which
$250,000 is due from the operators for overpaid well costs. There is
approximately $24.1 million remaining for further investment, fund expenses or
completion of existing investments of which $11.6 million has been allocated to
specific projects. See Item 7, Management's Discussion and Analysis.

         As of December 31, 2005, we had estimated proved developed reserves of
419 MMCFE, all of which are located in the Gulf of Mexico. Year-end reserves
were comprised of 333 MMCF natural gas and 14.5 MBBLS oil. The estimated present
value of the future net cash flows pertaining to our reserves as of December 31,
2005 is $2.9 million. At December 31, 2005, we have leasehold and other
interests in three offshore blocks and four wells, all of which are located in
the Gulf of Mexico. These projects are discussed in more detail in Item 2,
Properties.

         We operate in only one segment: oil and natural gas exploration and
production. The financial results from this segment are contained in the
financial statements attached to this Annual Report on Form 10-K and in Item 7,
Management's Discussion and Analysis.

         Manager

         We do not have a Board of Directors. Ridgewood Energy Corporation is
our Manager and pursuant to the LLC Agreement has direct and exclusive control
over our management and operations. As part of our project investment activities
and on our behalf, the Manager locates potential projects, conducts appropriate
due diligence and negotiates and completes the transactions in which the
investments are made. This includes, but is not limited to, review of existing
title documents, reserve information and other technical specifications related
to a project as well as the review and preparation of agreements related to the
investment. In addition, once the investment is made and the project begun, the
Manager is responsible for overseeing and managing the activities of the project
and the operator and is empowered to act on our behalf with the other working
interest owners.

         The Manager also performs, or arranges for the performance of, certain
management and administrative services we require including the administration
of shareholder accounts, shareholder relations, and the preparation, review and
dissemination of tax and other financial information. In addition, the Manager


                                       2
<PAGE>


provides us with office space, equipment and facilities, and other services
necessary for our operations. Finally, the Manager manages and conducts our
relationships with custodians, depositories, accountants, attorneys,
broker/dealers, corporate fiduciaries, insurers, banks and others as required.
See also, Item 1A, Risk Factors.

         As compensation for its management services, the Manager receives (i)
an annual "Management Fee" equal to 2.5% of the total Capital Contributions made
by our shareholders and (ii) a 15% interest in the cash distributions made to
our shareholders. As set forth in Item 7, Management's Discussion and Analysis,
the Manager received from us for the year 2005 a total of $1,285,027 for its
management services, and $125,798 representative of the 15% interest of cash
distributions.

         Business Strategy

         Our primary investment objective is to generate cash flow from the
acquisition, exploration, production and sale of crude oil and natural gas from
oil and gas properties. We have invested and participate in exploration and
production projects located in the waters of the Gulf of Mexico offshore
Louisiana and Texas on the Outer Continental Shelf ("OCS"). These activities are
governed by the Outer Continental Shelf Lands Act (OSCLA) enacted in 1953 and
administered by the Minerals Management Service ("MMS"). We generally look to
invest in projects that have been proposed by larger independent oil and gas
companies seeking to minimize their risks by selling a portion of their interest
in a project. These investments may require us to pay a larger interest of the
costs than our ownership interest would otherwise require. This is called a
"promote" and is relatively typical in the oil and natural gas exploration
industry. In addition, notwithstanding the sale of an interest to us, the seller
may retain a right for some period of time to payments from sale of the
production from a well or project. This is called an "overriding interest,"
which is also relatively common in the industry. Notwithstanding any such
promote or overriding interest, we have tried to invest in projects that we
believe contain sufficient commercial quantities of natural gas or oil and which
are near (i) existing natural gas or oil gathering and processing infrastructure
and (ii) developed markets where we can sell our natural gas or oil.

         We try and focus on projects that have significant reserve potential
and which are projected to have the shortest time period from our investment to
first production. However, we do not operate these projects, and the manner in
which and schedule pursuant to which our projects are developed and completed is
determined exclusively by the operator and is beyond our ability to
significantly influence. Moreover, when performing due diligence with respect to
a project, we must rely on the independent reservoir engineers who are hired and
paid, in most cases, by the operator, although we do engage certain consultants
for ourselves to examine and review such reserve estimates and seismic
information on our behalf.

         Acquisition Criteria

         The Manager has control over the selection of projects, the percentage
investment and ownership interest acquired. In evaluating various potential
investments, the Manager conducts due diligence of each such project against a
list of factors that we believe will result in the selection of those projects
that have the highest probability of success. These factors include, but are not
limited to, the following:

     o    The oil or gas reserve potential of the project.


                                       3
<PAGE>


     o    Economic  factors,  such as potential  revenues from the project,  the
          rate of return, and estimated time to first production.

     o    The technical quality of the project,  including its geology,  seismic
          profile,  locational trends, and whether the project has potential for
          multiple prospects.

     o    Whether a project will have operators and/or partners with significant
          resources, experience and prior success in oil and gas exploration.

     o    Whether and the extent to which the operator participates as a working
          interest owner in the project.

     o    The existence and  availability of drilling rigs,  platforms and other
          infrastructure, at or nearby the project.

     o    Proposed drilling schedule.

     o    The  terms  of  the  proposed   transaction,   including   contractual
          restrictions and obligations and lease term.

     o    Overall cost of the project

     Although these factors are those generally used by our Manager, we can not
say whether the Manager reviews every potential investment against all of these
factors or, if so, whether and for what reason one factor was given greater
weight in the analysis than another.

Oil and Gas Agreements

         We have entered onto a short-term month to month agreement with Energy
Upgrade Inc. who is currently marketing and selling our proportionate share of
the gas from South Timbalier 221 to the public market. We are receiving market
prices for such gas. The Manager believes that it is likely that gas from our
other projects, once producing, will also have access to pipeline transportation
and can be marketed in a similar fashion. Given current market prices for
natural gas, we anticipate that we will continue to market and sell gas through
Energy Upgrade Inc. at market prices.

Operators

         The projects in which we have invested are operated and controlled by
unaffiliated third-party entities acting as operators. The operator is
responsible for drilling, administration and production activities for leases
jointly owned by working interest owners and acts for the account 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.

         Because we do not operate any of the projects in which we have acquired
an interest, shareholders must not only bear the risk that the Manager will be
able to select suitable projects, but also that, once acquired, such projects
will be managed prudently, efficiently and fairly by our operators.


                                       4
<PAGE>


         As of December 31, 2005 the Fund has two producing wells on South
Timbalier 77 operated by ATP Oil and Gas Corporation ("ATP"), which acquired
Millennium Offshore Group, Inc, ("MOGI") in November 2005.

         We have one project, East Banks 157, operated by Woodside Energy that
is currently drilling and another, Eugene Island 337, that Devon Energy Corp.
will operate that is set to begin drilling in the Spring 2006.

         We also invested in one well each with Gryphon Exploration, Samson
Offshore Group and Apache Corporation all of which were considered dry-holes.
See Item 2, Properties.

Seasonality

         Our business operations are not subject to seasonal fluctuations that
would materially affect the amount of or manner in which our natural gas or oil
is sold and marketed. Once a well is drilled and reserves of oil and gas are
determined to exist, the operator of the well extracts such reserves throughout
the year. Oil and gas, once extracted, can be sold at any time during the year.

         However, our business operations and sales are subject to seasonal
"risks" that may affect, if anything, the price for such oil and gas or our
ability to bring such gas or oil to the market. For example, 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 or price of repair or replacement
equipment. As a result, these factors may affect the supply and, consequently,
the price of oil and gas resulting in a possible increase in the price if
supplies are reduced. However, even if commodity prices increase because of
weather related shortages, we 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 our projects, the gathering infrastructure or in
the transportation network.

Regulation

         Oil and 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,
our operators to obtain permits to drill wells and to meet bonding, insurance
and environmental requirements in order to drill, own or operate wells. In
addition, the location of wells, the method of drilling and casing wells, the
restoration of properties upon which wells are drilled and the plugging and
abandoning of wells are also subject to regulations.

         Outer Continental Shelf Lands Act

         Our projects are located in the offshore waters of the Gulf of Mexico
on the Outer Continental Shelf, or the OCS. Our operations and activities,
therefore, are governed by, among other things, the Outer Continental Shelf
Lands Act, or the OCSLA, which was enacted in 1953.

         Under OCSLA, as amended, 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
Minerals Management Services, or 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


                                       5
<PAGE>


such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental
Protection Agency. Offshore operations are subject to numerous regulatory
requirements, including stringent engineering and construction specifications
related to offshore production facilities and pipelines and safety-related
regulations concerning the design and operating procedures of these facilities
and pipelines. MMS regulations also restrict the flaring or venting of
production and proposed regulations would prohibit the flaring of liquid
hydrocarbons and oil without prior authorization. The MMS has also imposed
regulations governing the plugging and abandonment of wells located offshore and
the installation and removal of all production facilities. Under certain
circumstances, the MMS may require operations on federal leases to be suspended
or terminated. Any such suspension or termination could adversely affect our
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

         We currently are selling our natural gas and oil to the market and
receiving market prices from such sales. These sales are not currently subject
to regulation by any federal or state agency. However, in order for us to make
such sales we are dependent upon pipelines whose rates, terms and conditions of
transport are subject to regulation by the Federal Energy Regulatory Commission
("FERC"). The rates, terms and conditions are regulated by FERC pursuant to a
variety of statutes including the OSCLA, the Natural Gas Policy Act and the
Energy Policy Act of 1992. Generally, depending on certain factors, pipelines
can charge rates that are either market-based or cost-of-service. In some
circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates
that pipelines charge to us, although regulated, are beyond our control.
Nevertheless, such rates would apply uniformly to all transporters on that
pipeline and, as a result, we believe that the impact of any changes in such
rates, terms or conditions would not impact our operations differently in any
material way than the impact upon other natural gas or oil producers and
marketers.

Environmental Regulation

         Our 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 we share the
liability along with our other working interest owners for any environmental
damage, most of the activities to which these environmental laws and regulations
apply are conducted by our operator on our behalf. Nevertheless, environmental
laws and regulations to which our operations are subject may require us, or our
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 wells and, finally, impose in some instances severe
penalties, fines and liabilities for the environmental damage that is caused by
our operations.

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


                                       6
<PAGE>


         The Oil Pollution Act. The Oil Pollution Act ("OPA") amends Section 311
of the Federal Water Pollution Act (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 the oil spill. Under the OPA, parties
responsible for offshore facilities must provide financial assurance of at least
$35 million to address oil spills and associated damages. In certain limited
circumstances, that amount may be increased to $150 million. As indicated
earlier, we have not been required to make any such showing to the MMS as the
operator is responsible for such compliance. However, notwithstanding the
operator's responsibility for compliance, in the event of an oil spill, we,
along with the operator and other working interest owners, could be liable under
the OPA for the resulting environmental damage.

         Federal Water Pollution Act/Clean Water Act. Generally, the Clean Water
Act imposes liability for the unauthorized discharge of 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. Again, our operators are responsible
for compliance with the Clean Water Act although we may be liable for any
failure of the operator to do so.

         Federal Clean Air Act. The Federal 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, our operations may be required to incur additional
costs to comply with the Clean Air Act.

          Other Environmental Laws. In addition to the above, our 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 join 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 our operations. We believe that our operators are in
compliance with each of these environmental laws and the regulations promulgated
thereunder.

Competition and Markets

         Strong competition exists for the acquisition and participation in
offshore drilling projects. Such activity has increased recently given the
recent surge in the commodity price for oil and natural gas. Many companies with
whom we compete for the acquisition of projects have more financial and other


                                       7
<PAGE>


resources than may be available to us. Some of these companies, but certainly
not all, include Chevron, BP, Apache Corporation, and Houston Exploration, all
of whom are substantially larger than we are. As a result, our competitive
position against these companies is relatively weak. However, as indicated
earlier, most of our capital has been either spent or committed to projects such
that we will likely not be competing with these large companies in the future
for projects. However, if one or more of our existing projects were to be deemed
a dry-hole, the funds we are holding for completion would be free for further
investing. In such a case, we would again be competing with these larger
companies for projects.

         The availability of a market for any oil and gas produced from our
operations will depend on a number of factors beyond our control, most of which
cannot be accurately predicted. These factors include the extent of domestic
production and importation of oil and natural gas, the proximity of our wells to
and the capacity of natural gas pipelines, the availability of other competitive
fuels, fluctuations in seasonal supply and demand, government regulation of
supply and demand caused by its pricing and allocation restrictions, and general
national and worldwide economic conditions. Additionally, increased drilling
activity has caused a shortage of drilling rigs and other services necessary for
the drilling, production and marketing of oil and natural gas. Any such shortage
of equipment and services could adversely affect our activities.

Customers

         During the first ten months of 2005, all of the Fund's oil and natural
gas production from our producing properties (South Timbalier 77) was sold by
the operator on our behalf. During that time period, our producing properties
were operated by Millennium Offshore Group Inc., ("MOGI"). MOGI sold our oil and
natural gas production to the "market". As a result, we did not contract to sell
any of our oil or gas to third parties. Therefore, during this period, the Fund
had no customers or any one customer upon which we depended for more than 10% of
our revenue. In November 2005, MOGI sold its interest in these producing
properties to ATP and ATP became the new owner and operator. As a result of
MOGI's sale to ATP, the Manager retained Energy Upgrade to market our gas, as of
December 1, 2005. Our contract with Energy Upgrade is month to month but the fee
structure is guaranteed for the one year period beginning December 1, 2005. We
pay Energy Upgrade $0.04 per MMBTU less all costs or fees such as processing,
transportation and fuel charges. Energy Upgrade's cost to market our crude oil
and condensate is $0.50 per barrel for the same services. For quantities of gas
in excess of 25,000 MMBTU per day, Energy Upgrade will decrease its fee by
$0.015 per MMBTU. Energy Upgrade is also required to file all pertinent reports
with the MMS and any other royalty owners should there be any at no additional
cost to us.

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
which we can not 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 our future profitability. Also, we have
not engaged in any price risk management programs or hedges to date and do not
anticipate engaging in those types of transactions in the future.

Insurance

         Through our Manager we obtain hazard, property, general liability and
other insurance in commercially reasonable amounts to cover our projects, as
well as general liability and similar coverage for our business operations.
However, there is no assurance that such insurance will be adequate to protect


                                       8
<PAGE>


us from material losses related to our projects or operations. In addition, the
Manager's practice is to obtain insurance as a package that is intended to cover
most, if not all, of the natural gas and oil projects under its management,
including many projects not owned by us. As a result, given insurance limits, if
significant damages occur in a given year to projects owned by other energy
programs managed by our Manager, the insurance available for potential damages
to our projects in that year could be significantly reduced. Nevertheless, and
despite this risk, we believe that the Manager has obtained adequate insurance
in accordance with customary industry practices although the possibility does
exist that depending on the occurrence, there may not be enough insurance to
entirely cover any losses we sustain.

Salvage Fund

         As to projects in which we own a working interest, we deposit in a
separate interest-bearing account, or a salvage fund, which is in the nature of
a sinking fund, enough money to provide for our proportionate share of the
anticipated gross cost net of anticipated salvage value of dismantling
production platforms and facilities, plugging and abandoning the wells, and
removing the platforms, facilities and wells 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 we
may be liable for such expenses. We have deposited $1 million from capital
contributions into a salvage fund which we estimate to be sufficient to meet our
potential requirements. If management later determines the deposit and earned
interest is not enough to cover our proportionate share of expense, we will
deposit payments from operating income to make up any difference. Any portion of
a salvage fund that remains after we pay our share of the actual salvage cost
will be distributed to the shareholders. There are no legal restrictions on the
withdrawal of the salvage fund.

Employees

         We have no employees. The Manager operates and manages all of our
activities.

Item 1A. Risks
--------------

Risks Related to Oil and Gas Activities

         All of our oil and natural gas activities are subject to risks normally
incident to the exploration for and development and production of natural gas
and crude oil, including:

         Our investment activities have resulted in unsuccessful projects and
our other projects may not be successful. Notwithstanding the best efforts of
the Manager in selecting projects, there is always significant risk that despite
contrary indications, a project will not have commercially productive oil or
natural gas reservoirs. The successful acquisition of producing properties
requires assessment of reserves, seismic and other engineering information,
future commodity prices, operating costs and potential environmental
liabilities. Our assessment of these factors may not be successful. Indeed,
during 2004 and 2005, we invested in three projects that resulted in dry-holes,
meaning that there were either no, or commercially insufficient, quantities of
oil and natural gas. Those dry-holes as well as any future unsuccessful projects
will have an adverse effect on our future operations, financial condition and
cash distribution to shareholders. We have two pending wells, East Breaks 157,
which started drilling in January 2006 and Eugene Island 337.

         Our exploration and production activities are subject to risks that we
can not control and we may have insufficient insurance to cover these risks. To
the extent we are not covered by insurance, we could incur losses and
liabilities which could reduce revenues, increase costs or eliminate dollars


                                       9
<PAGE>


available for future exploration and development programs. Costs of drilling,
completing and operating wells are often uncertain and drilling operations may
be curtailed, delayed or canceled as a result of a variety of factors including:

     o    Fires, explosions, blowouts and cratering
     o    Equipment failures, casing collapse, pipe and cement failures
     o    Marine risks such as capsizing or collisions
     o    Adverse weather conditions, including hurricanes
     o    Shortages or delays in the delivery of equipment
     o    Acts of terrorism
     o    Environmental hazards
     o    Pipeline ruptures and discharge of toxic gases

         Many of the above-mentioned risks could result in damage to life and/or
property or cause sustained interruption of production. In accordance with
customary industry practice, we maintain insurance against some, but not all, of
these risks. Insurance to cover certain of these risks may be prohibitively
expensive or unavailable, particularly with respect to acts of terrorism.
Additionally, insurance coverage may not be sufficient to cover certain
catastrophic events.

         In addition, it is significantly less costly for our insurance to be
acquired and maintained by the Manager as a package intended to cover all of the
natural gas and oil projects under its management. The majority of these
projects are owned by other entities under its management. As a result, given
insurance limits, if significant damage occurs to those other projects in any
given year, the amount of insurance available to cover any damage to our
projects could be significantly reduced.

         Our reserve estimates are inherently uncertain and may be inaccurate
and if so, may adversely affect our revenue and profitability.. There are many
uncertainties inherent in estimating quantities of proved reserves and in
projecting future rates of production and timing of development expenditures,
including many factors beyond our control. Estimates of reserves by necessity
are projections based on engineering and geological data, including but not
limited to volumetrics, reservoir size, reservoir characteristics, the
projection of future rates of production and the timing of future expenditures.
The accuracy of any reserve estimate is a function of the amount and quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates of different engineers normally vary and may not be
accurate. Development of our reserves may not occur as scheduled and the actual
results may not be as estimated.

         In addition, results of drilling, testing and production subsequent to
the date of an estimate may justify revision of such reserve and cost estimate
upward or downward. Accordingly, reserve estimates are often different from the
quantities ultimately recovered. The Manager reviews the reserve estimates
provided by the operators of properties in which we participate and may retain
independent reserve engineers to review such reserve estimates and/or conduct an
independent review, as appropriate. Future performance that deviates
significantly from reserve estimates could have a material effect (positive or
negative) on our operations, business and prospects, as well as on the amounts
of such reserves.

         Moreover, our estimated or proved oil and natural gas reserves and the
estimated future net revenues from such reserves are based upon various
assumptions, including those required by the SEC relating to oil and natural gas
prices, drilling and operating expenses. As a result, we are required to make
assumptions and judgments, all of which can be wrong or inaccurate. Thus, our
estimates are inherently imprecise and the quality and reliability of this
information can vary, perhaps significantly, from actual results.


                                       10
<PAGE>


         Our revenue, profitability and cash flow are highly dependent on the
prices of oil and gas. 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.
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 our
future profitability and, in such an event, we may be required by accounting
rules to write down the carrying value of our Projects.

         We have not engaged in any price risk management programs or hedges to
date and we do not anticipate engaging in those types of transactions in the
future.

         The availability and cost of needed equipment may adversely affect our
profitability and operations. As a result of the increase in natural gas and oil
prices, drilling activity in the Gulf of Mexico has increased significantly.
Drilling rigs and other equipment could become harder to obtain and more costly
to acquire, especially if weather occurrences, such as hurricanes, occur with
frequency in the Gulf of Mexico. Theses circumstances could have a negative
impact on our operations.

         We have invested most of our capital. As a result, we have limited
ability to invest in additional projects. The capital we raised in our private
placement is all the capital we will be able to obtain for investments in
Projects. Given our structure, obtaining traditional financing from public
markets is unlikely and it is not practical to assume we can raise additional
funds through a supplemental offering or through debt financing. As a result, we
have little, if any, ability to grow our business and each of the unsuccessful
projects we have experienced to date not only reduces our ability to generate
revenue, but also exhausts our limited supply of capital.

         We may incur costs to comply with the many environmental and other
governmental regulations that apply to our operations. The oil and gas industry,
in general, and offshore activities, in particular, are subject to numerous
governmental laws and regulations which may affect our ongoing and future
operational decisions and financial results. United States legislation affecting
the oil and gas industry is under constant review for amendment and expansion.
Also, numerous departments and agencies, both federal and state, are authorized
by statute to issue and have issued rules and regulations which, among other
things, require permits for the drilling of wells, impose construction,
abandonment and remediation requirements, prevent the waste of natural gas and
liquid hydrocarbons through restrictions on flaring, require drilling bonds and
regulate environmental and safety matters. Additionally, governmental
regulations may also impact the demand for oil and gas, which could adversely
affect the price at which oil and gas is sold. The regulatory burden on the oil
and gas industry increases its cost of doing business and, subsequently, affects
its profitability. Finally, as additional legislation or amendments may be
enacted in the future, we are unable to predict the ultimate cost of compliance.

         We rely on third parties to operate, manage and maintain our projects
over which we have limited control. Neither we nor our Manager currently own or
have any plans to acquire drilling or production equipment nor do we maintain a
staff of technical employees required for on-site operations. Therefore, we rely
on unrelated third party operators to oversee and/or perform all drilling,
completion and ongoing maintenance and production activities for the projects in
which we participate. As such, we have little or no control over the day-to-day
operations of these projects. However, we have acquired and will continue to
seek projects in which the operators have significant resources, are experienced
in offshore operations and have a long term presence in the Gulf of Mexico.

         We own projects jointly with other companies over whom we have no
control and who may influence the manner in which the project is operated. We
participate in projects as a working interest owner along with other unrelated


                                       11
<PAGE>


third party entities, including the operator. While our Manager may monitor and
participate in decisions affecting exploration and development of the leases or
wells in which we participate, other decisions with respect to lease exploration
and development activities may be controlled by the other participants and could
be unfavorable to us. Finally, we could be held liable for the joint activity
obligations or tortuous actions of the operator or other working interest
owners. If our co-participants fail to pay their portion of the lease
acquisition, drilling and completion or ongoing maintenance costs for any well,
the project may lack sufficient funds to perform such work.

         We face competition. As a small natural gas and oil producer, we face
strong competition in all aspects or our business. Many of our competitors are
large, well-established companies that have significantly larger staffs and have
greater capital resources than we do. These companies may be able to pay more
for a project or sustain losses for a longer period of time than we can.

         We maintain a salvage fund. As indicated above, we have created a
salvage fund to cover certain anticipated salvage costs associated with our
projects. There is no assurance that the salvage fund will have sufficient
assets to meet these requirements, and we may be liable for our percentage share
of unfunded expenses.

Risks related to the nature of our shares.

         Our shares have severe restrictions on transferability and liquidity.
Our shares are illiquid investments. There is currently no market for these
shares. Because there will be a limited number of persons who purchase shares
and because there are significant restrictions on the transferability of such
shares under the LLC Agreement and under applicable federal and state securities
laws, it is expected that no public market will develop. Moreover, neither we
nor our Manager will provide any market for the shares. Shareholders are
generally prohibited from selling or transferring their shares except in the
circumstances permitted under the LLC Agreement, and all such sales or transfers
require our consent, which we may withhold in our sole discretion. Accordingly,
shareholders have no assurance that an investment can be transferred and must be
prepared to bear the economic risk of the investment indefinitely.

         Our shareholders can not participate in our management or operations.
Shareholders have no right, power or authority to participate in our management
or decision making or in the management of our projects. The Manager has the
exclusive right to manage, control and operate our affairs and business and to
make all decisions relating to our operation.

         Our assets will be illiquid. Our interest in projects will be illiquid.
We do not anticipate selling our interests in the projects, or any part thereof.
Even if we elected to sell, it is likely that there will be little or no market
for these assets. However, if we were to attempt to sell any such interest, a
successful sale would depend upon, among other things, the operating history and
prospects for the well or interest being sold, proven oil and gas reserves, the
number of potential purchasers and the economics of any bids made by them and
the current economics of the oil and gas market. In addition, any such sale may
result in adverse tax consequences to the shareholders. The Manager has full
discretion to determine whether any project, or any partial interest, should be
sold. Shareholders have no ability to override the decision of the Manager.
Consequently, shareholders will depend on the Manager for the decision to sell
all or a portion of a project, or retain it, for the benefit of the
shareholders.

         We indemnify our officers and the Manager and its employees for certain
actions taken on our behalf. The LLC Agreement provides that our officers and
agents, the Manager, the affiliates of the Manager and their respective


                                       12
<PAGE>


directors, officers and agents when acting on behalf of the Manager or its
affiliates on our behalf, will be indemnified and held harmless by the
shareholders from any and all claims rising out of our management, except for
claims arising out of the bad faith, gross negligence or willful misconduct or a
breach of the underlying LLC operating agreement. Therefore, we may have
difficulty sustaining an action against the Manager, or its affiliates and their
officers based on breach of fiduciary responsibility or other obligations to the
shareholders.

         The Manager will receive a management fee regardless of our
profitability. The Manager will receive an annual management fee from us
regardless of whether our activities are profitable. The annual fee is equal to
2.5% of total capital contributed by shareholders. Inherent in the fee and
compensation arrangements are the possibility of conflicts between our interests
and the best interests of the Manager. The Manager may have incentive to act in
its best interests rather than in our best interest.

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

         Our Manager will receive cash distributions in addition to its
management fee. The Manager as compensation for its management services will
receive, in addition to its annual management fee, 15% of our cash distributions
to shareholders although it has not contributed any cash to us. Accordingly, our
shareholders contribute all of the cash utilized for our investments and
activities. If we are unsuccessful, the shareholders lose 100% of their
investment.

         Shareholders have limited access to information. Delaware law permits
Delaware limited liability companies to restrict access to certain information
provided that such restricted access is set forth in the LLC Agreement. Our LLC
Agreement contains provisions that limit shareholder access to certain sensitive
or confidential information such as trade secrets, agreements or confidential or
proprietary information. Moreover, shareholder access to information regarding
other shareholders is likewise limited and we may refuse to give shareholder
information, such as name and address, of other shareholders, which could make
it difficult for a shareholder to contact other shareholders. Nevertheless,
shareholders do have access to our tax, other financial information or any other
reasonable information regarding our operations.

         Cash distributions are not guaranteed and may be less than anticipated
or estimated. Distributions depend primarily on our available cash from oil and
gas operations. At times, distributions may be delayed to repay the principal
and interest on our borrowings, if any, or to fund our costs, although we do not
anticipate such borrowings. Our taxable income will be taxable to the
shareholders in the year earned, even if cash is not distributed.

         Our Manager has conflicts of interest in its management of our
operations. Our shareholders will not be involved in the management of our
operations. Accordingly, they must rely on the Manager's judgment in such
matters. Inherent with the exercise of its judgment, the Manager will be faced
with conflicts of interest. While neither we nor the Manager have specific
procedures in place in the event of any such conflicting responsibilities, the
Manager recognizes that it has fiduciary duties to us in connection with its
position and responsibilities as Manager and the Manager intends to abide by
such fiduciary responsibilities in performing its duties. Therefore, the Manager
and its affiliates will attempt, in good faith, to resolve all conflicts of
interest in a fair and equitable manner with respect to all persons affected by
those conflicts of interest. The Manager is not liable to us for how conflicts
of interest are resolved unless it has acted in bad faith, or engaged in gross
negligence or willful misconduct.


                                       13
<PAGE>


Tax risks associated with an investment in our Shares.
------------------------------------------------------

         Although we have received an opinion from our counsel that we would be
classified as a partnership and our shareholders would be treated as limited
partners for federal income tax purposes, we will not obtain a ruling from the
Internal Revenue Service (the "IRS") as to any aspect of our tax status. The tax
consequences of investing in our shares could be altered at any time by
legislative, judicial, or administrative action.

         The IRS may audit our tax returns. Any audit issues will be resolved by
our Manager. If adjustments are made by the IRS, corresponding adjustments will
be required to be made to the federal income tax returns of our shareholders,
which may require payment of additional taxes, interest, and penalties. An audit
of our tax return may result in the examination and audit of a shareholder's
return that otherwise might not have occurred, and such audit may result in
adjustments to items in the shareholder's return that are unrelated to our
operations. Each shareholder bears the expenses associated with an audit of that
shareholder's return.

         In the event that an audit of us by the IRS results in adjustments to
the tax liability of a shareholder, such shareholder will be subject to interest
on the under payment and may be subject to substantial penalties. In addition, a
number of substantial penalties could potentially be asserted by the IRS on any
such deficiencies.

         There can be no assurance that any deductions, credits or other tax
consequences will be available. In addition, no assurance can be given that
legislative or administrative changes or court decisions may not be forthcoming
which would significantly change the tax risks to our shareholders. In some
instances, these changes could have substantial effect on our taxes and those of
our shareholders. Any future legislative changes may or may not be retroactive
with respect to transactions prior to the effective date of such changes. Bills
have been introduced in Congress in the past and may be introduced in the future
which, if enacted, would adversely affect us.

Item 1B. Unresolved Staff Comments
----------------------------------

         None.

Item 2. Properties
------------------

Oil and Gas Exploration and Production Properties and Reserves
--------------------------------------------------------------

         Projects

         As of December 31, 2005, we owned working interests in six offshore
blocks as noted below. Since inception (May 27, 2004), we have participated in
the drilling of five wells, of which three were dry and two were successful. In
addition, one well is currently drilling and another well will begin drilling in
Spring 2006.

Main Pass 155

          The Main Pass 155 Project consisted of ten (10) lease blocks, Main
Pass 154-157, Viosca 338-339 and Chandeleur 43, all of which are located
approximately 46 miles offshore Alabama. In 2005, we participated in an
exploratory well paying 10% of the drilling costs to earn a 7.5% working
interest in these blocks from Samson Offshore Group, the operator. The well was
drilled in June 2005 and targeted the Lower Cretaceous James Lime at
approximately 15,505 feet. The well was drilled and logged. A thick section of
porous but wet James Lime was encountered between 15,100 feet and 15,500 feet.


                                       14
<PAGE>

Interpretation of the 3D data post drilling indicated that the updip porosity
pinchout we were looking for was not sufficient to seal the trap and any
hydrocarbons that migrated through the section leaked out. On July 29, 2005, we
plugged and abandoned the well which had a dry-hole cost of approximately $958
thousand.

         An affiliate, the Ridgewood Energy M Fund, LLC, also participated in
the well to earn a 30% working interest in the Main Pass 155 Project.

South Timbalier 77

         In 2004 we participated in an exploratory test well paying 32% of the
drilling costs on the first well to acquire a 20% working interest in South
Timbalier 77, which was drilled and operated by Millennium Offshore Group
("MOGI") (See Item 1 "Operator") prior to their sale to ATP in November 2005.
ATP is now the owner and operator of both South Timbalier 77 wells #4 and #5.
South Timbalier is located in federal waters approximately 63 miles offshore
Louisiana. To date, two producing wells have been drilled and completed at a
total cost of approximately $8.6 million.

         An affiliate, the Ridgewood Energy N Fund, LLC is also participating in
the two wells on South Timbalier 77 to earn a 30% working interest.

West Cameron 103

         In July 2004, we participated in an exploratory test well paying 26.67%
of the drilling costs to earn a 20% working interest in West Cameron 103. West
Cameron 103 was operated by Gryphon Exploration and is located in federal waters
approximately 12 miles offshore Texas.

           An affiliate, the Ridgewood Energy K Fund LLC, also participated in
the well to earn a 40% working interest.

         The well reached a total depth of 17,510 feet and evaluation of the
wireline log data showed very low resistivity, non-commercial pay through most
of the target sands indicating that the gas had migrated and the trap was not
competent. The presence of residual gas was sufficient enough to give the
amplitude versus offset (AVO) response seen on the 3D seismic data. The well was
non-commercial and was plugged and abandoned on November 6, 2004. Our total
expenditures for West Cameron 556 were approximately $2.8 million.

East Cameron 48

         In 2005, we participated in an exploratory test well paying 40% of the
drilling costs to earn a 25% working interest in East Cameron 48 which covered
portions of East Cameron 47, 48 and 63. The block was operated by Apache
Corporation and is located in federal waters approximately 58.5 miles offshore
Louisiana. The exploratory well targeted sands between 12,600 and 14,500 feet,
and was offset across a fault from a Hunt Oil discovery in the same geologic
section. The prospect was delineated by 3D seismic data. A directional well was
drilled to 12,969 feet and logged in September 2005. The well encountered two
sands in the target interval, each sand being approximately 100-150 feet in
gross thickness. Both sands were wet and the well was plugged and abandoned.
Total expenditures to date were approximately $5.8 million.

East Breaks 157

         In 2005, we agreed to participate in a 12,000 foot exploratory well
paying 10.5% of the drilling costs for the first well to earn a 7% working
interest in East Breaks 157. The lease block is operated by ENI Petroleum and


                                       15
<PAGE>


started drilling in January 2006. This well is located in 940 feet of water and
is off the coast of Texas. Total drilling risk is approximately $1.3 million. If
successful, we have budgeted for a total of four wells and the total budget for
the lease block to date is $7.71 million.

         An affiliate, Ridgewood Energy M Fund, LLC is also participating in
this lease block to earn an 18% working interest in East Breaks 157.

Eugene Island 337

         Eugene Island 337 is a two well prospect located offshore Louisiana. In
September 2005 we agreed to participate in the project which was supposed to
start drilling by December 31, 2005. There was damage on the Eugene Island 330
platform during Hurricane Katrina. This platform was to process our production
if successful. Because of this platform delay, Devon Energy as the operator
postponed the drilling of the well for six to eight months. The initial test
well was to be drilled to 12,860 feet and we agreed to pay 17.6% of the drilling
costs for the first well to earn a 13.33% working interest in the lease block.
To date we have paid a prospect generation fee of $99,000 toward the overall
budget of $5.3 million for Eugene Island 337.

         An affiliate, the Ridgewood Energy M Fund, LLC has also agreed to
participate in the lease block to earn a 20% working interest in this project.

         Drilling Activities. During the periods ended December 31, 2004 and
2005, we expended approximately $6.7 million and $12.8 million, respectively for
exploratory and development activities. We have budgeted an additional $11.6
million for the drilling and completion of the East Breaks 157 and Eugene Island
337 wells.

         Reserve Information. As of December 31, 2005, the Fund's estimated net
total proved developed reserves were 419 thousand cubic feet equivalent (MMCFE),
of which 333 thousand cubic feet (MMCF) were natural gas reserves and 14.5
thousand barrels (MBBLS) were crude oil, condensate and natural gas liquid
reserves (see "Supplemental Information to Consolidated Financial Statements").
At such date, 100% of our reserves were located in United States Offshore and
Texas State waters. MCFE is determined using a ratio of 6.0 thousand cubic feet
(MCF) of natural gas to one barrel (BBL) of crude oil, condensate or natural gas
liquids.

Item 3. Legal Proceedings
-------------------------

          We are currently not a party to any material existing or pending legal
action that would have a material effect on our business, financial condition,
results of operations or liquidity.

Item 4.  Submission of Matters to a Vote of Security Holders
------------------------------------------------------------

         There were no matters submitted to a vote of security holders in 2005.

PART II

Item 5. Market for Registrant's Common Equity Related Stockholder Matters and
-----------------------------------------------------------------------------
Issuer Purchases of Equity Securities
-------------------------------------

         There is currently no established trading market for our shares. The
aggregate capital contributions made were $51,400,840 and as of the date of this
filing, there are 350.1081 shares outstanding. We are not currently offering or
proposing to offer any shares for sale to the public. There are no outstanding
options or warrants to purchase, or securities convertible into shares and we do
not have any equity-based compensation plans. The shares are severely restricted
as to resale.


                                       16
<PAGE>


         Cash distributions to shareholders and the Manager for the year ended
December 31, 2005 were $712,873 and $125,798 respectively. There were no
distributions made in 2004.

Item 6.  Selected Financial Data
--------------------------------

         The following table summarizes certain of our selected financial data
for the year ending December 31, 2005 and the period ended December 31, 2004.
The information for 2004 is from our inception (May 27, 2004). The information
summarized below should be read in conjunction with Management's Discussion and
Analysis of Financial Condition and Results of Operations and our audited
Financial Statements and related Notes.

----------------------------------------------------------------------------
Year Ended December 31                               2005          2004 (1)
----------------------------------------------------------------------------
Statement of Operations Data:
----------------------------------------------------------------------------
Revenues                                      $ 7,837,837       $         -
----------------------------------------------------------------------------
Loss from operations                           (5,465,635)       (5,790,890)
----------------------------------------------------------------------------
Net loss                                       (4,759,364)       (5,685,547)
----------------------------------------------------------------------------
Net loss per share                                (15,926)          (15,839)
----------------------------------------------------------------------------
Number of shares outstanding                     350.1081          350.1081
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Balance Sheet Data:
----------------------------------------------------------------------------
Cash and cash equivalents                      21,964,099        36,362,893
----------------------------------------------------------------------------
Salvage fund                                    1,033,427                 -
----------------------------------------------------------------------------
Oil and gas properties, net                     5,495,700         3,844,685
----------------------------------------------------------------------------
Total assets                                   35,231,843        40,229,806
----------------------------------------------------------------------------
Total current liabilities                         121,162            16,240
----------------------------------------------------------------------------
Total long-term liabilities                       495,150                 -
----------------------------------------------------------------------------
Total members' capital                         34,615,531        40,213,566
----------------------------------------------------------------------------
Total liabilities and members' capital         35,231,843        40,229,806
----------------------------------------------------------------------------

(1) From inception - May 27, 2004

Item 7. Management's Discussion and Analysis of Financial Condition and Results
-------------------------------------------------------------------------------
of Operations
-------------

Overview of Our Business

         We are a small independent natural gas and oil producer. Our primary
investment objective is to generate cash flow for distribution to our
shareholders through participation in oil and natural gas exploration and
development projects in the Gulf of Mexico. We began our operations by offering
our shares in a private offering, which began on July 6, 2004. As a result of
such offering, we raised $51.4 million through the sale of 350.1081 shares of
LLC membership interests. After the payment of $7.8 million in offering fees,
commissions and investment fees to Ridgewood Energy Corporation and
broker-dealers, we retained approximately $43.6 million available for
investment. Since our inception in May of 2004, we have acquired an interest in
six offshore lease blocks and have participated in the drilling of five wells.
As of December 31, 2005, we have two successful wells located in the South
Timbalier 77 block, located offshore Louisiana. During 2004 and 2005, we
invested in three projects that resulted in dry-holes. In total, $9.5 million of
investors' capital has been expended on dry-holes. We have also invested in East
Breaks 157 which is currently drilling and we plan to participate in Eugene
Island 337 which is scheduled to start drilling in Spring 2006. Approximately
$11.6 million is estimated for the future development of these two projects.


                                       17
<PAGE>


         The Manager performs certain duties on our behalf including the
evaluation of potential projects for investment and ongoing administrative and
advisory services associated with these projects. We do not currently, nor is
there any plan to, operate any project in which we participate. The Manager
enters into operating agreements with third-party outside operators for the
management of all exploration, development and producing operations, as
appropriate. As compensation for these above duties, the Manager is paid a
one-time investment fee for the evaluation of projects on our behalf and an
annual management fee for ongoing administrative and advisory duties as well as
reimbursement of expenses. The Manager also participates in our distributions as
additional compensation for its duties. (See also Item 1, Business).

         The following review of operations for each of the two periods ended
December 31 should be read in conjunction with our financial statements and the
notes thereto beginning on page F-1. The financial statements for 2004 reflect
results from May 27, 2004 (Inception) through December 31, 2004.

Results of Operations

         During 2005, our first full year of operations, we had a loss from
operations of $5,465,635 compared to a loss from operations in 2004 of
$5,790,890.

         Operating  Revenues.  Operating  revenues  commenced in August 2005 and
reflect sales of natural gas and oil for five months.

         During 2005, revenues from the sale of natural gas, crude oil and
condensate were $7,837,837; there was no revenue generated in 2004.

--------------------------------------------------------------------------------
Wellhead volume and price statistics for the periods ended December 31, were as
follows:
--------------------------------------------------------------------------------
                                                         2005 (4)          2004
                                                         --------          ----
--------------------------------------------------------------------------------
Natural Gas Volumes (MCF) (1)
--------------------------------------------------------------------------------
         South Timbalier 77                               517,827             -
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
Average Natural Gas Prices ($/MCF) (2)
--------------------------------------------------------------------------------
         Average                                           $13.29             -
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
Crude Oil and Condensate Volumes (BBLS) (1)
--------------------------------------------------------------------------------
         South Timbalier 77                                15,971             -
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
Average Crude Oil and Condensate Prices ($/BBL) (2)
--------------------------------------------------------------------------------
         Average                                           $59.80             -
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
Natural Gas Equivalent Volumes (MCFE) (3)
--------------------------------------------------------------------------------
         South Timbalier 77                               613,652             -
--------------------------------------------------------------------------------

(1) Thousand cubic feet or barrels, as applicable.
(2) Dollars per thousand cubic feet or per barrel, as applicable.
(3)  Thousand  cubic  feet  equivalent  and  includes  natural  gas,  crude oil,
condensate  and natural gas liquids.  Thousand cubic feet  equivalent  (MCFE) is
determined  using a ratio of 6.0 MCF of  natural  gas to 1.0 BBL of  crude  oil,
condensate or natural gas liquids.
(4) Represents approximately five months of production.


                                       18
<PAGE>


         Total wellhead natural gas sales of $6,882,812 and wellhead crude oil
and condensate sales of $955,025 for 2005 represents five months of production
from the South Timbalier #4 and #5 wells. There was no production in 2004.

         Natural gas volumes of 517,827 MCF and wellhead crude oil and
condensate volumes of 15,971 BBLS represents total volume production since the
well began producing in August. During initial start-up (August and September)
the combined average monthly production was 378,000 MCFE. Since October 2005
production has more than doubled to approximately 986,000 MCFE per month.
Because the South Timbalier project is located off the Eastern shores of
Louisiana our production was not impacted by Hurricane Katrina or Hurricane Rita
where damage to the gas processing infrastructure resulted in many wells being
shut-in.

         The average natural gas price of $13.29 per MCF and average crude oil
and condensate price of $59.80 per barrel for 2005 were favorably impacted by
the hurricane activity in the Gulf. In some instances the hurricanes have
delayed the production of gas and the recognition of revenue, which has combined
to dramatically raise gas prices over the short-term. Compared with year-end
2004 market prices of $6.70 per MCF and $37.46 per BBLS, the average market
prices of natural gas and crude oil and condensate in 2005 have increased 98%
and 60%, respectively. The dramatic price increases seen for natural gas are a
result of supply and demand. Unlike the situation with crude oil, which can be
readily stored in bulk for long periods of time and is relatively easy to
import, there is not enough of a National Gas Reserve to turn to when shortages
arise. Natural gas demand continues to exceed supply and there is little chance
of increasing supply in the near-term regardless of any further increases in the
natural gas price. Because the supply cannot increase for many years, the price
remains high due to the market driven mechanism for rationing the tight
supplies.

         Operating and Other Expenses

         Certain costs of operations can be compared more effectively when
presented on a per-unit basis. The following table summarizes these costs per
MCFE for the periods ended December 31:

         ------------------------------------------------
                                            2005    2004
         ------------------------------------------------
         Lease Operating Expense           $0.40     $ -
         ------------------------------------------------
         D&A                               $8.10     $ -
         ------------------------------------------------

         Lease Operating Expenses. Lease operating expenses are the day-to-day
costs incurred related to the ongoing operations and maintenance of wells and
related facilities. These costs include lease operating expenses, transportation
expense, work-over expenses, if any, as well as well control insurance and
certain other items, as applicable. All properties in which we participate are
operated by third parties, with whom we have contractual agreements. Lease
operating expenses totaled $248,498 for 2005.

          Depletion and Amortization. Depletion and amortization ("D&A") refer
to the systematic expensing of the capital costs related to the acquisition,
exploration and development of natural gas and oil. We incurred D&A expense in
the amount of $4,969,587 in 2005.

         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
natural gas or oil in sufficient quantities to justify completion of the well.
In 2005, dry-holes costs were $6,658,246, an increase of $3,677,518 from the
$2,880,728 of dry-hole costs recorded in 2004. See Item 2, Properties.


                                       19
<PAGE>


Dry-hole costs for the periods ended December 31 were as follows:

         -----------------------------------------------------------------------
                                                         2005              2004
                                                         ----              ----
         -----------------------------------------------------------------------

         -----------------------------------------------------------------------
         East Cameron 48                           $5,786,386        $        -
         -----------------------------------------------------------------------
         Main Pass 155                                957,839                 -
         -----------------------------------------------------------------------
         West Cameron #103                            (85,979)        2,880,728
         =======================================================================
                  Dry Hole Costs                   $6,658,246        $2,880,728
         -----------------------------------------------------------------------

         General and Administrative Expenses.

General and administrative expenses for the periods ended December 31 were as
follows:
         ----------------------------------------------------------------------
                                                           2005          2004
                                                           ----          ----
         ----------------------------------------------------------------------

         ----------------------------------------------------------------------
         Investment fees                              $        -    $2,315,967
         ----------------------------------------------------------------------
         Management fees                               1,285,027       549,306
         ----------------------------------------------------------------------
         Accounting and legal fees                        98,240        26,240
         ----------------------------------------------------------------------
         Insurance                                        33,758        15,877
         ----------------------------------------------------------------------
         Accretion expense                                 9,113             -
         ----------------------------------------------------------------------
         Other general and administrative expenses         1,003         2,772
         ======================================================================
                                                      $1,427,141    $2,910,162
         ----------------------------------------------------------------------

         The Manager is paid a one time investment fee of 4.5% of initial
capital contributions. Fees are payable for services of investigating and
evaluating investment opportunities and effecting transactions when the capital
contribution is made. Investment fees of $2,315,967 were paid in 2004.

         Management fees are charged to cover those expenses associated with
overhead, including payroll and benefits for employees, rent and other
administrative costs incurred by the Manager for its on-going management,
administrative and advisory services. For such services, the Manager receives an
annual management fee, payable monthly, of 2.5% of total capital contributions.
Management fees were $1,285,027 in 2005 compared to $549,306 for 2004. The
increase is a result of twelve months of fees paid in 2005 as compared to only
six months in 2004.

         Accounting and legal fees and insurance expenses represent those costs
specifically identifiable or allocable to us. The increase in accounting and
legal fees is due to the additional review and audit procedures required for SEC
reporting requirements as compared to 2004. Insurance expense represents
premiums related to the directors and officers liability policy and is allocated
by the Manager to the fund based on total capital raised.

Other Income

         Interest income increased from $105,343 in 2004 to $706,271 in 2005
representative of higher interest rates on larger average cash balances in 2005.


Capital Resources and Liquidity

         The primary sources of our cash during the periods from inception
through December 31, 2005 included the initial net cash contribution of $51.4
million obtained from our private offering and $8.5 million total revenue and
interest income. Primary cash outflow included funds used for operation,
exploration and development expenditures and the payment of distributions to
shareholders. We had a cash balance of $21.9 million at December 31, 2005 and
$36.4 million at December 31, 2004.


                                       20
<PAGE>


The following table reflects inception-to-date actual sources and uses of our
cash:

         -----------------------------------------------------------------
         Sources and Uses of Cash (In Millions)
         -----------------------------------------------------------------

         -----------------------------------------------------------------
         Initial private placement                                  $51.4
         -----------------------------------------------------------------
         Fees (1)                                                    (7.8)
         =================================================================
         Net proceeds                                                43.6
         -----------------------------------------------------------------
         Revenues                                                     7.8
         -----------------------------------------------------------------
         Interest income                                              0.7
         =================================================================
         Total Available Cash                                        52.2
         -----------------------------------------------------------------

         -----------------------------------------------------------------
         Exploration and development expenditures                   (19.5)
         -----------------------------------------------------------------
         Management fee                                              (1.8)
         -----------------------------------------------------------------
         Expenses (LOE, G&A, etc.)                                   (0.4)
         -----------------------------------------------------------------
         Distributions                                               (0.8)
         -----------------------------------------------------------------
         Net Receivable                                              (6.8)
         -----------------------------------------------------------------
         Salvage Fund                                                (1.0)
         -----------------------------------------------------------------
              Cash and cash equivalents                              21.9
         -----------------------------------------------------------------
         Funds for future project development                       (11.6)
         =================================================================
         Available uninvested capital at December 31, 2005          $10.3
         -----------------------------------------------------------------

    (1)  Includes  syndication costs of $5.5 million and one-time investment fee
         paid to the Manager of $2.3 million.

         In 2005, we generated $0.4 million from operating activities compared
to a net operating cash outflow of $2.8 million in 2004. The major component of
the cash outflow in 2004 was the one-time investment fee paid of $2.3 million
plus various other general and administrative expenses. Operating cash flows for
2005 represents revenues generated from oil and gas sales less lease operating
expenses and other general and administrative expenses.

         Net investing cash outflows of $13.8 million in 2005 increased $7.1
million as compared to 2004 due to a significant increase in the amount of
capital expended related to dry-holes. During 2004 we invested cash in two
projects, one of which was determined to be a dry-hole. In 2005 we invested an
additional $4.7 million in the South Timbalier 77 lease block, expended $6.7
million related to dry- hole properties and invested an additional $1.4 million
in exploratory drilling costs related to the East Breaks 157 project.
Additionally $1.0 million was transferred to an interest bearing salvage fund
account.

         We have deposited $1 million from capital contributions into a salvage
fund which we estimate to be sufficient to meet our share of the anticipated
costs in the dismantling of production facilities, the plugging and abandoning
of wells and the removing of any equipment in accordance with applicable federal
and state laws and regulations.

         Cash used in financing activities in 2005 totaled $0.8 million compared
to $45.9 million of cash generated from financing activities the previous year.
In 2004, we generated cash contributions from shareholders of $51.4 million net
of syndication costs of $5.5 million. In 2005, we made distributions to
shareholders of $0.7 million and distributed $0.1 million to the Manager. The


                                       21
<PAGE>


Manager may distribute available cash from operations (as defined in the LLC
Agreement) including cash received for net operating revenues net of lease
operating expenses and other cash expenditures and net reserves designated for
operating expenses, plug and abandonment costs, and certain other contingent
liabilities.

Exploration and Development Expenditures

         The below chart is a summary of our investments detailing the drilling
risk and the actual dollars spent on each well. The total spent on producing
properties shows the completion and facilities costs in addition to the drilling
risk money. The total spent on dry-holes represents the total amount spent on
each well and written off.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
          Lease Block             Working    Operator      Offshore        Target         Drilling       Total Spent
                                  Interest               Location in        Depth          Risk(b)       12/31/05 (c)
                                                        Gulf of Mexico                 ($ in millions) ($ in millions)
---------------------------------------------------------------------------------------------------------------------
<S>                                 <C>         <C>           <C>         <C>               <C>              <C>
Producing
---------------------------------------------------------------------------------------------------------------------
South Timbalier 77 #4                20%         ATP           LA         15,470'           $4.4             $6.1
---------------------------------------------------------------------------------------------------------------------
South Timbalier 77 #5                20%         ATP           LA         12,612'             .9              2.5
---------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------------------
Dry Holes (a)
---------------------------------------------------------------------------------------------------------------------
East Cameron 48                      25%         Apache        LA         14,329'            6.5              5.8
---------------------------------------------------------------------------------------------------------------------
Main Pass 155                       7.5%         Samson        AL         15,500'             .9               .9
---------------------------------------------------------------------------------------------------------------------
West Cameron 103                     20%         Gryphon       LA         17,500'            2.3              2.8
---------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------------------
Drilling/To be Drilled
---------------------------------------------------------------------------------------------------------------------
East Breaks 157                       7%         ENI           TX         12,000'            1.3              1.3
---------------------------------------------------------------------------------------------------------------------
Eugene Island 337                 13.33%         Devon         LA         12,860'            2.4               .1
---------------------------------------------------------------------------------------------------------------------
</TABLE>


     (a)  Dry hole costs represent wells that have been drilled but do not have
          commercially productive oil and/or gas reservoirs. See Item 2,
          Properties.
     (b)  Drilling risk represents the potential dry-hole costs, leasehold costs
          or sunk costs including promote for project participation per AFE's.
     (c)  Total Spent includes development money, i.e. completion and facilities
          costs on wells that are deemed commercially productive.
     o    In addition to reaching target depth, South Timbalier 77 found a
          couple of productive intervals between 10,200' and 10,600' on the way
          to the target depth.

          An affiliate, Ridgewood Energy N Fund, LLC has a 30% working interest
          in the South Timbalier 77 project.

          An affiliate, Ridgewood Energy M Fund, LLC had a 30% working interest
          in the Main Pass 155 which has been deemed a dry- hole.

          An affiliate, Ridgewood Energy K Fund, LLC had a 40% working interest
          in West Cameron 103 which has been deemed a dry- hole.

          An affiliate, Ridgewood Energy M Fund, LLC has an 18% working interest
          in East Breaks 157 which is now drilling.

          An affiliate, Ridgewood Energy M Fund LLC has a 20% working interest
          in Eugene Island 337 which will be drilled in the Spring of 2006.


                                       22
<PAGE>


         The table below sets out actual exploration and development capital
expenditures for the periods ending December 31, 2005 and 2004 along with
estimated budgeted amounts for future periods (dollars in thousands):

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
Expenditure Category                                           Actual             Budget (1)
---------------------------------------------------------------------------------------------
                                                         2004(2)         2005           2006
---------------------------------------------------------------------------------------------
<S>                                                   <C>            <C>         <C>
Capital
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Exploration
---------------------------------------------------------------------------------------------
         Property Acquisition Costs                   $1,441,757     $579,884    $         -
---------------------------------------------------------------------------------------------
         Exploratory Drilling Costs                    2,402,928      840,000      2,110,000
=============================================================================================
Total Exploration                                      3,844,685    1,419,884      2,110,000
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Development
---------------------------------------------------------------------------------------------
         Developmental Drilling Costs                          -    4,714,681      9,491,000
=============================================================================================
Total Development                                              -    4,714,681      9,491,000
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Total Capital Expenditures                             3,844,685    6,134,565     11,601,000
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
Dry-Hole Costs                                         2,880,728    6,658,246              -
=============================================================================================

---------------------------------------------------------------------------------------------
Capital Expenditures for Oil and Gas Properties      $ 6,725,413  $12,792,811    $11,601,000
=============================================================================================
</TABLE>

(1) Budget amounts assume that the wells are commercially successful. If any of
the budgeted exploratory projects are unsuccessful, budgeted development capital
will be reallocated to one or more new unspecified projects.
(2) From Inception - May 27, 2004.

         Although SEC reporting only considers proven reserves, we consider
probable and possible reserves when making investment decisions and when
estimating future cash flow. The chart below represents undiscounted proven,
probable and possible reserves as determined by an independent engineering firm
for our producing properties.

         --------------------------------------------------------------------
         Producing Properties                         12.31.05 Future
                                                   Est. Revenue to L Fund
         --------------------------------------------------------------------

         --------------------------------------------------------------------
         ST 77 #4
         --------------------------------------------------------------------
         Proved                                                   $3,394,903
         --------------------------------------------------------------------
         Probable                                                  6,870,173
         ====================================================================
                                                                 $10,265,076
         --------------------------------------------------------------------
         ST 77 #5
         --------------------------------------------------------------------
         Proved                                                   $2,094,214
         --------------------------------------------------------------------
         Probable                                                  1,917,491
         --------------------------------------------------------------------
         Possible                                                    189,800
         ====================================================================
                                                                  $4,201,505
         --------------------------------------------------------------------

              A. Gas prices for ST 77 average $10.00 for 2006 and $9.00 for 2007
and $8.00 thereafter.


                                       23
<PAGE>


         We have invested most of our capital. As a result we have limited
ability to invest in new projects. However, in addition to available uninvested
capital of $10.3 million on our sources and use of cash chart, should East
Breaks not be successful, $6.4 million of the budgeted completion costs will
become available for re-investment. As well, if Eugene Island 337 is not drilled
$5.3 million would increase the uninvested capital and if it is drilled but
unsuccessful the budgeted completion costs of $2.9 million would increase the
uninvested capital balance.

Off-Balance Sheet Arrangements

         We have no off-balance sheet arrangements as of December 31, 2005 and
do not anticipate the use of such arrangements in the future.

Contractual Obligations

         We have no known contractual obligations as of December 31, 2005.

Summary of Critical Accounting Policies

         We prepare our financial statements and the accompanying notes in
accordance with accounting principles generally accepted in the United States of
America, which require management to make estimates and assumptions about future
events that affect the reported assets and liabilities and the reported amounts
of revenue and expenses during the reporting period. We identify certain
accounting policies as critical, based on, among other things, their impact on
our financial condition, results of operations or liquidity, and the degree of
difficulty, subjectivity and complexity in their deployment. Critical accounting
policies cover accounting matters that are inherently uncertain because future
resolution of such matters is unknown. Management routinely discusses the
development, selection and disclosure of each of the critical accounting
policies. Following is a discussion of our most critical accounting policies:

         Proved Oil and Gas Reserves

         Proved reserves represent estimated quantities of natural gas, crude
oil and condensate that geological and engineering data demonstrate, with
reasonable certainty, to be recoverable in future years from known reservoirs
under economic and operating conditions existing at the time the estimates are
made. 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. The process of
estimating quantities of natural gas, crude oil and condensate reserves is very
complex, requiring significant decisions in the evaluation of all available
geological, geophysical, engineering and economic data. The data for any given
reservoir also may change over time as a result of numerous factors including,
but not limited to, additional development activity, evolving production history
and continual reassessment of the viability of production under varying economic
conditions. Consequently, material revisions (upward or downward) to existing
reserve estimates may occur from time to time. Our reserve quantities are
prepared annually by an independent engineering firm. See the Supplemental
Information (unaudited) in our financial statements for reserve data related to
our properties.

         Oil and Gas Properties

         We use the successful efforts method of accounting for our oil and gas
producing activities. Acquisition costs are capitalized when incurred. Other oil
and gas exploration costs, excluding the costs of drilling exploratory wells,
are charged to expense as incurred. The costs of drilling exploratory wells are
capitalized pending determination of whether the wells have discovered proved


                                       24
<PAGE>


commercial reserves. If proved commercial reserves have not been found, such
drilling costs are expensed. If commercial quantities of reserves are found,
costs remain capitalized. Costs to develop proved reserves, including the costs
of all development wells and related facilities and equipment used in the
production of natural gas and crude oil, are capitalized. Expenditures for
ongoing repairs and maintenance of producing properties are expensed. Upon the
sale or retirement of a proved property, the cost and related accumulated
depletion and amortization are eliminated from the property accounts, and the
resultant gain or loss is recognized. On the sale or retirement of an unproved
property, gain or loss on the sale is recognized, taking into consideration the
amount of any recorded impairment if the property had been assessed for
impairment. It is not the Manager's intention to sell any of the Fund's property
interests.

         Depletion and Amortization for Oil and Gas Properties

         Depletion and amortization of the cost of proved oil and gas properties
are calculated using the units-of-production method. Proved developed reserves
are used as the base for depleting the cost of successful exploratory drilling
projects and development costs. The base used to calculate depletion and
amortization is the sum of proved developed reserves and proved undeveloped
reserves for leasehold acquisition costs, the costs to acquire proved properties
and platform and pipeline costs. Estimated future dismantlement, restoration and
abandonment costs, net of salvage values, are taken into account and will be
adjusted each year as additional information becomes available. Depletion and
amortization rates are updated quarterly to reflect the addition of capitalized
costs, property acquisitions or dispositions, and impairments; reserve additions
and revisions are updated annually. The quantities of estimated proved oil and
gas reserves are a significant component of our calculation of depletion and
amortization and revisions in such estimates may alter our future expense.
Holding all other factors constant, if reserves are revised upward or downward,
earnings will increase or decrease, respectively.

         Impairments

         An impairment analysis is performed when events or changes in
circumstances occur which indicate that an oil and gas asset's carrying value
may not be recoverable. The determination of whether impairment has occurred is
made by comparing the carrying value of the asset 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 undiscounted cash
flows attributable to the asset or the estimated fair value of the asset.

         Gas Imbalances

         Oil and gas sales are recognized when delivery is made by the operator
to the purchaser and title is transferred. The actual volume of gas sold may
differ from the volume of gas to which we are entitled. We will account for such
gas production imbalances by the entitlements method. Under the entitlements
method, we will record as revenues our entitled share of the total gas sold
during the period. We will record a receivable from or payable to other working
interest owners for the value of any under or overproduction, respectively. As
of December 31, 2005 and 2004, there were no gas-balancing arrangements.

         Asset Retirement Obligations

         For proved oil and gas properties, we have obligations to perform
certain removal and remediation when the asset is retired. SFAS 143 requires
that we estimate the future cost of this obligation, discount it to its present
value, and record a corresponding asset and liability on our balance sheet. The


                                       25
<PAGE>


values ultimately derived are based on many significant estimates, including the
expected future costs of this obligation, the future date of the required cash
payment, and interest and inflation rates. Any revisions to these estimates will
result in an adjustment to the carrying value of the capitalized asset and
corresponding liability on a prospective basis.

         Authorization for Expenditures

         Authorization for Expenditures ("AFE's") represents the operator's
estimated budget for the cost of drilling or completing a well. AFE's are
supplied to the working interest owners by the operator for review and
acceptance before work has begun on a project. At times, operators may require a
cash advance for our proportionate share of the AFE before beginning work. As
the actual costs are incurred, they are offset against the prepaid AFE.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk
--------------------------------------------------------------------

         We do not currently have, or use, any derivative instruments nor do we
have any plans to enter into such derivatives. We will generally invest cash
equivalents in high-quality credit instruments consisting primarily of money
market funds, Bankers acceptance notes and government agency securities with
maturities of 180 days or less. We do not expect any material loss from cash
equivalents and therefore believe that potential interest rate exposure is not
material. We have no plan to conduct any international activities and therefore
believe we are not subject to foreign currency risk.

         The principal market risk to which we are exposed that may adversely
impact our results of operations and financial position is changes in oil and
gas prices.

         Our revenue is sensitive to changes in the price received for oil and
gas production. Prevailing market prices fluctuate in response to many factors
that are outside of the Fund's control such as the supply and demand for oil and
gas. Availability of alternative fuels as well as seasonal risks associated with
hurricanes can also impact the supply and demand.

         High oil and gas prices have resulted in a strong demand for and a
tight supply of drilling rigs necessary to drill new wells. The increased cost
in daily rig rates could have a negative impact on the return to our investors.
Any shortage of drilling rigs could delay the employment of capital to such
projects and thus delay revenue from operations.

Item 8.  Financial Statements and Supplementary Data
----------------------------------------------------

       See Item 15

Item 9.  Changes in and Disagreements with Accountants on Accounting and
------------------------------------------------------------------------
Financial Disclosure
--------------------

         None.

Item 9A.  Controls and Procedures
---------------------------------

         Disclosure Controls and Procedures. Our Chief Executive Officer and
Chief Financial Officer, have evaluated the effectiveness of our disclosure
controls and procedures as defined in Rules 13a-15(e) of the Securities and
Exchange Act of 1934, as amended ("Exchange Act") as of December 31, 2005
("Evaluation Date"). Based on this evaluation, our Chief Executive Officer and
the Chief Financial Officer have concluded that our disclosure controls and
procedures were effective as of the Evaluation Date to ensure that information
that is required to be disclosed by us in the reports we file or submit under
the Exchange Act is recorded, processed, summarized and reported, within the
time periods specified in the SEC's rules and forms.


                                       26
<PAGE>


         Changes to Internal Controls. There have been no changes in our
internal control over financial reporting during the fiscal quarter ended
December 31, 2005 that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.

Item 9B.  Other Information
---------------------------

         None.

PART III

Item 10.  Directors and Executive Officers of the Registrant
------------------------------------------------------------

         Ridgewood Energy Corporation, our Manager, is controlled by Robert E.
Swanson, who is the manager, chairman, and, together with his family trusts,
owns all of the membership interests of the Manager. The officers of the Manager
are also our officers. Our Manager takes all actions necessary to manage our
business affairs. We do not have a board of directors nor an audit committee or
nominating committee as contemplated by the Sarbanes-Oxley Act of 2002. Instead,
the Manager effectively performs the functions that the board of directors or
the audit or nominating committee would otherwise perform.

         The Manager has direct and exclusive discretion in management and
control of our affairs. The Manager may resign as Manager only (i) with cause
(which cause does not include the fact or determination that continued service
would be unprofitable to the Manager), or (ii) without cause with the consent of
a majority in interest of the Investors. The Manager may be removed as manager
as provided in our LLC Agreement.

         Ridgewood Energy Corporation was incorporated in October 1982 as a
Delaware corporation for the primary purpose of acting as a manager of the
business of funds and as a managing general partner of limited partnerships. All
of the equity in the Manager is owned by Mr. Swanson or by family trusts. Mr.
Swanson has the power on behalf of those trusts to vote or dispose of the
membership equity interests owned by them.

         The Manager has also organized affiliated funds as Delaware limited
partnerships or Delaware limited liability companies. Ridgewood Energy also
manages those affiliated natural gas and oil funds. The business objectives of
these other funds are similar to our objectives.

         The Manager is an affiliate of Ridgewood Renewable Power, LLC
("Ridgewood Power"), which organizes and operates Delaware business trusts and
limited liability companies that have invested in independent renewable electric
power project and other related activities. Other affiliates of the Manager
include Ridgewood Securities LLC ("Ridgewood Securities"), an NASD member which
has been the placement agent for the private placement offerings of the funds
sponsored by the Manager and the funds sponsored by Ridgewood Power; Ridgewood
Capital Management LLC ("Ridgewood Capital"), which assists in offerings made by
the Manager and which is the sponsor of four privately offered venture capital
funds; and Ridgewood Power Management, LLC, which operates the power projects
owned by the trusts and funds managed by Ridgewood Power. Each of these
companies is controlled by Robert E. Swanson, who is their sole director or
manager.


                                       27
<PAGE>


         Our executive officers, as well as those of REC, and their ages at
December 31, 2005, are as follows:

Name, Age and Position with Registrant                      Officer Since
--------------------------------------                      -------------

Robert E. Swanson, 58
President and Chief Executive Officer                       1982*

W. Greg Tabor, 45
Executive Vice President and Director of Business
Development                                                 January 2004

Robert L. Gold, 46
Executive Vice President                                    1987

Kathleen P. McSherry, 40
Senior Vice President and Chief Financial Officer           2000

Daniel V. Gulino, 44
Senior Vice President and General Counsel                   2003

Mary Lou Olin, 51
Vice President and Secretary                                1982*

*Each officer has served as an executive officer of the Fund since its
inception.

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

Robert E. Swanson has served as the President, Chief Executive Officer and sole
director of Ridgewood Energy since its inception and sole stockholder of
Ridgewood Energy since its inception. Mr. Swanson is also the controlling member
of Ridgewood Power, and Ridgewood Capital. Mr. Swanson has been President and
registered principal of Ridgewood Securities 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 bars, the Association of the Bar of
the City of New York and the New York State Bar Association. He is a graduate of
Amherst College and Fordham University Law School.

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

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

Kathleen P. McSherry has served as the Senior 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 CFO 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.


                                       28
<PAGE>


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 RPM, Ridgewood Power and Ridgewood Capital and
has done so since 2000. Mr. Gulino is a member of the New Jersey State Bar and
the Pennsylvania State Bar. He is a graduate of Fairleigh Dickinson University
and Rutgers School of Law.

Mary Lou Olin has served as the Vice President and Secretary of Ridgewood Energy
since its inception. Ms. Olin has been a Vice President RPM, and Ridgewood
Capital Management, LLC since their inception. Ms. Olin has a Bachelor of Arts
degree from Queens College.

         Pursuant to the LLC Agreement, the Manager has appointed our officers
to act on our behalf and sign documents on our behalf as authorized by the
Manager. Mr. Swanson serves as our Chairman and our other executive officers are
identical to those of the Manager, as indicated in the table immediately above.

         The officers have the duties and powers usually applicable to similar
officers of a Delaware business corporation in carrying out our business.
Officers act under the supervision and control of the Manager, which is entitled
to remove any officer at any time. The Manager expects that most actions taken
in our name will be taken by Mr. Swanson and the other principal officers in
their capacities as our officers under the direction of the Manager rather than
as officers of the Manager.

Section 16(a) Beneficial Ownership Reporting Compliance

         The individuals who are subject to the requirements of Section 16(a)
have complied with those reporting requirements during 2005.

Code of Ethics

         In March 2004, a Code of Ethics was adopted for the Manager, Ridgewood
Power, Ridgewood Capital and for the funds organized and managed by the Manager
and its affiliated entities. The Code of Ethics is applicable to the principal
executive officer, principal financial officer, principal accounting officer or
controller (or any persons performing similar functions), of each such entity. A
copy of the Code of Ethics is being filed as an exhibit to this report. A copy
of the Code of Ethics will be provided to any person without charge, upon
written request made to Ridgewood Energy L Fund, LLC, 947 Linwood Avenue,
Ridgewood, New Jersey 07450 Attn: Daniel V. Gulino.

 Audit Committee Financial Expert.

         We have neither a board of directors nor an audit committee as
contemplated by the Sarbanes-Oxley Act of 2002 and instead, the Manager
effectively performs the functions that the board of directors or the audit
committee would otherwise perform. However, the Manager has determined that
Kathleen P. McSherry, who serves as our Senior Vice President and Chief
Financial Officer and the Chief Financial Officer of the Manager qualifies as an
audit committee financial expert as defined in Item 401(h)(2) of Regulation S-K.

Item 11.  Executive Compensation
--------------------------------

         Other than the management fee, we do not compensate our officers or
those of REC. The Manager, or its affiliates, compensates its officers without
any additional payments by us.


                                       29
<PAGE>


Item 12. Security Ownership of Certain Beneficial Ownersand Management and
--------------------------------------------------------------------------
Related Stockholder Matters
---------------------------

         The following table sets forth information with respect to beneficial
ownership of our shares as of December 31, 2005 and 2004 (no person owns more
than 5% of the shares) for:

         - Each executive officer (there are no directors)

         - 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 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,
2005 and December 31, 2004. Other than as set forth below, no officer owns any
of our shares.

<TABLE>
<CAPTION>
                                                                 Number of
Name of beneficial owner                                           shares       Percent
------------------------                                         ---------      -------
<S>                                                                <C>           <C>
Robert E. Swanson (1), President and Chief Executive Officer       .6667          *
Executive officers as a group (1)                                  .6667          *
</TABLE>

* Represents less than one percent.
(1) - Includes shares owned by the spouse of Mr. Swanson.

Item 13. Certain Relationships and Related Transactions
-------------------------------------------------------

         In connection with the sale of shares in 2004, Ridgewood Securities
Corporation, an affiliate of our Manager, earned $716,113 as a placement agent
fee and for commissions. The Manager was paid $2,315,967 in 2004 as an
investment fee for the services of investigating and evaluating projects for
future investment. The Manager was paid $1,801,319 to cover legal and
syndication fees for the organization, distribution and offering expenses.

         The Manager receives an annual management fee equal to 2.5% of total
capital contributions, payable monthly, for general and administrative services
supplied to us. For the periods ending December 31, 2005 and 2004, we paid
management fees totaling $1,285,027 and $549,306, respectively. Additionally,
when distributions are made, the Manager is entitled to a portion of funds
distributed to shareholders. We made no distributions in 2004. In 2005, we made
$838,671 of distributions, of which the 15% paid to the Manager was $125,798.

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

         Available cash from dispositions, as defined in our LLC Agreement, will
be paid 99% to shareholders and 1% to the Manager until the shareholders have
received 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.

         Allocation of profits or losses from the normal course of operations of
our wells shall be allocated 85% to shareholders and 15% to the Manager. The
primary exception to this treatment is that all items of expense, loss,
deduction and credit attributable to the expenditure of shareholders' capital
contributions are allocated 99% to shareholders and 1% to the Manager.


                                       30
<PAGE>


         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. As of December 31, 2005 we owed the Manager $5,583. As of December 31,
2004 no amounts were outstanding.

         We have co-invested with similar affiliated natural gas and oil funds,
which are also managed by our Manager to acquire and develop oil and gas
projects. See Item 2, Properties.

Item 14.  Principal Accountant Fees and Services
------------------------------------------------

         For the year ended December 31, 2005, Perelson Weiner LLP billed us
$92,240 for professional services of which $12,240 related to preparation of our
tax returns and $80,000 related to the audit of our financial statements in our
Annual Report on Form 10-K and for related services relating to our Registration
Statement on Form 10 and our Quarterly Reports on Form 10-Q. From inception
through December 31, 2004, Perelson Weiner LLP billed us $32,240 for
professional services, of which $12,240 related to the preparation of our tax
returns and $20,000 related to the audit of our financial statements as filed
with our Registration Statement on Form 10.

         Because we do not have an audit committee in the traditional sense, all
services provided to us by Perelson Weiner LLP were approved by the appropriate
senior management of the Manager, including, but not limited to, the Manager's
Chief Executive Officer and Chief Financial Officer.

PART IV

Item 15.  Exhibits and Financial Statement Schedules
----------------------------------------------------

1.       Financial Statements
<TABLE>
<CAPTION>
<S>                                                                             <C>
Report of Independent Registered Public Accounting Firm                            F1
Balance Sheets at December 31, 2005 and 2004                                       F2
Statements  of Operations  for the Year Ended  December 31, 2005
    and the period from May 27, 2004  (Inception)  through December 31, 2004       F3
Statements  of Changes in  Members'  Capital  for the Year Ended
    December  31,  2005 and the period  from May 27, 2004 (Inception)
    through December 31, 2004                                                      F4
Statements  of Cash Flows for the Year Ended  December  31, 2005
    and the period from May 27, 2004  (Inception)  through December 31, 2004       F5
Notes to Financial Statements                                                   F6-10
Supplemental Information About Oil and Gas Producing Activities (Unaudited)    F11-13
Quarterly Financial Information (unaudited)                                        32
</TABLE>


                                       31
<PAGE>


             Report of Independent Registered Public Accounting Firm


The Shareholders and Manager
Ridgewood Energy L Fund, LLC


We have audited the accompanying balance sheets of Ridgewood Energy L Fund, LLC
("Fund") as of December 31, 2005 and 2004, and the related statements of
operations, changes in members' capital and cash flows for the year ended
December 31, 2005 and the period May 27, 2004 (inception) through December 31,
2004. These financial statements are the responsibility of the manager of the
Fund. Our responsibility is to express an opinion on these financial statements
based on our audits.

We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by the manager, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Fund as of December 31,
2005 and 2004 and the results of its operations and its cash flows for the year
ended December 31, 2005 and the period May 27, 2004 (inception) through December
31, 2004 in conformity with accounting principles generally accepted in the
United States of America.



/s/ Perelson Weiner LLP
-----------------------


New York, New York
March 3, 2006





                                       F1
<PAGE>


                          RIDGEWOOD ENERGY L FUND, LLC
                                 BALANCE SHEETS
<TABLE>
<CAPTION>
                                                                           December 31,
                                                             ---------------------------------------
                                                                 2005                       2004
                                                             ------------              ------------
                        ASSETS
<S>                                                          <C>                       <C>
Current assets:
        Cash and cash equivalents                            $ 21,964,099              $ 36,362,893
        Production receivable                                   6,472,470                        --
        Due from operators                                        250,000                        --
        Prepaid expenses                                           16,147                    22,228
                                                             ------------              ------------
               Total current asset                             28,702,716                36,385,121
                                                             ------------              ------------

Salvage fund                                                    1,033,427                        --
                                                             ------------              ------------

Oil and gas properties

        Proved properties                                       9,045,403                        --
        Unproved properties                                     1,419,884                 3,844,685
                                                             ------------              ------------
                                                               10,465,287                 3,844,685
        Less:  accumulated depletion and
           amortization - proved properties                    (4,969,587)                       --
                                                             ------------              ------------

        Oil and gas properties, net                             5,495,700                 3,844,685
                                                             ------------              ------------

               Total assets                                  $ 35,231,843              $ 40,229,806
                                                             ============              ============

           LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
        Due to operator                                      $     74,459              $         --
        Accrued expenses payable                                   41,120                    16,240
        Due to affiliate (Note 6)                                   5,583                        --
                                                             ------------              ------------
               Total current liabilities                          121,162                    16,240

Asset retirement obligations                                      495,150                        --
                                                             ------------              ------------
               Total liabilities                                  616,312                    16,240
                                                             ------------              ------------

Commitment and contingencies (Note 8)

Members' capital:
        Manager:

               Distributions                                     (125,798)                       --
               Accumulated earnings (deficit)                     676,347                  (140,043)
                                                             ------------              ------------
                    Manager's total                               550,549                  (140,043)
                                                             ------------              ------------
        Shareholders:
             Capital contributions (670 shares authorized;
              350.1081 issued and outstanding)                 51,400,840                51,400,840
             Syndication costs                                 (5,501,727)               (5,501,727)
             Distributions                                       (712,873)                       --
             Accumulated deficit                              (11,121,258)               (5,545,504)
                                                             ------------              ------------
                    Shareholders' total                        34,064,982                40,353,609
                                                             ------------              ------------
               Total members' capital                          34,615,531                40,213,566
                                                             ------------              ------------
               Total liabilities and members' capital        $ 35,231,843              $ 40,229,806
                                                             ============              ============
</TABLE>

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


                                       F2
<PAGE>


                          RIDGEWOOD ENERGY L FUND, LLC
                            STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                                                 For the period
                                                                                  May 27, 2004
                                                                                   (Inception)
                                                           Year Ended                through
                                                       December 31, 2005        December 31, 2004
                                                       -----------------        -----------------
<S>                                                    <C>                        <C>
Revenues
     Gas                                               $  6,882,812               $        --
     Oil                                                    955,025                        --
                                                       ------------               -----------
        Total revenues                                    7,837,837                        --
                                                       ------------               -----------

Expenses
     Dry-hole costs                                       6,658,246                 2,880,728
     Depletion and amortization                           4,969,587                        --
     Investment fees (Note 6)                                    --                 2,315,967
     Management fees (Note 6)                             1,285,027                   549,306
     Lease operating expenses                               248,498                        --
     Accounting and legal fees                               98,240                    26,240
     Insurance                                               33,758                    15,877
     Accretion expense                                        9,113                        --
     Other general and administrative expenses                1,003                     2,772
                                                       ------------               -----------
        Total expenses                                   13,303,472                 5,790,890
                                                       ------------               -----------
        Loss from operations                             (5,465,635)               (5,790,890)

Other income
     Interest income                                        706,271                   105,343
                                                       ------------               -----------
        Net loss                                       $ (4,759,364)              $(5,685,547)
                                                       ============               ===========

        Manager - Net income (loss)                    $    816,390               $  (140,043)
        Shareholders - Net loss                        $ (5,575,754)              $(5,545,504)
        Net loss per share                             $    (15,926)              $   (15,839)

</TABLE>

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


                                       F3
<PAGE>


                          RIDGEWOOD ENERGY L FUND, LLC
                    STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

<TABLE>
<CAPTION>
                                                           Year ended                       For the period May 27, 2004 (Inception)
                                                       December 31, 2005                           through December 31, 2004
                                              -----------------------------------------  -------------------------------------------
                                                Manager     Shareholders      Total        Manager      Shareholders       Total
                                              ----------    ------------  -------------   ---------     -------------   ------------

<S>                                           <C>           <C>           <C>               <C>           <C>            <C>
Balances, January 1                            $(140,043)   $ 40,353,609  $ 40,213,566    $      --        $       --    $       --

Shareholders' capital contributions                   --              --            --           --        51,400,840    51,400,840
Syndication costs (included offering fee
   of $1,801,319 paid to the Manager and
   selling commissions and placement fees
   of $201,500 and $514,613, respectively,
   paid to Ridgewood Securities Corp. - Note 6)       --              --            --           --        (5,501,727)   (5,501,727)


Distributions                                   (125,798)       (712,873)     (838,671)          --              --              --

Net income (loss)                                816,390      (5,575,754)   (4,759,364)    (140,043)     (5,545,504)     (5,685,547)
                                               ---------    ------------  ------------    ---------    ------------    ------------

Balances, December 31                          $ 550,549      34,064,982  $ 34,615,531    $(140,043)     40,353,609    $ 40,213,566
                                               =========    ============  ============    =========    ============    ============
</TABLE>

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


                                       F4
<PAGE>


                          RIDGEWOOD ENERGY L FUND, LLC
                            STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
                                                                                                   For the period
                                                                                                    May 27, 2004
                                                                                                     (Inception)
                                                                              Year ended               through
                                                                           December 31, 2005      December 31, 2004
                                                                           -----------------      -----------------
<S>                                                                          <C>                     <C>
Cash flows from operating activities
       Net loss                                                              $ (4,759,364)           $ (5,685,547)
       Adjustments to reconcile net loss to net cash
          provided by (used in) operating activities
          Depletion and amortization                                            4,969,587                      --
          Accretion expense                                                         9,113                      --
          Dry-hole costs                                                        6,658,246               2,880,728
          Interest collected on salvage fund                                      (33,427)                     --
          Changes in assets and liabilities
             Increase in production receivable                                 (6,472,470)                     --
             Increase in due from operator                                       (250,000)                     --
             Decrease (increase) in prepaid expenses                                6,081                 (22,228)
             Increase in due to operator                                           74,459                      --
             Increase in accrued expenses payable                                  24,880                  16,240
             Increase in due to affiliate                                           5,583                      --
                                                                             ------------            ------------
             Net cash provided by (used in) operating activities                  232,688              (2,810,807)
                                                                             ------------            ------------

Cash flows from investing activities
       Capital expenditures for oil and gas properties                        (12,792,811)             (6,725,413)
       Funding of salvage fund                                                 (1,000,000)                     --
                                                                             ------------            ------------
             Net cash used in investing activities                            (13,792,811)             (6,725,413)
                                                                             ------------            ------------

Cash flows from financing activities
       Contributions from shareholders                                                 --              51,400,840
       Syndication costs                                                               --              (5,501,727)
       Distributions                                                             (838,671)                     --
                                                                             ------------            ------------
             Net cash (used in) provided by financing activities                 (838,671)             45,899,113
                                                                             ------------            ------------
             Net (decrease) increase in cash and cash equivalents             (14,398,794)             36,362,893
             Cash and cash equivalents, beginning of period                    36,362,893                      --
                                                                             ------------            ------------
             Cash and cash equivalents, end of period                        $ 21,964,099            $ 36,362,893
                                                                             ============            ============

Supplemental schedule of non-cash investing activity
       Asset retirement cost capitalized                                     $    486,037            $         --
                                                                             ============            ============
</TABLE>

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


                                       F5
<PAGE>


                          RIDGEWOOD ENERGY L FUND, LLC
                     NOTES TO AUDITED FINANCIAL STATEMENTS


1.  Organization and Purpose

The Ridgewood Energy L Fund, LLC ("Fund"), a Delaware limited liability company,
was formed on May 27, 2004 and operates pursuant to a limited liability company
agreement ("Agreement") dated July 1, 2004 by and among Ridgewood Energy
Corporation ("Manager"), and the shareholders of the Fund.

The Fund was organized to acquire, drill, construct and develop natural gas and
oil properties located in the United States offshore waters of Texas and
Louisiana in the Gulf of Mexico. Prior to August 2005, the Fund had not earned
revenue from these operations and was considered in the exploratory stage. The
Fund ceased to be in the exploratory stage during the fourth quarter of 2005 as
South Timbalier 77 began production in August 2005. The Fund has been earning
production revenue from the two wells in South Timbalier 77.

The Manager performs (or arranges for the performance of) the management and
administrative services required for Fund operations. Such services include,
without limitation, the administration of shareholder accounts, shareholder
relations and the preparation, review and dissemination of tax and other
financial information. In addition, the Manager provides office space, equipment
and facilities and other services necessary for Fund operations. The Manager
also engages and manages the contractual relations with outside custodians,
depositories, accountants, attorneys, broker dealers, corporate fiduciaries,
insurers, banks and others as required. (Notes 2, 5 and 6)

2. Summary of Significant Accounting Policies

     Use of Estimates

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

     Oil and gas properties

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

The successful efforts method of accounting for oil and gas producing activities
is followed. Acquisition costs are capitalized when incurred. Other oil and 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. Costs to develop proved reserves,
including the costs of all development wells and related facilities and
equipment used in the production of natural gas and crude oil, are capitalized.
Expenditures for ongoing repairs and maintenance of producing properties are
expensed as incurred.

Upon the sale or retirement of a proved property (i.e. a producing well), the
cost and related accumulated depletion and amortization are eliminated from the
property accounts, and the resultant gain or loss is recognized. On the sale or
retirement of an unproved property, gain or loss on the sale is recognized,
taking into consideration the amount of any recorded impairment if the property
had been assessed for impairment. It is not the Manager's intention to sell any
of the Fund's property interests.


                                       F6
<PAGE>


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

     Revenue Recognition

Oil and gas sales are recognized 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 gas sold by the operator on the Fund's behalf may differ from the
volume of gas the Fund is entitled to. The Fund will account for such 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 the other
working interest owners for volumes oversold by the Fund. For the periods ended
December 31, 2005 and 2004, there were no gas-balancing arrangements between the
Fund and other working interest owners.

     Interest Income

Interest income is recognized when earned.

     Syndication Costs

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.

     Asset Retirement Obligations

For proved oil and gas properties, there are obligations to perform removal and
remediation activities when the properties are retired. The Fund adopted
Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for
Asset Retirement Obligations" in 2004. SFAS No. 143 requires the Fund to record
a separate liability for the discounted present value of the Fund's asset
retirement obligations, with an offsetting increase to the related oil and gas
properties on the balance sheet. As of December 31, 2004, asset retirement
obligations did not have a material effect on the results of operations or
financial position of the Fund. In 2005, the Fund recorded asset retirement
obligations of $495,150 related to its producing properties of which $9,113
represents accretion expense during 2005. There were no asset retirement
obligations settled for the periods ended December 31, 2005 and 2004.

     Impairment of Long-Lived Assets

In accordance with the provisions of SFAS No. 144, "Accounting for the
Impairment of Long-Lived Assets", long-lived assets, such as oil and gas
properties, are evaluated when events or changes in circumstances indicate that
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 assets. The impairment loss recognized is the excess of the carrying
value over the future discounted cash flows attributable to the asset or the
estimated fair value of the asset. No impairment was recorded during 2005 or
2004.

     Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are
calculated using the units of production method. Proved developed reserves are
used as the base for depleting the cost of successful exploratory drilling and
development costs. The sum of proved developed and proved undeveloped reserves
are used as the base for depleting (or amortizing) leasehold acquisition costs,
the costs to acquire proved properties and platform and pipeline costs. For the
year ended December 31, 2005, depletion and amortization totaled $4,969,587.
There was no depletion and amortization for 2004.


                                       F7
<PAGE>


     Income Taxes

No provision is made for income taxes in the financial statements as the income
or losses are passed through and included in the tax returns of the individual
shareholders.

     Cash and cash equivalents / Salvage fund

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. As of December 31, 2005, bank balances
inclusive of the salvage fund exceeded federally insured limits by approximately
$22.8 million. The Fund maintains bank deposits with high quality financial
institutions to mitigate such risk.

     Income and Expense Allocation

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

3.   Recent Accounting Pronouncements

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB
Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations"
(FIN 47). This interpretation clarifies that the term "conditional asset
retirement obligation" as used in SFAS No. 143 refers to a legal obligation to
perform an asset retirement activity in which the timing and/or method of
settlement are conditional on a future event that may or may not be within the
control of the entity incurring the obligation. The obligation to perform the
asset retirement activity is unconditional even though uncertainty exists about
the timing and/or method of settlement. Thus, the timing and/or method of
settlement may be conditional on a future event. Accordingly, an entity is
required to recognize a liability for the fair value of a conditional asset
retirement obligation if the fair value of the liability can be reasonably
estimated. Uncertainty about the timing and/or method of settlement of a
conditional asset retirement obligation should be factored into the measurement
of the liability, rather than the timing of recognition of the liability, when
sufficient information exists. FIN 47 is effective for calendar year-end
entities no later than December 31, 2005. The application of FIN 47 did not have
an impact on the Fund's financial position or results of operations.

In April 2005, the FASB issued FASB Staff Position FAS 19-1, "Accounting for
Suspended Well Costs." The Fund adopted FAS 19-1 during the second quarter of
2005 (Note 4). 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 for impairment of value by
evaluating and monitoring if sufficient progress is made on assessing the
reserves. Capitalized costs are expensed as dry hole costs in the event that
reserves are determined to be not proved. Dry hole costs were $6,658,246 and
$2,880,728 for the year ended December 31, 2005 and the period from May 27, 2004
(inception) to December 31, 2004, respectively.

In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities", ("FIN 46") which changes the criteria by which one
company includes another entity in its consolidated financial statements. FIN 46
requires a variable interest entity to be consolidated by a company if that
company is subject to a majority of the risk of loss from the variable interest
entity's activities or entitled to receive a majority of the entity's residual
returns or both. The consolidation requirements of FIN 46 apply immediately to
variable interest entities created after December 31, 2003, and apply in the
first fiscal period ending after March 15, 2004, for variable interest entities
created prior to January 1, 2004. The Fund adopted the disclosure provisions of
FIN 46 effective May 27, 2004, with no impact to the financial statements. In
December 2003, the FASB issued a revision of FIN 46 ("FIN 46R") to clarify some
of the provisions and to exempt certain entities from its requirements. The Fund
implemented the full provisions of FIN 46R effective May 27, 2004, with no
impact on the financial statements.


                                       F8
<PAGE>


4.   Unproved Properties - Capitalized Exploratory Well Costs

The following table reflects the net changes in capitalized exploratory well
costs for the year ended December 31, 2005 and the period May 27, 2004
(inception) through December 31, 2004.

<TABLE>
<CAPTION>
                                                                                                    For the period
                                                                                                     May 27, 2004
                                                                                                     (Inception)
                                                                                                       through
                                                                                                     December 31,
                                                     Year ended December 31, 2005                        2004
                                                --------------------------------------------------   ------------
                                                    South         East        Eugene                    South
                                                  Timbalier      Breaks       Island                  Timbalier
                                                    #77           157          337        Total          #77
                                                --------------------------------------------------   ------------
<S>                                             <C>          <C>           <C>          <C>          <C>
Balance - beginning of period                   $3,844,685   $        -    $       -    $3,844,685   $          -

Additions to capitalized exploratory well costs
 pending the determination of proved reserves    4,714,680    1,320,884       99,000     6,134,564      3,844,685
Reclassifications to proved properties based
  on the determination of proved reserves       (8,559,365)           -                 (8,559,365)             -
                                                --------------------------------------------------   ------------
Balance - end of period                         $        -   $1,320,884    $  99,000    $1,419,884   $  3,844,685
                                                ==================================================   ============
</TABLE>

Exploratory drilling in South Timbalier #77 commenced in January 2005 and both
wells began producing in August 2005. As of December 31, 2005 and 2004, the Fund
has no capitalized exploratory well costs greater than a year since the drilling
phase has ended.

5.   Distributions

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

The Manager will determine whether Available Cash from Operations, as defined in
the Fund's Operating Agreement, is to be distributed. Such distribution will be
allocated 85% to the shareholders and 15% to the Manager.

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

The Fund made its first distributions in November 2005. Of this distribution,
the 15% paid to the Manager was $125,798. No distributions were paid in 2004.

6.  Transactions with Manager

The Manager is paid an investment fee of 4.5% of initial capital contributions.
Fees are payable for services of investigating and evaluating investment
opportunities and effecting transactions when the capital contribution is made.
For 2004, the Manager was paid investment fees of $2,315,967.

A management 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.
For the year ended December 31, 2005, a management fee of $1,285,027 was
incurred and paid. For 2004, a management fee of $549,306 was incurred and paid.


                                       F9
<PAGE>


The Manager was paid an offering fee which approximated 3.5% of capital
contributions to cover expenses incurred in the offer and sale of shares of the
Fund. Such offering fee was included in syndication costs (Note 2). For 2004,
the Manager was paid an offering fee of $1,801,319.

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. As of December 31, 2005 the Fund owed the Manager $5,583. As of
December 31, 2004, no amounts were outstanding.

In 2004, Ridgewood Securities Corp., a registered broker dealer affiliated with
the Manager, was paid selling commissions and placement fees of $201,500 and
$514,613, respectively, for shares of the Fund sold which are reflected in
syndication costs (Note 2).

The Fund co-invests with affiliated funds managed by the Manager to acquire and
develop oil and gas projects.

7.  Fair Value of Financial Instruments

As of December 31, 2005 and 2004, the carrying value of cash and cash
equivalents, production receivable, salvage fund, due from/to operators and
accrued expenses payable approximate fair value. Cash and cash equivalents
principally consist of money market funds.

8.  Commitment and Contingencies

     Environmental Considerations

The exploration for and development of oil and 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,
earnings or the competitive position of the Fund in the oil and gas industry.
However, due to the significant public and governmental interest in
environmental matters related to those activities, the Manager cannot predict
the effects of possible future legislation, rule changes, or governmental or
private claims. As of December 31, 2005 and 2004, there were no known
environmental issues that required the Fund to record a liability.

     Salvage Fund

Pursuant to the Fund's Operating Agreement, the Fund deposits in a separate
interest-bearing account, or a salvage fund, money to provide for dismantling of
production platforms and facilities, plugging and abandoning the wells and
removing the platforms, facilities and wells after their useful lives have
expired, 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 the withdrawal from the salvage fund.

     Insurance Coverage

The Fund is subject to all risks inherent in the exploration for and development
of oil and 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.


                                      F10
<PAGE>


Supplemental Information About Oil and 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 gas exploration and producing activities of
the Fund. Tables I through III provide historical cost information pertaining to
capitalized costs, costs incurred in exploration, property acquisitions and
development, and results of operations. Tables IV through VI present information
on the Fund's estimated net proved reserve quantities, standardized measure of
estimated discounted future net cash flows related to proved reserves and
changes in estimated discounted future net cash flows.

The Fund is engaged solely in oil and 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  Exploration  and Producing
Activities

<TABLE>
<CAPTION>

                                                                          December 31,
                                                                   -------------------------
                                                                       2005          2004
                                                                   -----------    ----------
<S>                                                                <C>            <C>
Leasehold acquisition costs                                        $ 1,906,894    $       --
Development costs                                                    6,652,472            --
Asset retirement costs                                                 486,037            --
                                                                   -----------     ---------
     Proved oil and gas properties                                   9,045,403            --
                                                                   -----------     ---------
Leasehold acquisition costs                                            579,884     1,441,757
Exploratory drilling costs                                             840,000     2,402,928
                                                                   -----------     ---------
     Unproved oil and gas properties                                 1,419,884     3,844,685
                                                                   -----------     ---------
Accumulated depletion and amortization - proved properties          (4,969,587)           --
                                                                   -----------     ---------
Oil and gas properties, net                                        $ 5,495,700    $3,844,685
                                                                   ===========     =========
</TABLE>


                                      F11
<PAGE>

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

                                                              For the period
                                                               May 27, 2004
                                          Year ended       (inception) through
                                         December 31,          December 31,
                                             2005                 2004
                                         -----------           ----------

Dry-hole costs                           $ 6,658,246           $2,880,728
Developmental drilling costs               4,249,544                   --
Property acquisition costs                 1,045,021            1,441,757
Exploratory drilling costs                   840,000            2,402,928
Asset retirement costs                       486,037                   --
Lease operating costs                        248,498                   --
                                         -----------           ----------
                                         $13,527,346           $6,725,413
                                         ===========           ==========


Table III - Results of Operations for Oil and Gas Producing Activities

<TABLE>
<CAPTION>
                                                                                         For the period
                                                                                          May 27, 2004
                                                                   Year ended         (inception) through
                                                                  December 31,            December 31,
                                                                      2005                   2004
                                                                  ------------            -----------
<S>                                                               <C>                     <C>
Gas revenues                                                      $  6,882,812            $        --
Oil revenues                                                           955,025                     --
                                                                  ------------            -----------
     Total revenues                                                  7,837,837                     --
                                                                  ------------            -----------
Dry-hole costs                                                       6,658,246              2,880,728
Depletion and amortization                                           4,969,587                     --
Lease operating costs                                                  248,498                     --
Accretion expense                                                        9,113                     --
                                                                  ------------            -----------
     Total expenses                                                 11,885,444              2,880,728
                                                                  ------------            -----------
     Results of Operations for Oil and Gas Producing Activities   $ (4,047,607)           $(2,880,728)
                                                                  ============            ===========
</TABLE>


                                      F12
<PAGE>


Table IV - Proved Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by an independent petroleum
engineer as of December 31, 2005. The reserve estimates as of December 31, 2005
were based on estimated future reserves as of September 30, 2005 provided by an
independent petroleum engineer further adjusted for fourth quarter production.
These reserves have been prepared in compliance with the Securities and Exchange
Commission rules based on year-end prices.

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. The fund had no proved
undeveloped reserves at December 31, 2005.

                                                       Year ended
                                                   December 31, 2005
                                                     United States
                                        Oil (BBLS)                Gas (MCF)
                                       ----------------------------------------

Proved developed reserves:
     Beginning of Year                          --                       --
     Discoveries                            30,440                  850,417
     Revisions of previous estimates            --                       --
     Production                            (15,971)                (517,827)
                                       ----------------------------------------
     End of year                            14,469                  332,591
                                       ----------------------------------------

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



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

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

                                                                December 31,
                                                                    2005
                                                                ------------
Future estimated revenues                                       $  4,223,837
Future estimated production costs                                   (422,384)
Future estimated development costs                                  (745,000)
                                                                ------------
               Future net cash flows                               3,056,453
10% annual discount for estimated timing of cash flows              (119,178)
                                                                ------------
Standardized measure of discounted future estimated
net cash flows                                                  $  2,937,275
                                                                ------------


                                      F13
<PAGE>


Table VI - 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.

<TABLE>
<CAPTION>
                                                                                          Year ended
                                                                                       December 31, 2005
                                                                                       -----------------
<S>                                                                                      <C>
Sales of oil and gas production, net of production costs                                 $(7,589,339)
Extensions, discoveries, and improved recovery techniques, less related costs              1,600,389
Development costs incurred during the period                                               9,045,403
Accretion of discount                                                                       (119,178)
                                                                                         -----------
                                                                                         $ 2,937,275
                                                                                         ===========
</TABLE>


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 since the computations are based on a large number of estimates and
assumptions. 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 of demand and
governmental control. Actual future prices and costs are likely to be
substantially different from the current prices and costs 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 limitations inherent therein.


                                      F14
<PAGE>


         Selected Quarterly Financial Data for the year ended December 31, 2005
and the period from May 27, 2004 (Inception) through December 31, 2004
(unaudited).

<TABLE>
<CAPTION>
                                                                             2005
                                         ----------------------------------------------------------------------------
                                         First Quarter       Second Quarter        Third Quarter       Fourth Quarter
                                         -------------       --------------        -------------       --------------
<S>                                           <C>                <C>                 <C>                  <C>
Revenues                                            --                   --           $1,674,509           $6,163,328
Income(loss) from operations                  (337,358)          (1,340,972)          (4,626,822)             839,517
Net  income(loss)                             (231,417)          (1,121,472)          (4,439,066)           1,032,591

                                                                             2004
                                         ----------------------------------------------------------------------------
Revenues                                            --                   --                   --                   --
Loss from operations                                --                   --           (2,439,751)          (3,351,139)
Net  loss                                           --                   --           (2,403,637)          (3,281,910)

</TABLE>

Revenue began in Q3 05 when the two South Timbalier wells came on production. As
production and price increased, so did Q4 05 revenue.


                                      32
<PAGE>


         2.       Exhibits

         Exhibit No.       Description
         -----------       -----------

         3(i)(A)           Articles of Formation of Registrant  (incorporated by
                           reference to Exhibit 3.1 of Registrant's Registration
                           Statement on Form 10-12 G/A filed with the Commission
                           on September 2, 2005.)

         3(i)(B)           Limited  Liability  Company  Agreement of  Registrant
                           (incorporated   by   reference  to  Exhibit  10.1  of
                           Registrant's  Registration Statement on Form 10-12G/A
                           filed with the Commission on September 2, 2005.)

         10.1              Registrant's Confidential Private Offering Memorandum
                           (incorporated   by  reference  to  Exhibit  10.1A  of
                           Registrant's  Registration Statement on form 10-12G/A
                           filed with the Commission on September 2, 2005.)

         10.2              Joint Operating Agreement between Gryphon Exploration
                           Company and Ridgewood  Energy  Corporation as Manager
                           of  the  Registrant  (incorporated  by  reference  to
                           Exhibit 10.2 of Registrant's  Registration  Statement
                           on  Form  10-12G/A   filed  with  the  Commission  on
                           September 2, 2005.)

         10.3              Offshore   Operating   Agreement  between  Millennium
                           Offshore  Group and Ridgewood  Energy  Corporation as
                           Manager of the Registrant for the South  Timbalier 77
                           (incorporated   by   reference  to  Exhibit  10.3  of
                           Registrant's  Registration Statement on Form 10-12G/A
                           filed with the Commission on September 2, 2005.)

         10.4              Offshore Operating  Agreement between Samson Offshore
                           Company and Ridgewood  Energy  Corporation as Manager
                           of  the   Registrant   for  the  James  Lime  project
                           (incorporated   by   reference  to  Exhibit  10.4  of
                           Registrant's  Registration Statement on Form 10-12G/A
                           filed with the Commission on September 2, 2005.)

         10.5              Offshore    Operating    Agreement   between   Apache
                           Corporation  and  Ridgewood  Energy   Corporation  as
                           Manager  of the  Registrant  for the East  Cameron 48
                           Project (incorporated by reference to Exhibit 10.5 of
                           Registrant's  Registration Statement on Form 10-12G/A
                           filed with the Commission on September 2, 2005.)

         14*               Code of Ethics adopted by the Manager in March 2004.

         31.1*             Certification  of Robert E. Swanson,  Chief Executive
                           officer  of the  Registrant  pursuant  to  Securities
                           Exchange Act Rule 13a-14(a).

                                       33
<PAGE>

         31.2*             Certification   of   Kathleen  P.   McSherry,   Chief
                           Financial  Officer  of the  Registrant,  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  Registrant and Kathleen P.
                           McSherry, Chief Financial Officer of the Registrant.


-------------------------
* Filed herewith


                                   SIGNATURES

         Pursuant to the requirements of Section13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 14th day of
March, 2006.

                      RIDGEWOOD ENERGY L FUND, LLC


                      By: /s/ Robert E. Swanson
                      -------------------------
                              Robert E. Swanson
                              Chief Executive Officer

                      By: /s/ Kathleen P. McSherry
                      ----------------------------
                              Kathleen P. McSherry
                              Senior Vice President and Chief Financial Officer



                                       34