UNITED STATES 
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the fiscal year ended December 31, 2006
oroTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 
                For the transition period from _____to _____ Commission File No. 000-51267  RIDGEWOOD ENERGY L FUND, LLC(Exact name of registrant as specified in its charter) Delaware
	
	11-3719724(State or other jurisdiction of
	
	(I.R.S. Employerincorporation or organization)
	
	Identification No.)
  1314 King Street, Wilmington, Delaware 19801(Address of principal executive offices) (Zip code)(302) 888-7444(Registrants telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Shares of LLC Membership Interest Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes
oNo
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
oNo
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
xNo
o Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained herein, to the best of the registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
x Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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
o
Accelerated filer
o
Non-accelerated filer
x Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes
oNo
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 March 30, 2007 was approximately $51.4 million and as of that
date there are 350.1081 Shares outstanding. 1   2006 Annual Report on Form 10-KTable of ContentsPart I
	
	
	PageItem 1
	Business
	
	7Item 1A
	Risk Factors
	
	20Item 1B
	Unresolved Staff Comments
	
	29Item 2
	Properties
	
	30Item 3
	Legal Proceedings
	
	31Item 4
	Submission of Matters to a Vote of Security Holders
	
	31Part IIItem 5
	Market for Registrant's Common Equity, Related Security Holder Matters, and Issuer
    Purchases of
	Equity Securities
	
	32Item 6
	Selected Financial Data
	
	35Item 7
	Management's Discussion and Analysis of Financial Condition and Results of Operations
	
	36Item 7A
	Quantitative and Qualitative Disclosures about Market Risk
	
	45Item 8
	Financial Statements and Supplementary Data
	
	45Item 9
	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	
	45Item 9A
	Controls and Procedures
	
	46Item 9B
	Other Information
	
	47Part IIIItem 10
	Directors, Executive Officers and Corporate Governance
	
	48Item 11
	Executive Compensation
	
	49Item 12
	Security Ownership of Certain Beneficial Owners and Management and Related Security
     Holder Matters
	
	50Item 13
	Certain Relationships and Related Party Transactions,
and Director Independence
	
	51Item 14
	Principal Accountant Fees and Services
	
	52Part IVItem 15
	Exhibits and Financial Statement Schedules
	
	53Signatures
	
	54Exhibit Index2



CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Report on Form 10-K (Annual Report) and the documents the Fund has incorporated by reference into this Annual Report, 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, 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, seek, expects, intends,
estimates, projects, will, would, will likely result, will continue, future and similar terms and expressions. The forward-looking statements in this Form 10-K
reflect the current views of the management of Ridgewood Energy L Fund, LLC (the Fund) with respect to future events and financial performance. These forward-looking statements are subject to certain risks and uncertainties, including,
among other things, the high-risk nature of oil and natural gas exploratory operations, the fact that the Funds drilling activities are managed by third parties, the volatility of oil and
natural gas prices and extraction, and those other risks and
uncertainties discussed in this report and in the Funds registration statement on Form 10, as amended, filed with the United States Securities and Exchange Commission (the SEC), that could cause actual results to differ materially
from historical results or those anticipated. A detailed discussion of these and other risks and uncertainties that could cause actual results and events to differ materially from such forward-looking statements is included in Item 1A. Risk
Factors beginning on page 20 of this Annual Report. You are urged to carefully consider all such factors.
In light of these risks and uncertainties, there can be no assurance that the forward-looking information contained in this Annual Report 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 todays date. We undertake no obligation to publicly revise these forward-looking statements to reflect events or circumstances that may arise after today. All
subsequent written or oral forward-looking statements attributable to the Fund or persons acting on the Funds behalf are expressly qualified in their entirety by this section.
AVAILABLE INFORMATIONThe Funds shares are registered under Section 12(g) of the Exchange Act. The Fund must therefore comply with, among other things, the periodic reporting requirements of Section 13(a) of the Exchange Act. As a result,
the Fund prepares and files annual reports with the SEC on Form 10-K, quarterly reports on Form 10-Q and, from time to time, current reports on Form 8-K. Moreover, the Manager maintains a website at http://www.ridgewoodenergy.com that contains
important information about the Manager, including biographies of key management personnel, as well as information about the oil and natural gas investments made by the Fund and the other investment programs managed by the Manager. Such information
includes, without limitation, a map of the Gulf of Mexico that provides the location of every well and project managed by the Manager along with information as to whether the project is exploratory, in completion or producing. This information is
publicly available (i.e., not password protected) and is updated regularly.
3



REPORTS TO SHAREHOLDERSThe Fund does not anticipate providing annual reports to shareholders but will make available upon request copies of the Fund's periodic reports to the SEC on Form 10-K and on Form 10-Q.
WHERE YOU CAN GET MORE INFORMATION
The Fund files annual, quarterly and current reports and certain other information with the SEC. Persons may read and copy any documents the Fund files at the SECs public reference room at 100 F Street, NE, Washington
D.C. 20549. You may obtain information on the operation at the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding
issuers that file electronically with the SEC at http://www.sec.gov. A copy of any such filings will be provided free of charge to any shareholder upon written request to the Fund at its business address 947 Linwood Avenue, Ridgewood, New Jersey
07450, ATTN: General Counsel.
4



Commonly Used Oil and Gas TermsBelow are explanations of some commonly used terms in the oil and gas business.
AFE.Authorization for expenditures.
Barrel (Bbl).A standard measure of volume for crude oil and liquid petroleum products. One barrel equals 42 U.S. gallons liquid volume, used herein in reference to crude oil or
condensate.
Bcf.Billion cubic feet.
Bcfe.Billion cubic feet equivalent, determined using the ratio of six Mcf gas to one Bbl of crude oil or condensate.
Btu.British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion.The installation of permanent equipment for the production of oil or natural gas from a recently drilled well.
Deep shelf.Structures located on the Outer Continental Shelf at depths generally greater than 14,000 feet in over pressured horizons where there has been limited or no production
from deeper stratigraphic zones.
Deepwater.Generally considered to be water depths in excess of 1,000 feet.
Development well.A well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive, including a well drilled to find
and produce probable reserves.
Dry-hole.A well found to be incapable of producing hydrocarbons in sufficient or commercial quantities such that proceeds from the sale of such production exceed production expenses
and taxes.
Exploration or exploratory well.A well drilled to find and produce oil or natural gas reserves in an unproved area.
FERC.The Federal Energy Regulatory Commission.
Field.An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
MBbls.One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf.The standard measure of volume for
natural gas, one thousand cubic feet.
Mcfe.One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.
MMS.The Minerals Management Service of the United States Department of the Interior.
MMBbls.One million
barrels of crude oil or other liquid hydrocarbons.
MMBTU.Million British Thermal Units.
MMcf.One million cubic feet.
MMcfe.One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.
Non-Consent.The option to elect not to participate in a well or project.
NYMEX.The New York Mercantile
Exchange.
OCS.The U.S. Outer Continental Shelf of the Gulf of Mexico. Water depths generally range from 50 feet to 1,000 feet.
Overriding Interest.The seller of ownership interest may retain a right for some period of time to payments from the sale of oil and natural gas production from a well or project.
Probable reserves.Reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing
economic conditions, but where such analysis suggests the likelihood of their existence and future recovery.
5



Productive well.A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses
and taxes.
Promote.The payment of a larger portion of the costs than ownership interest would require.
Proved developed reserves.Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
Proved developed nonproducing reserves.Proved developed reserves expected to be recovered from zones behind casing in existing wells.
Proved reserves.The estimated quantities of crude oil or natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is
required for recompletion.
SEC. United States Securities and Exchange Commission.
Working interest.The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover.Operations on a producing well to restore, maintain or increase production.


6



PART I
ITEM 1. BUSINESSGeneral Overview
Ridgewood Energy L Fund, LLC (the Fund) is a Delaware limited liability company and was formed on May 27, 2004 to acquire interests primarily in oil and natural gas projects located in the U.S. waters of the
Gulf of Mexico. Ridgewood Energy Corporation (Ridgewood Energy or the Manager), a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management and control of Fund
operations. The Fund is engaged in the acquisition, development and production of oil and natural gas projects in the Gulf of Mexico. To date, the Fund has focused primarily on acquiring oil and natural gas 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.
The Fund initiated its private placement offering on July 6, 2004, selling whole and fractional shares of membership interests primarily at $150 thousand per share. There is no public market for these shares and one is
not likely to develop. In addition, the shares are subject to severe restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund's limited liability company operating agreement (LLC
agreement) and applicable federal and state securities laws. The offering was terminated on September 30, 2004. The Fund raised approximately $51.4 million. After payment of approximately $7.8 million in offering fees, commissions and
investment fees, the Fund had approximately $43.6 million for investments and operating expenses. As of March 30, 2007 the Fund had 555 shareholders.
ManagerRidgewood Energy was founded in 1982 by Robert E. Swanson. As the Manager, Ridgewood Energy has direct and exclusive control over the management of the Fund's operations. With respect to project investment, Ridgewood Energy
locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made. This includes not only review of existing title documents, reserve information, and other technical
specifications regarding a project, but also the review and preparation of participation agreements and other agreements relating to an investment.
In addition, Ridgewood Energy performs (or arranges for the performance of) the management and administrative services required for Fund operations. Among other services, Ridgewood Energy administers the accounts and
handles relations with the shareholders, including tax and other financial information. In addition, Ridgewood Energy provides the Fund with office space, equipment and facilities and other services necessary for its operation. Finally, Ridgewood
Energy manages and conducts the Fund's relations with custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others, as required.
The Fund is required to pay all other expenses it incurs, including expenses of preparing and printing periodic reports for shareholders and the United States Securities and Exchange Commission (the SEC),
commission fees, taxes, outside legal, accounting and consulting fees,
litigation expenses and other expenses, if any,
7



properly payable by the Fund. The Fund is required to reimburse the Manager for all such Fund expenses paid by it.
As compensation for its management services, the Manager is entitled to (i) an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by our shareholders and (ii) a 15% interest
in the cash distributions made to the Funds shareholders. Effective September 2006, the Manager has changed its policy regarding the annual management fee. Commencing on September 1, 2006, the management fee, payable monthly, will be equal to
2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund.  As set forth in Item 7. Management's Discussion and Analysis, the Manager received from the Fund for the years ended December 31, 2006 and 2005 and
for the period May 27, 2004 (Inception) through December 31, 2004 approximately $1.1 million, $1.3 million and $0.5 million, respectively for its management services. Additionally, for the years ended December 31, 2006 and 2005 and for
the period May 27, 2004 (Inception) through December 31, 2004, the Manager received approximately $1.4 million, $0.1 million and nil, respectively, representative of the 15% interest of cash distributions.
Business Strategy
The Funds primary investment objective is to generate cash flow from the acquisition, exploration, production and sale of crude oil and natural gas from oil and natural gas projects. The Fund has invested and
participates in exploration and production projects located in the waters of the Gulf of Mexico offshore Texas, Louisiana and Alabama on the Outer Continental Shelf (OCS). These activities are governed by the Outer Continental Shelf
Lands Act (OCSLA) enacted in 1953 and administered by the Minerals Management Service of the Department of the Interior (MMS). The Fund generally looks to invest in projects that have been proposed by larger independent oil
and natural gas companies seeking to minimize their risks by selling a portion of their interest in a project. These investments may require the Fund to pay a disproportionate part of the drilling costs on the exploratory well of a project than its
ownership interest would otherwise require. This is called a promote and is common in the oil and natural gas exploration industry. In addition, notwithstanding the sale of an interest to the Fund, the seller may retain a right for some period of
time to payments from sales of oil and natural gas production from a well or project. This is called an overriding interest which is also relatively common in this industry. Notwithstanding any such promote or overriding interest, the Fund has tried
to invest in projects that it believes contain sufficient commercial quantities of oil or natural gas and which are near (i) existing oil or natural gas gathering and processing infrastructure and (ii) developed markets where the Fund can sell its
oil or natural gas.
The Fund tries to focus on projects that have significant reserve potential and which are projected to have the shortest time period from investment to first production. However, the Fund does not operate these projects,
and although it has a vote, it is not in control of the schedule pursuant to which its projects are developed and completed. Moreover, when performing due diligence with respect to a project, the Fund must rely on the independent reservoir engineers
who are hired and paid, in most cases, by the operator. The Fund does engage certain consultants to examine and review such reserve estimates and seismic information on its behalf.
8



Managers Investment Committee and Investment Criteria
The New Jersey office has four executives on the investment committee, three of whom have been working together at Ridgewood Energy for 20 years. The Houston office, which opened in 2003, has five executives on the
investment committee who provide operational, scientific and technical oil and natural gas expertise.
In considering projects, the Manager and investment committee investigates each such project against a list of factors that it believes will result in the selection of those projects that have the highest probability of
success. These factors, in no particular order, include, but are not limited to, the following (i) targeting projects that have or are expected to have operators with significant resources and experience in oil and natural gas exploration; (ii)
targeting projects that have or are expected to have partners that also have significant resources and experience in oil and natural gas exploration; (iii) technical quality of the project including its geology, seismic profile, locational trends,
and whether the project has potential for multiple prospects; (iv) oil or natural gas reserve potential; (v) whether and the extent to which the operator participates as a working interest owner in the project; (vi) economic factors, such as
potential revenues from the project, the rate of return, and estimated time to first production; (vii) risk factors associated with exploration, as more fully described in this filing; (viii) existence of drilling rigs, platforms and other
infrastructure, at or nearby the project; (ix) proposed drilling schedule; (x) terms of the proposed transaction, including contractual restrictions and obligations and lease term; and (xi) overall cost of the project.
Working Interest in Oil and Natural Gas Leases
Existing projects, and future projects, if any, are expected to be located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The OCSLA, which was enacted in 1953, governs certain
activities with respect to working interests and the exploration of oil and natural gas in the OCS.
Under OCSLA, the United States federal government has jurisdiction over oil and natural gas exploration and development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration,
development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the MMS, an agency of the United States Department of Interior. As part of the leasing
activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the length of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a degree, the planned activities of exploration
and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.
The winning bidder(s) at the lease sale, or the lessee(s), are given a lease by the MMS that grants such lessee(s) the exclusive right to conduct oil and natural gas exploration and production activities within a specific
lease block, or working interest. Leases in the OCS are generally issued for a primary lease term of 5, 8 or 10 years depending on the water depth of the lease block. The 5-year lease term is for blocks in water depths generally less than 400
meters, 8 years for depths between 400 meters to 800 meters and 10 years for depths in excess of 800 meters. During this primary lease term, except in limited circumstances, lessees are not subject to any
9



particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.
The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee
(or third-party operator for a project) may conduct additional geological studies and may determine to drill additional or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must
be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee's working interest ownership percentage.
Generally, working interests in an offshore gas lease under the OCSLA pay a 16.67% royalty to the MMS. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund
will invest is approximately 83.33% of the total revenue of the project, and, is further reduced by any other royalty burdens that apply to a lease block. However, as described below, the MMS has adopted royalty relief for existing OCS leases for
those who drill deep oil and natural gas projects.
Mineral Management Services Deep Natural Gas Royalty Incentive
On January 26, 2004, the MMS promulgated a rule providing incentives for companies to increase deep oil and natural gas production in the Gulf of Mexico (the "Royalty Relief Rule"). Under the Royalty Relief Rule, lessees
will be eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief would be available for wells drilled and
perforated deeper than 18,000 feet subsea. It should be noted that the Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the continental shelf nor does it apply if the price of natural gas exceeds $9.91 Million British
Thermal Units (mmbtu) adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters.
Oil and Natural Gas Agreements
We have entered into 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 77 # 4 and South Timbalier 77 #5, to the
public market. We are receiving market prices for such gas. The Manager believes that it is likely that gas from our other properties, once producing, will also have access to pipeline transportation and can also 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.
OperatorThe projects in which the Fund has 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 on behalf of all working interest owners under the terms of the applicable offshore operating agreements. In certain circumstances, operators will enter into agreements with independent
third-party subcontractors and suppliers to provide the various services
required for
10



operating leases. Currently, the Fund's projects are operated by ATP Oil and Gas Corporation (ATP), Devon Energy Corporation
(Devon), LLOG Exploration Company (LLOG) and Newfield Exploration Company (Newfield).
Because the Fund does not operate any of the projects in which it has acquired an interest, shareholders must not only bear the risk that the Manager will be able to select suitable projects, but also that, once selected,
such projects will be managed prudently, efficiently and fairly by the operators.
InsuranceThe Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover the projects, as well as general liability and similar coverage for its business operations.
However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to the projects. In addition, the Manager's past practice has been to obtain insurance as a package that is intended to cover most,
if not all, of the funds under its management. These projects are owned by affiliates of the Fund. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on
the extent of the incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature, and payment of any claims to the Funds affiliates, yearly insurance limits may become exhausted and be
insufficient to cover a claim made by the Fund in that year.
Salvage FundAs to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or a salvage fund, which is in the nature of a sinking fund, money to help provide for the Funds
proportionate share of the cost of dismantling production platforms and facilities, plugging and abandoning the projects, and removing the platforms, facilities and projects in respect of each of such projects after their useful life, in accordance
with applicable federal and state laws and regulations. There is no assurance that the salvage fund will have sufficient assets to meet these requirements and any unfunded expenses, and the Fund may be liable for such expenses. The Fund has
deposited approximately $1.0 million from capital contributions into a salvage fund which the Fund estimates to be sufficient to meet its potential requirements. If management later determines the deposit and earned interest is not enough to cover
the Funds proportionate share of expense, the Fund will deposit payments from operating income to make up any differences. Any portion of a salvage fund that remains after the Fund pays its share of the actual salvage cost will be distributed
to the shareholders. There are no legal restrictions on the withdrawal of the salvage fund.
SeasonalityGenerally, the Fund's business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund's oil and natural gas being sold, or likely to be sold, during
one or more particular months or seasons. Once a project is drilled and reserves of oil and natural gas are determined to exist, the operator of the project extracts such reserves throughout the year. Oil and natural gas, once extracted, can be sold
at any time during the year.
11



However, the Fund's drilling, production and transportation operations are subject to seasonal risks, such as hurricanes, that may affect our ability to bring such oil or natural gas to the market and, consequently, affect
the price for such oil and natural gas. The National Hurricane Center defines hurricane season in the Atlantic Region, Caribbean, and Gulf of Mexico to be from June 1 through November 30. During hurricane season, the number and intensity of and
resulting damage from hurricanes in the Gulf of Mexico region could affect the gathering and processing infrastructure, drilling platforms or the availability or price of repair or replacement equipment. As a result, these factors may affect the
supply and, consequently, the price of oil and natural gas resulting in an increase in price if supplies are reduced. However, even if commodity prices increase because of weather related shortages, the Fund may not be in a position to take
immediate advantage of any such price increase if, as a result of such weather related incident, damage occurred to its projects, the gathering infrastructure or in the transportation network.
The Manager has experienced the range of possible interruptions in operations due to hurricanes from as little as no damage and insignificant or no interruptions to significant damage and extended interruptions. However, it
is of course impossible to predict whether and to what extent hurricanes and damage may occur and to what projects.
CustomersAll of the oil and natural gas production from the Funds producing properties is sold by a third party on the Funds behalf. As a result, the Fund did not contract to sell oil and natural gas to third parties.
Therefore, the Fund had no customers or any one customer upon which the Fund depends for more than ten percent (10%) of its revenues.
Energy PricesHistorically, 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
the Fund cannot control or influence. Therefore, it is impossible to predict the future price of crude oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Funds future profitability. Also, the Fund
has not engaged in any price risk management programs or hedges to date and does not anticipate engaging in those types of transactions in the future.
CompetitionStrong competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. Although the Fund does not compete for the acquisition of working
interests from the MMS, it does compete with other companies for the acquisition of percentage ownership interests in oil and natural gas working interests in the secondary market.
In many instances, the Fund competes for projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and more experience in oil
and natural gas exploration and production than the Fund. As a result, these larger companies are in a position that they could outbid the Fund for a project. However, because these companies are so large and have such significant resources, they
tend to focus more on projects that are larger, have greater reserve potential, but cost significantly more
to explore and develop. These larger projects increasingly tend to be projects
in the
12



deepwater areas of the Gulf of Mexico and the North Sea off the coast of Great Britain. However, the focus of these companies on larger
projects does not necessarily mean that they will not investigate and/or acquire smaller projects in shallow waters for which the Fund competes. Many of these larger companies have participated in the auctions for lease blocks directly from the U.S.
Government. In such cases, these companies obtain from the U.S. Government 100% of the leasehold of a particular lease block in the Gulf of Mexico. In order to obtain even more resources to invest in other larger and more expensive projects, they
diversify current holdings, including projects they own in the shallow waters of the Gulf of Mexico, by selling off percentage interests in these lease blocks. As a result, very good projects in the shallow waters of the Gulf of Mexico become
available. The Fund, therefore, has opportunities to acquire interests in these smaller, yet economically attractive projects.
EmployeesThe Fund has no employees as the Manager operates and manages the Fund.
OfficesThe Managers principal executive offices are located at 947 Linwood Avenue, Ridgewood, NJ 07450, and its phone number is 800-942-5550. The Manager also leases additional office space at 11700 Old Katy Road, Houston,
TX 77079 for use by the Managers geologist and engineering staff.
RegulationOil and natural gas exploration, development and production activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other
things, our operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects,
the restoration of properties upon which projects are drilled and the plugging and abandoning of projects are also subject to regulations.
Outer Continental Shelf Lands Act
The Funds projects are located in the offshore waters of the Gulf of Mexico on the OCS. The Funds operations and activities, therefore, are governed by, among other things, the OCSLA.
Under OCSLA, 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 MMS, an agency of the United States Department of Interior. The MMS administers federal
offshore leases pursuant to regulations promulgated under the OCSLA. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required
from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. 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.
13

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
The Fund expects to sell its proportionate share of oil and natural gas to the market and to receive market prices from such sales. These sales are not currently subject to regulation by any federal or state agency.
However, in order for the Fund to make such sales the Fund is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission (FERC). The
rates, terms and conditions are regulated by FERC pursuant to a variety of statutes including the OSCLA, the Natural Gas Policy Act and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are
either market-based or cost-of-service. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge us, although regulated, are beyond our control. Nevertheless, such rates would apply uniformly to
all transporters on that pipeline and, as a result, the impact to the Fund of any changes in such rates, terms or conditions would not impact its operations differently in any material way than the impact upon other oil or natural gas producers and
marketers.
Environmental Matters and Regulation
The Funds operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water and the protection of aquatic species and habitats. However, although the
Fund shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Funds behalf.
Nevertheless, environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into
the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe
penalties, fines and liabilities for the environmental damage that is caused by our projects.
Some of the environmental laws that apply to oil and natural gas exploration and production are:
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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 an oil spill. Under the OPA, parties
responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages. In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier,
the Fund has not been required to make any such showing to the MMS as the operator is responsible for such compliance. However, notwithstanding the operator's responsibility for compliance, in the event of an oil spill, the Fund, 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 Federal Water Pollution Act/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, the Funds operators are responsible for compliance with the Clean Water Act although the Fund may be liable for any failure of the operator to do so.
Federal Clean Air Act.The Federal Clean Air Act restricts the emission of certain air pollutants. Prior to constructing new facilities, permits
may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. As a result, the Funds operations may be required to incur additional costs
to comply with the Clean Air Act.
Other Environmental Laws.In addition to the above, the Funds operations may be subject to theResource Conservation and Recovery Act,which regulates the generation, transportation, treatment, storage, disposal and cleanup
of certain hazardous wastes, as well as theComprehensive Environmental Response, Compensation and Liability Actwhich imposes joint and several liability without regard to fault or legality of conduct on classes of
persons who are considered responsible for the release of a hazardous substance into the environment.
The above represents a brief outline of the major environmental laws that may apply to the Funds operations. The Fund believes that its operators are in compliance with each of these environmental laws and the
regulations promulgated there under.
15



Potential Tax BenefitsThe following discussion is a summary of the primary tax benefits of ownership of a membership interest in the Fund and does not include all possible tax benefits or other tax implications of such ownership.
Deduction of Intangible Drilling and Development Costs
Section 263(c) of the Internal Revenue Code of 1986, as amended (the Code) authorizes an election by the Fund to deduct as expenses intangible drilling and development costs incurred in connection with oil and
natural gas properties at the time such costs are incurred in accordance with the Fund's method of accounting, provided that the costs are not more than would be incurred in an arm's length transaction with an unrelated drilling contractor. Such
costs include, for example, amounts paid for labor, fuel, wages, repairs, supplies and hauling necessary to the drilling of the project and preparation of the project for production. Generally, this election applies to items that in themselves do
not have salvage value. Alternatively, each Fund shareholder may elect to capitalize their share of the intangible drilling and development costs and amortize them ratably over a 60-month period.
The Fund may enter into carried interest arrangements whereby the Fund would purchase interests in certain leases and agree to pay a disproportionate part of the costs of drilling the first project thereon. In such
situations, the party who is paying more than their share of costs of drilling may not deduct all such costs as intangible drilling and development costs unless their percentage of ownership of the lease is not reduced before they have recovered
from the first production of the project an amount equal to the cost they incurred in drilling, completing, equipping and operating the project. The Fund may not have this right in certain of the transactions of this type in which it may engage. If
circumstances permit, however, the Fund will adopt the position that all of the intangible drilling and development costs incurred are deductible (even though such costs may be disproportionate to its ownership of the lease) on the basis that such
arrangements constitute partnerships for federal income tax purposes and that the excess intangible drilling and development costs are specifically allocable to the Fund. There can be no assurance that this position would prevail against challenge
by the Internal Revenue Service (the IRS).
In the case of a shareholder who constitutes an integrated oil company, 30% of the amount otherwise allowable as a deduction for intangible drilling costs under Section 263(c) must be capitalized and deducted ratably over a
60-month period beginning with the month the costs are paid or incurred. This provision does not apply to nonproductive projects. For this purpose, an integrated oil company is generally defined as an individual or entity with retail sales of oil
and natural gas aggregating more than $5 million and refining more than 50,000 barrels per day for the taxable year.
To the extent that drilling and development services were performed for the Fund in 2006, amounts incurred pursuant to bona fide arm's-length drilling contracts and constituting intangible drilling and development costs
were deductible by the Fund in 2006. To the extent that such services are performed in 2007, however, the Fund will only be allowed to deduct for the year 2007 amounts that are:
16



incurred pursuant to bona fide arm's-length drilling contracts
which provide for absolute noncontingent liability for payment,
and
attributable towellsspud within 90 days after
December 31, 2006.Sections 461(h)(1) and 461(i)(2) of the Code provide, in relevant part:
...in determining whether an amount has been incurred with respect to any item during any taxable year, the all events tests shall not be treated as met any earlier than when economic performance with respect to such item
occurs.
* * *
...economic performance with respect to the act of drilling an oil or natural gas well shall be treated as having occurred within a taxable year if drilling of the well commences before the close of the 90th day after the
close of a taxable year.
The clear implication of these provisions is that an amount incurred during a taxable year for drilling or completion services which could otherwise be accrued for federal tax purposes will not be disqualified as a
deduction merely because the services are performed during the subsequent taxable year (provided that the services commence within the first 90 days of such subsequent year).
Consequently, intangible drilling and development costs meeting the above criteria were deducted by the Fund in 2006 even though a portion of such costs are attributable to services performed during 2007.
Each shareholder, however, may deduct their share of amounts paid in 2006 for services performed in 2007 only to the extent of their cash basis in the Fund as of the end of 2006. For this purpose, a taxpayer's cash basis in
a tax shelter which is taxable as a partnership (such as the Fund) is the taxpayer's basis in the Fund determined without regard to any amount borrowed by the taxpayer with respect to the Fund which (a) is arranged by the Fund or by any person who
participated in the organization, sale or management of the Fund (or any person related to such person within the meaning of Section 461(b)(3)(c)) of the Code, or (b) is secured by any asset of the Fund. Inasmuch as cash basis excludes borrowing
arranged by an extremely broad group of persons who could be related to a person who participated in the organization, sale or management of the Fund, it is not possible to express an opinion as to whether each shareholder of the Fund will be
allowed to deduct their allocable share of any prepaid drilling expenses to the extent that they exceed their actual cash investment in the Fund.
Depletion Deductions
Subject to the limitations discussed hereafter, the shareholders will be entitled to deduct, as allowances for depletion under Section 611 of the Code, their share of percentage or cost depletion, whichever is greater, for each oil and natural gas producing project owned by the Fund.
17



Cost depletion is computed by dividing the basis of the project by the estimated recoverable reserves to obtain a unit cost, then multiplying the unit cost by the number of units sold in the current year. Cost depletion
cannot exceed the adjusted basis of the project to which it relates. Thus, cost depletion deductions are limited to the capitalized cost of the project, while percentage depletion may be taken as long as the project is producing income. The
depletion allowance for oil and natural gas production will be computed separately by each shareholder and not by the Fund. The Fund will allocate to each shareholder their proportionate share of production and the adjusted basis of each Fund
project. Each shareholder must keep records of their share of the adjusted basis and any depletion taken on the project and use their adjusted basis in the computation of gain or loss on the disposition of the project by the Fund.
Percentage depletion with respect to production of oil and natural gas is available only to those qualifying for the independent producer's exemption, and is limited to an average of 1,000 barrels per day of domestic oil
production or 6,000,000 cubic feet per day of domestic natural gas production. The applicable rate of percentage depletion on production under the independent producer exemption is 15% of gross income from oil and natural gas sales. The depletion
deduction under the independent producer exemption may not exceed 65% of the taxpayer's taxable income for the year, computed without regard to certain deductions. Any percentage depletion not allowed as a deduction due to the 65% of adjusted
taxable income limitation may be carried over to subsequent years subject to the same annual limitation. For a shareholder that is a trust, the 65% limitation shall be computed without deduction for distributions to beneficiaries during the taxable
year.
The determination of whether a shareholder will qualify for the independent producer exemption will be made at the shareholder level. A shareholder who qualifies for the exemption, but whose average daily production exceeds
the maximum number of barrels on which percentage depletion can be computed for that year, will have to allocate their exemption proportionately among all of the properties in which they have an interest, including those owned by the Fund. In the
event percentage depletion is not available, the shareholder would be entitled to utilize cost depletion as discussed above.
The independent producer exemption is not available to a taxpayer who refines more than 50,000 barrels of oil on any one day in a taxable year or who directly or through a related person sells oil or natural gas or any
product derived therefrom (i) through a retail outlet operated by them or a related person or (ii) to any person who occupies a retail outlet which is owned and controlled by the taxpayer or a related person. In general, a related person is defined
by Section 613A of the Code as a corporation, partnership, estate, or trust in which the taxpayer has a 5% or greater interest. For the purpose of applying this provision: (a) bulk sales of oil or oil and natural gas to commercial or industrial
users are excluded from the definition of retail sales; (b) if the taxpayer or a related person does not export any domestic oil or natural gas production during the taxable year or the immediately preceding year, retail sales outside the U.S. are
not deemed to be disqualifying sales; and (c) if the taxpayer's combined receipts from disqualifying sales do not exceed $5 million for the taxable year of all retail outlets taken into account for the purpose of applying this restriction, such taxpayer will not be deemed a retailer.
18



Depreciation
Costs of equipment, such as casing, tubing, tanks, pumping units, pipelines, production platforms and other types of tangible property and equipment generally cannot be deducted currently, but may be eligible for
accelerated cost recovery. All or part of the depreciation claimed may be subsequently recaptured upon disposition of the property by the Fund or of a share by any shareholder.
In addition, the Code provides for certain uniform capitalization rules which could result in the capitalization rather than deduction of Fund management fee and administration costs.

19



ITEM 1A. RISK FACTORSIn addition to the other information set forth elsewhere in this report, you should carefully consider the following factors when evaluating the Fund:
RISKS INHERENT IN THE FUNDS BUSINESS
The Funds exploration and production activities are subject to risks that it cannot control and it may have insufficient insurance to cover these risks. To the extent the Fund is not covered by insurance, it
could incur losses and liabilities that could reduce revenues, increase costs or eliminate dollars available for future exploration and development projects.
Costs of drilling, completing and operating projects are often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:
Fires, explosions, blowouts and cratering
Equipment failures, casing collapse, pipe and cement failures
Marine risks such as capsizing or collisions
Adverse weather conditions, including hurricanes
Shortages or delays in the delivery of equipment
Acts of terrorism
Environmental hazards
Pipeline ruptures and discharge of toxic gasesMany of the above-mentioned risks could result in damage to life and / or property, or cause sustained interruption of production.
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. The Fund could be liable for costs in excess of its insurance coverage.
In addition, it is significantly less costly for insurance to be acquired and maintained by the Manager as a package that covers all of the oil and natural gas projects under its management. The majority of these projects
are owned by other entities that are likewise managed by Ridgewood Energy. As a result, given insurance limits, if significant damage occurs to other projects owned by other investment vehicles managed by the Manager in any given year, the amount of
insurance available to cover any damage to the Fund's projects could be significantly reduced.
The Funds investment activities may result in unsuccessful projects.
There is always significant risk that a project will not have commercially productive oil or natural gas reservoirs. In other words, the well may be a dry-hole. The successful acquisition of producing properties requires
assessment of reserves, seismic and other engineering information, future commodity prices, operating costs and potential environmental liabilities. The Funds assessment of these factors may not be successful.
20



The Fund has already experienced dry-holes and further dry-holes will adversely impact the funds profitability and returns.
The Fund has had five dry-holes, West Cameron 95, East Breaks 157, East Cameron 48, Main Pass 155 and West Cameron 103. Cumulative dry-hole costs to the Fund for the years ended December 31, 2006 and 2005 and for the period
May 27, 2004 (Inception) through December 31, 2004 totaled approximately $4.9 million, $6.7 million and $2.9 million, respectively.  With respect to the dry-holes, the Fund does not anticipate incurring any significant future costs as
all the wells have been plugged and abandoned. However, given that the Funds capital is limited to the amount it raised (less various fees) in the offering of its shares, the aforementioned dry-holes, and every other dry-hole that the Fund may
experience, has the effect of reducing the limited capital available for investment. In addition, because dry-holes reduce the capital available for additional investment, a significant number of dry-holes will reduce the returns of the Fund because
the remaining capital, even if invested in successful wells, may not generate enough cash for investors to realize significant or positive returns on their investments.
The actual costs to drill a well, or dry-hole costs, can materially exceed estimates due to cost overruns. In such event, the risks associated with the well increase.
When the Fund invests in a particular project the operator will generally provide what is referred to as an AFE or authorization for expenditures. The AFE(s) for a particular project generally represent the dry-hole costs
associated with that project and not the development costs should the project be successful.  Dry-hole costs are generally an estimate made by the Operator after considering numerous factors, such as water depth, drilling depth, seismic information,
and equipment costs and availability. Notwithstanding the Operators best estimates of drilling cost, the actual drilling of the well may result in cost overruns that materially increase the costs of the drilling the project. The cost overrun
can occur for any number of reasons including but not limited to, weather delays, equipment unavailability, pressure or irregularities in formations and other risks identified herein. The Fund has little choice but to pay these costs overruns or
potentially lose its right to participate in the well by going non-consent.  Significant cost overruns will increase the risk associated with the project as additional Fund capital that would otherwise be used for other projects is being allocated
to cover the overruns.
The Funds reserve estimates are inherently uncertain and may be inaccurate and if so, may adversely affect the Funds revenue and profitability.
Once reserves are proved, 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
the Funds 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 the Funds reserves may not occur as scheduled and the actual results may not be as estimated.
21



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, sometimes materially, from the quantities ultimately recovered. The Manager reviews the reserve
estimates provided by the operators of projects in which the Fund participates 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 the Funds operations, business and prospects, as well as on the amounts of such reserves.
Moreover, the Fund's estimated or proved oil and natural gas reserves and the estimated future net revenues from such reserves will be based upon various assumptions, including available geological, geophysical, engineering
and production data. The process also requires certain economic assumptions such as oil and natural gas prices, drilling and operating expenses, capital expenditures, and availability of funds. As a result, the Fund is required to make assumptions
and judgments, all of which can be wrong or inaccurate. Thus, these estimates are inherently imprecise and the quality and reliability of this information can vary, perhaps significantly, from actual results.
The prices that the Fund may receive for its oil or natural gas are highly volatile and unpredictable and may not be sufficient to generate enough cash flow to make distributions to investors.
When oil and natural gas production begins, the Fund's revenue, profitability and cash flow are highly dependent on the prices of oil and natural 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 the Funds future profitability and, in such an event, the Fund may be required by accounting rules to write-down the carrying value of its projects.
The Fund has not engaged in any price risk management programs or hedges to date and does not anticipate engaging in those types of transactions in the future.
The Fund may be required to take write-downs if natural gas and prices decline.The Fund may be required under successful efforts accounting rules to write-down the carrying value of the Funds properties if oil and natural gas and oil prices decline or if the Fund has substantial downward
adjustments to the Funds estimated proved reserves, increases in the Funds estimates of development costs or deterioration in the Funds exploration results.
The Fund utilizes the successful efforts method of accounting for natural gas and oil exploration and development activities. If the net book value of the Funds natural gas and oil properties exceeds the Funds
undiscounted cash flows, Generally Accepted Accounting Principles in the United States (GAAP) require the Fund to impair or write-down the book value of its oil and natural gas properties. Depending on the magnitude of any future
impairment, a write-down could significantly reduce the Funds income, or produce a loss. As impairment computations involve the prevailing price on the last day of the quarter, it is impossible to predict the timing and magnitude of any future
impairment.  To the extent the Funds finding and development
22



costs continue to increase as the Fund expects, the Fund will become more susceptible to impairments in low price environments. For the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception)
through December 31, 2004, the Fund recorded no impairment losses.
The unavailability and cost of needed equipment may adversely affect the Funds profitability and operations.
As a result of the increase in oil and natural gas prices, drilling activity in the Gulf of Mexico has increased significantly. Drilling rigs and other equipment have become harder to obtain and more costly to acquire,
especially if weather occurrences, such as hurricanes, occur with frequency in the Gulf of Mexico. These circumstances could have a negative impact on the Fund's operations.
The Fund has a limited amount of capital available to invest and therefore has limited ability to invest in many more projects. Further, each unsuccessful project erodes the Funds limited capital.The capital raised by the Fund in its private placement is more than likely all the capital it will be able to obtain for investments in projects. Given its structure, obtaining traditional financing from public markets is
unlikely and it is not practical to assume the Fund can raise additional funds through a supplemental offering or through debt financing. As a result, it has little, if any, ability to grow its business beyond its current projects or through
investing its available cash in new projects. In any event, the number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund has experienced not only reduced its ability to generate revenue, but
has also exhausted its limited supply of capital.
The Fund may incur costs to comply with the many environmental and other governmental regulations that apply to its operations, which may adversely impact its ability to generate cash flow for distributions.The oil and natural gas industry, in general, and offshore activities, in particular, are subject to numerous governmental laws and regulations which may affect the ongoing and future operational decisions and financial
results of the Fund. United States legislation affecting the oil and natural 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 projects, 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 natural gas, which could adversely affect the price at which oil and natural gas is sold.
The regulatory burden on the oil and natural 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, the Fund is unable to predict
the ultimate cost of compliance.
The Fund relies on third parties to operate, manage, and maintain its projects over which it has limited control. Therefore, decisions may be made by these third parties that adversely affect the Fund or its
operations.
Neither the Fund nor the Manager currently own or have any plans to acquire drilling or
production
23



equipment nor does the Fund or Manager maintain a staff of technical employees required for on-site drilling operations. Therefore, the Fund must 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 it participates. For example, lack of operating control could lead to higher operating costs, drilling delays, increased rig costs or labor issues.
As such, the Fund has little or no control over the day-to-day operations of these projects. However, the Fund has acquired and will continue to seek projects, to the extent of its available capital, in which the operators have significant
resources, are experienced in offshore operations and have a long term presence and track record of success in the Gulf of Mexico.
The Fund owns projects jointly with other companies over whom it has no control and who may influence the manner in which the project is operated.
The Fund participates in projects as a working interest owner along with other unrelated third party entities, including the operator. While the Manager may monitor and participate in decisions affecting exploration and
development of the leases or projects in which the Fund participates, other decisions with respect to lease exploration and development activities may be controlled by the other participants and could be unfavorable to the Fund. Finally, the Fund
could be held liable for the joint activity obligations or tortuous actions of the operator or other working interest owners. If the Funds co-participants fail to pay their portion of the drilling and completion or ongoing maintenance costs,
the project may lack sufficient funds to perform such work. As a result, the Fund, as well as the remaining working interest owners, may be required to pay such additional sums in order to complete drilling or development of the project.
The Fund faces competition from larger entities with greater capital resources that could limit the number and availability of economically attractive projects.As an independent oil and natural gas producer, the Fund faces competition in all aspects of its business. Many of its competitors are large, well-established companies that have significantly larger staffs and have greater
capital resources. These companies may be able to pay more for a project or sustain losses for a longer period of time than the Fund.
The Fund maintains a salvage fund that may be insufficient to cover such salvage costs, in which event; the Fund could be liable for any excess.
The Fund has created a salvage fund to cover certain anticipated salvage costs associated with the Funds projects. The salvage fund may not have sufficient assets to meet salvage costs and thus the Fund may be liable
for its proportionate share of the unfunded expenses if in excess of the salvage fund.
The Funds projects and operations are located exclusively in the Gulf of Mexico and are subject to interruptions and damage from hurricanes that could adversely affect the Funds cash
flow.
The Fund has invested in projects exclusively within the Gulf of Mexico and any
future investments by the Fund in projects will likewise be located in the Gulf
of Mexico. As a result of such exclusivity in location, the Fund is particularly
susceptible to hurricane risks in that the impact to the Fund's operations of a
severe storm or storms could be more pronounced and severe (depending on the
storm, its path, and resulting damage) because the Fund does not have projects
in other areas of the globe to offset such damage. If, for example, the
24



Fund had projects in areas not affected by hurricanes those projects could still operate and generate cash flow during the interruptions in operations in the Gulf of Mexico. As it is, a hurricane, or series of hurricanes in a season, has the
potential of interrupting all of the Funds operations, at least for some period of time, if all of the Funds projects were affected. In such event, the Fund would not have sufficient cash flow to make distributions to investors and,
additionally and as disclosed earlier, insurance may not be sufficient to cover all of the damages caused by the hurricanes.
The Funds internal control over financial reporting could be adversely affected by material weaknesses in the Funds internal controls.
In the Funds Form 10-K/A for the
year ended December 31, 2005, filed March 7, 2007, the Fund reported material
weaknesses with respect to its lack of technical accounting resources on staff
and the need for additional training, formalized policies and procedures on
documenting financial controls.  These control deficiencies resulted in the
restatement of the Funds Form 10-K.  As a result of these material weaknesses,
the Fund concluded in its Form 10-K/A that its control over financial reporting
was not effective as of the end of the periods covered by the reports.  The Fund
has remediated these material weaknesses.  Investors, however, should be aware
that the Fund cannot guarantee that future material weaknesses will not develop
or be identified.  Any new material weaknesses identified could harm the Funds operating results, cause the Fund to fail to meet its
reporting obligations or result in material misstatements in its financial
statements. Any such failure also could affect the ability of management to
certify that the Funds internal controls are effective when it provides an
assessment of the Funds internal control over financial reporting.
RISKS RELATED TO THE NATURE OF THE FUNDS SHARES
The Funds shares have severe restrictions on transferability and liquidity and shareholders are required to hold the shares indefinitely.
The Fund's shares are illiquid investments. There is currently no market for these shares and one is not likely to develop. 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 Funds LLC agreement and under applicable federal and state securities laws, it is expected that no public market will develop. Moreover, neither the Fund nor the 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 Funds LLC agreement and applicable law, and all such sales or transfers
require the Fund's consent, which it may withhold at its 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.
Shareholders are not permitted to participate in the Funds management or operations and must rely exclusively on the Manager.
Shareholders have no right, power or authority to participate in the Funds management or decision making or in the management of the Funds projects. The Manager has the exclusive right to manage, control and
operate the Funds affairs and business and to make all decisions relating to its operation.
25



The Funds assets are illiquid and, therefore, cash flow for distributions, if any, must come from operations and not dispositions of assets.
The Fund's interest in projects is illiquid. The Fund does not anticipate selling any interests in the projects, or any part thereof. Even if the Fund elected to sell, it is likely that there will be little or no market for
these assets.  However, if the Fund were to attempt to sell any such interest, a successful sale would depend upon, among other things, the operating history and prospects for the project or interest being sold, proven oil and natural gas reserves,
the number of potential purchasers and the economics of any bids made by them and the current economics of the oil and natural 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 and the terms and conditions under which such projects would be sold. 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 and for negotiating and completing the sale transaction.
The Fund indemnifies its officers, as well as the Manager and its employees, for certain actions taken on its behalf and therefore, Fund assets may be used to reimburse such officers.
The LLC agreement provides that the Fund's officers and agents, the Manager, the affiliates of the Manager and their respective directors, officers and agents when acting on behalf of the Manager or its affiliates on the
Fund's behalf, will be indemnified and held harmless by the shareholders from any and all claims rising out of the Fund's management, except for claims arising out of bad faith, gross negligence or willful misconduct or a breach of the LLC
agreement. Therefore, the Fund 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 receives a management fee regardless of the Funds profitability and also receives cash distributions.
The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. The annual fee, payable monthly, is equal to 2.5% of total capital contributed by
shareholders. Effective September 2006, the Manager has changed its policy regarding the annual management fee.  Commencing in September 1, 2006, the management fee, payable monthly, will be equal to 2.5% of the total shareholder capital
contributions, net of dry-hole expenses incurred by the Fund.
In addition to an annual management fee, the Manager, as compensation for its management services, receives 15% of our cash distributions to shareholders although the Manager has not contributed any cash to the Fund.
Accordingly, shareholders contribute all of the cash utilized for the Fund's investments and activities. If the Fund's projects are unsuccessful, the shareholders lose 100% of their investment while the Manager, not having contributed any capital,
will lose nothing. For the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004 distributions to the Manager were $1.4 million, $0.1 million and nil, respectively.
26



Inherent in these fee arrangements is the possibility of conflicts between the Fund's interests and the best interests of the Manager. The Manager may have incentive to act in its best interests rather than in the Funds best interest by taking actions designed to increase its fees but with significant risk to the
Fund. Any such conflict of interests will be addressed by the Manager as described in the risk factor below headed Because the Manager manages many other oil and natural gas funds, it may have conflicts of
interest in its management of our operations.
None of the compensation to be received by the Manager has been derived as a result of arm's length negotiations.
Under Delaware law, shareholders have limited access to information and therefore, the Fund and Manager can restrict certain information, including shareholder information, making communications with other
shareholders difficult.  As a result, the information you receive about the Fund and its activities will be limited to what the Manager chooses to provide.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. The Fund's 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
the Fund 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 tax, other financial
information or any other reasonable information regarding Fund operations.
Cash distributions are not guaranteed and may be less than anticipated or estimated.
Distributions depend primarily on available cash from oil and natural gas operations. At times, distributions may be delayed to repay the principal and interest on fund borrowings, if any, or to fund other costs, although
the Fund does not anticipate such borrowings. The Fund's taxable income will be taxable to the shareholders in the year earned, even if cash is not distributed.
Because the Manager manages many other oil and natural gas funds, it may have conflicts of interest in its management of the Funds operations.
Shareholders will not be involved in the management of the Fund's 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 the Fund 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 the Fund in connection with its position
and responsibilities as Manager and it 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 parties affected by any such conflicts of interest. The Manager is not liable to the Fund for how conflicts of interest are resolved unless it has acted in bad faith, or engaged in gross negligence or willful misconduct.
27



TAX RISKS ASSOCIATED WITH AN INVESTMENT IN SHARES
The Fund is organized as a Delaware limited liability company and the Manager has qualified the Fund as a partnership for federal tax purposes. The principal tax risks to shareholders are that:
The Fund may recognize income taxable to the shareholders but may not distribute enough cash to cover the income taxes on the Fund's taxable
income.
The allocation of
Fund items of income, gain, loss, and deduction may not be recognized for federal income tax purposes.
All or a portion of the Fund's expenses could be considered either investment expenses (which would be deductible by a shareholder only to the extent the
aggregate of such expenses exceeded 2% of such shareholder's adjusted gross income) or as nondeductible items that must be capitalized.
All or a substantial portion of the Fund's income could be deemed to constitute unrelated business taxable income, such that tax- exempt shareholders could
be subject to tax on their respective portions of such income.
If any Fund income is deemed to be unrelated business taxable income, a shareholder that is a Charitable Remainder Trust could have all of its income from
any source deemed to be taxable.
All or a portion of the losses, if any, allocated to the shareholders will be passive losses and thus deductible by the shareholder only to the extent of
passive income.
The shareholders could have capital losses in excess of the amount that is allowable as a deduction in a particular year.Although the Fund has obtained an opinion of counsel regarding the matters described in the preceding paragraph, it will not obtain a ruling from the IRS as to any aspect of the Fund's tax status. The tax consequences of
investing in the Fund could be altered at any time by legislative, judicial, or administrative action.
If the IRS audits the Fund, it could require investors to amend or adjust their tax returns or result in an audit of their tax.The IRS may audit the Fund's tax returns. Any audit issues will be resolved at the Fund level by the Manager. If adjustments are made by the IRS, corresponding adjustments will be required to be made to the federal income
tax returns of the shareholders, which may require payment of additional taxes, interest, and penalties. An audit of the Fund's 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 the Fund operations. Each shareholder bears the expenses associated with an audit of that shareholder's return.
In the event that an audit of the Fund by the IRS results in adjustments to the tax liability of a shareholder, such shareholder will be subject to interest on the underpayment 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.
28



The tax treatment of the Fund can not be guaranteed for the life of the Fund. Changes in law or regulations may adversely affect any such tax treatment.
Deductions, credits or other tax consequences may not be available to shareholders. Legislative or administrative changes or court decisions could be forthcoming which would significantly change the statements herein. In
some instances, these changes could have substantial effect on the tax aspects of the Fund. 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 some of the tax consequences of the Fund.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not Applicable.

29



ITEM 2. PROPERTIESIn 2004, the Fund acquired from Millenium Offshore Group (MOGI) a 20% working interest in the South Timbalier 77 field of which two wells were drilled and are now operated by ATP.Well Name
        Operator
        Offshore
        Working Interest %
        Costs Incurred through 12/31/06(in thousands)
        StatusSouth Timbalier 77#4
        ATP
        LA
        20.00%
        $               6,374
        Currently producingSouth Timbalier 77#5
        ATP
        LA
        20.00%
        $               3,005
        Currently producingThe Fund acquired the West Cameron 103 from Gryphon Exploration Company (Gryphon) and East Breaks 157 from ENI Petroleum Company Inc (ENI Petroleum). Both wells were deemed dry-holes and were plugged and abandoned.Well Name
        Operator
        Offshore
        Working Interest %
        Costs Incurred through
			
			12/31/06(in thousands)
        StatusWest Cameron 103
        Gryphon
        LA
        20.00%
        $               2,798
        DRY:November 2004East Breaks 157
        ENI Petroleum
        TX
        7.00%
        $               1,793
        DRY:March 2006The Fund acquired a 13.3% working interest in Eugene Island 337 from Devon, which was drilled in two zones, one at 12,500 feet which was dry and one at 7,500 feet which will be completed during the first quarter of 2007 and is scheduled to begin production in April 2007.Well Name
        Operator
        Offshore
        Working Interest %
        Costs Incurred through 12/31/06(in thousands)
        StatusEugene Island 337
        Devon
        LA
        13.33%
        $               3,456
        Discovery July 2006: Waiting on ProductionThe Fund acquired a 25% working interest in East Cameron 48 from Apache Corporation (Apache) which was drilled and deemed a dry-hole in September 2005.Well Name
        Operator
        Offshore
        Working Interest %
        Costs Incurred through 12/31/06(in thousands)
        StatusEast Cameron 48
        Apache
        LA
        25.00%
        $               5,893
        DRY:September 2005The Fund acquired a 7.5% working interest in Main Pass 155 from Samson Energy (Samson) which was drilled and deemed a dry-hole in July 2005.Well Name
        Operator
        Offshore
        Working Interest %
        Costs Incurred through 12/31/06(in thousands)
        StatusMain Pass 155
        Samson
        AL
        7.50%
        $                  988
        DRY:July 200530


The Fund acquired a 20% working interest in West Cameron 95 from El Paso Corporation ("El Paso") in 2006 which was drilled and deemed a dry-hole in July 2006. At a depth of 10,781 feet the drilling string became stuck which
forced us to side-track the well. The Fund has filed a claim with its insurance carrier for the cost of the side-track, and expects to recover $2.5 million of the costs incurred.
Costs Incurred
through
12/31/06
(in thousands)Working
Interest %Well Name
	Operator
	Offshore
	StatusWest Cameron 95
	El Paso
	LA
	20.00%
	$ 5,597
	DRY:July 2006In October 2006, the Fund acquired a working interest in the following wells operated by LLOG.
Working
Interest %
	
	Drilling Risk
(in thousands)Well Name
	
	Operator
	
	Offshore
	
	
	
	StatusGalveston 248
	
	LLOG
	
	TX
	
	7.50
	%
	$
	800
	
	2nd quarter 2007drilling dateShip Shoal 81
	
	LLOG
	
	LA
	
	7.50
	%
	$
	500
	
	3rd quarter 2007drilling dateSouth Marsh Island 111
	
	LLOG
	
	LA
	
	7.50
	%
	$
	500
	
	2nd quarter 2007drilling dateVermilion 344
	
	LLOG
	
	LA
	
	7.50
	%
	$
	500
	
	Successful-completion inprogressWest Delta 67
	
	LLOG
	
	LA
	
	7.50
	%
	$
	600
	
	2nd quarter 2007drilling dateWest Delta 68
	
	LLOG
	
	LA
	
	7.50
	%
	$
	650
	
	Successful-completion inprogressIn December 2006, the Fund acquired a working interest in Main Pass 275 well operated by Newfield.
Working
Interest %
	
	
	Drilling Risk
(in thousands)Well Name
	
	Operator
	
	Offshore
	
	
	
	
	StatusMain Pass 275
	
	Newfield
	
	LA
	
	10.00
	%
	
	$
	1,260
	
	Successful-completion inprogressITEM 3. LEGAL PROCEEDINGSOn August 16, 2006, the Manager of the Fund filed a lawsuit against the former independent registered public accounting firm for the Fund, Perelson Weiner ("PW"), in New Jersey Superior Court, captioned Ridgewood Energy
Corporation v. Perelson Weiner, LLP, Docket No. L-6092-06. The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Fund by PW. Thereafter, PW filed a counterclaim against
the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. Discovery is ongoing and no trial date has been set.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
31



PART II.
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED SECURITY HOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Price of Common Units, Distributions and Related Unitholder Matters
There is currently no established public trading market for the shares of membership interest of the Fund. The Fund is 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 the Fund does not have any equity-based compensation plans. The shares are restricted as to resale. Shareholders wishing to transfer shares should also consider the
applicability of state securities laws. The shares have not been registered under the Securities Act of 1933, as amended (the Securities Act) or under any other similar law of any state (except for certain registrations that do not
permit free resale) in reliance upon what the Fund believes to be exemptions from the registration requirements contained therein. Because the shares have not been registered, they are restricted securities as defined in Rule 144 under the
Securities Act. As of March 30, 2007, no shares of the Fund could be sold pursuant to Rule 144. The Fund has not agreed to register any shares under the Securities Act for sale by security holders.
As of the date of this filing, there were approximately 555 holders of Fund shares.
Participation in Costs and Revenues
The Funds investment objective is primarily to generate current cash flow for distribution to shareholders from the operation of the Fund projects to the extent that such distributions are consistent with the reserve
requirements and operational needs of those projects.  If the Fund does make distributions, this section describes how the Fund will:
determine what cash flow will be available for distributions to Investors,
distribute available cash flow,
give the Manager a share of cash flow, if available,
handle returns of capital contributions,
allocate income and deductions for tax purposes, and
maintain capital accounts for Investors.Available cash determines what amounts in cash the Fund will be able to distribute in cash to Investors. There are three types of available cash as follows:
Available Cash from Capital Transactions is total cash received by the Fund from the proceeds of the sale or other disposition of the Funds property (including items such as insurance proceeds, refinancing
proceeds, condemnation proceeds and other amounts received out of the ordinary course of business), but excluding dispositions of temporary investments of the Fund.
32



Available Cash from Temporary Investments is cash from short-term investments (i.e. U.S. Treasury Bills, certificates of deposits) and other interest bearing cash accounts.
Available Cash from Operations is all other available cash.
There is no fixed requirement to distribute available cash; instead, it will be distributed to shareholders to the extent and at such times as the Manager believes is advisable. Once the amount and timing of a distribution
is determined, it shall be made to shareholders as described below.
Distributions from Operations
At various times during a calendar year, the Fund will determine whether there is enough Available Cash from Operations for a distribution to shareholders. The amount of Available Cash from Operations determined to be
available, if any, will be distributed to the shareholders. At all times, the Manager will be entitled to 15% and shareholders will be entitled to 85% of the Available Cash from Operations distributed.
Distributions of Available Cash from Capital TransactionsAvailable Cash from Capital Transactions that the Fund decides to distribute will be paid as follows:
Before shareholders have received total distributions equal to their capital contributions, 99% of Available Cash from Capital Transactions will be
distributed to shareholders and 1% to the Manager.
After shareholders have received total distributions equal to their capital contributions, 85% of Available Cash from Capital Transactions will be
distributed to Investors and 15% to the Manager.General Distribution Provisions
Distributions to shareholders under the foregoing provisions will be apportioned among them in proportion to their ownership of their shares. The Manager has the sole discretion to determine the amount and frequency of any
distributions; provided, however, that a distribution may not be made selectively to one shareholder or group of shareholders but must be made ratably to all shareholders entitled to that type of distribution at that time. The Manager in its
discretion nevertheless may credit select persons with a portion of its compensation from the Fund or distributions otherwise payable to the Manager.
Because distributions, if any, will be dependent upon the earnings and financial condition of the Fund, its anticipated obligations, the Managers discretion and other factors, there can be no assurance as to the
frequency or amounts of any distributions that the Fund may make.
33



Return of Capital ContributionsIf the Fund for any reason at any time does not find it necessary or appropriate to retain or expend all capital contributions, in its sole discretion it may return any or all of such excess capital contributions ratably to
shareholders.  A return of capital contributions is not treated as a distribution. The Fund and the Manager will not be required to return any fees deducted from the original capital contribution or any costs and expenses incurred and paid by the
Fund. Any such return of capital will decrease the shareholders capital contributions.
Capital Accounts and Allocations
The tax consequences of an investment in the Fund to a shareholder in the event of dissolution depend on the shareholders capital account and on the allocations of profits and losses to that account. The Funds
taxable profits or losses are allocated among the shareholders as described below and profits or losses are added to or subtracted from the shareholders capital accounts. The amounts allocated to each shareholder will generally not be equal to
the distributions the shareholder receives until final liquidating distributions are made to shareholders.
The Fund does not currently anticipate that any contributions or distributions of property will be made. Certain additional adjustments to capital accounts will be made if necessary to account for the effects of
non-recourse debt incurred by the Fund, if any, or contributions of property, if any, to the Fund.
During the period from July 6, 2004 until December 31, 2004, the Fund issued an aggregate 350.1081 shares for gross proceeds of approximately $51.4 million. All sales of unregistered securities relied on Section 4(2) of
the Securities Act and Rule 506 of Regulation D promulgated thereunder. All of the sales were made without the use of an underwriter. All purchasers of shares represented and warranted to the Fund that they were accredited investors as defined in
Rule 501(a) under the Securities Act and that the shares were being purchased for investment and not for resale.
From the amount raised, approximately $5.5 million was disbursed for commissions and legal syndication fees. Additionally, approximately $2.3 million was paid as an investment fee to Ridgewood Energy Corporation,
the Manager, for the investigation and evaluation of investment property prospects. Remaining funds are expected to be used for exploration and development activities of oil and
natural gas properties as well as the operation of the Fund.

34



ITEM 6. SELECTED FINANCIAL DATAThe following table summarizes certain selected financial data for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004 and is derived from the audited financial
statements included herein. Although the date of formation of the Fund is May 27, 2004, the Fund did not begin business activities until July 6, 2004 when it began its private offering of shares. There were no business activities prior to 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 the Funds audited Financial Statements and related Notes.

For the period May
27, 2004 (Inception)
through December
31,
2004For the years endedDecember 31,($ in thousands except for share and per share amounts)
	
	
	
	2006
	
	
	
	2005Statement of Operations Data:Revenues
	
	$
	
	5,522
	
	$
	
	7,432
	
	
	$
	
	-Loss from operations
	
	
	
	(5,660
	)
	
	
	(5,767
	)
	
	
	
	(5,791
	)Net loss
	
	
	
	(4,800
	)
	
	
	(5,061
	)
	
	
	
	(5,685
	)Net loss per share
	
	$
	
	(14,995
	)
	$
	
	(16,623
	)
	
	$
	
	(15,906
	)Statement of Cash Flows Data:Net cash flows provided by (used in) operating activities
	
	$
	
	9,934
	
	$
	
	287
	
	
	$
	
	(2,827
	)Net cash flows used in investing activities
	
	
	
	(9,675
	)
	
	
	(12,825
	)
	
	
	
	(7,731
	)Net cash flows (used in) provided by financing activities
	
	
	
	(9,009
	)
	
	
	(839
	)
	
	
	
	45,899December 31,Balance Sheet Data:
	
	
	
	2006
	
	
	
	2005Cash and cash equivalents
	
	$
	
	13,215
	
	$
	
	21,964Salvage fund
	
	
	
	1,112
	
	
	
	1,033Oil and gas properties,
	net
	
	
	
	3,967
	
	
	
	5,934Total assets
	
	
	
	21,536
	
	
	
	35,264Total current liabilities
	
	
	
	682
	
	
	
	617Total members' capital
	
	
	
	20,505
	
	
	
	34,314Total liabilities and members' capital
	
	
	
	21,536
	
	
	
	35,264Number of shares outstanding
	
	
	
	350.1081
	
	
	
	350.1081
35



ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of Our BusinessThe Fund is an independent oil and natural gas producer. The Funds 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. The Fund began its operations by offering shares in a private offering on July 22, 2004. As a result of such offering, it raised approximately $51.4 million through the sale of 350.1081 shares of
LLC membership interests. After the payment of approximately $7.8 million in offering fees, commissions and investment fees to Ridgewood Energy Corporation, affiliates, and broker-dealers, the Fund retained approximately $43.6 million
available for investment. Investment fees represent a one time fee of 4.5% of initial capital contributions.  The fee is payable to the Manager for the service of investigating and evaluating investment opportunities and affecting
transactions.
The Manager performs certain duties on the Funds behalf including the evaluation of potential projects for investment and ongoing administrative and advisory services associated with these projects. The Fund does not
currently, nor is there any plan, to operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as
appropriate. As compensation for the above duties, the Manager is paid a onetime investment fee (4.5% of capital contributions) for the evaluation of projects on the Funds behalf and an annual management fee (2.5% of capital contributions less
dry-hole costs), payable monthly, for ongoing administrative and advisory duties as well as reimbursement of expenses. The Manager also participates in distributions. See also Item 1. Business.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in conformity with GAAP. In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of our assets and liabilities, including
the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of the Funds revenues and expenses during the periods presented. The Fund evaluates these estimates and assumptions on an
ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and their effects
cannot be predicted with absolute certainty. Therefore, the determination of estimates requires the exercise of judgment. Actual results inevitably will differ from these estimates and assumptions under different circumstances or conditions, and
such differences may be material to the financial statements. See Note 2  Summary of Significant Accounting Policies of Item 8. contained in this Form 10-K for a discussion of the Funds significant accounting policies.
Accounting for Exploration and Development Costs
Exploration and production activities are accounted for using the successful efforts method.
36



Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory
dry-hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
The costs of exploratory wells that find oil and natural gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is
completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of
those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and
operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
Proved Reserves
The Funds reserves are fully engineered on an annual basis by independent petroleum engineers. The Funds estimates of proved reserves are based on the quantities of
oil and natural gas which geological and
engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Funds control. The estimation process is very complex and relies on assumptions and subjective
interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In
addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues
to change. Estimates of proved reserves are key components of Funds most significant financial estimates involving the Funds rate for recording depreciation, depletion and amortization.
Unproved Properties
Unproved properties is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress, wells pending determination and related capitalized interest. These costs are initially
excluded from the depletion base until the outcome of the project has been determined, or generally, until it is known whether proved reserves will or will not be assigned to the property. The Fund assesses all items in its unevaluated property
balance on an ongoing basis for possible impairment or reduction in value. The Fund believes that substantially all of the costs included in its unevaluated property balance will be evaluated in the next two years.
Asset Retirement ObligationsFor oil and natural gas properties, there are obligations to perform removal and remediation
37



activities when the properties are retired.  When a project reaches drilling depth and is determined to be either proved or dry, a liability is recognized for the fair value of legally required asset retirement obligations
once it can be reasonably estimated. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole
costs.
Impairment of Long-Lived AssetsThe Fund reviews long-lived assets, including oil and natural gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested
based on identifiable cash flows (the field level for oil and gas assets) and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by
undiscounted future net cash flow estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
In the case of oil and natural gas fields, the present value of future net cash flows is based on managements best estimate of future prices, which is determined with reference to recent historical prices and
published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be
produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and natural gas prices used for
determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.
Results of Operations
The following discussion is intended to assist you in understanding the Funds results of operations and present financial condition. The Funds Financial Statements and the accompanying Notes to the Financial
Statements included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.
Net loss.Net loss for the year ended December 31, 2006 was approximately $4.8 million, a decrease of approximately $0.3 million, or 5% compared to approximately
$5.1 million for the year ended December 31, 2005.
Net loss for the year ended December 31, 2005 was approximately $5.1 million, a decrease of approximately $0.6 million, or 11% compared to approximately $5.7 million for the period May 27, 2004 (Inception)
through December 31, 2004.
See discussion below for details regarding results.
Oil and gas revenues.Oil and natural gas revenues for the year ended December 31, 2006 were approximately $5.5 million, a decrease of approximately $1.9 million, or
26% compared to approximately $7.4 million for the
38



year ended December 31, 2005. This decrease is the result of decreases in production and average sales price per
one thousand cubic feet ("MCF") for natural gas partially offset by higher production and average
sales price per one thousand cubic feet equivalent (MCFE) for oil 2006 as compared to 2005. Production volume for natural gas was approximately 386 thousand MCF and 528 thousand MCF for the years ended December 31, 2006 and 2005,
respectively. Average sales price for natural gas was approximately $8.83 per MCF and $12.47 per MCF for the years ended December 31, 2006 and December 31, 2005, respectively. Production volume for oil was approximately 153 thousand MCFE
and 87 thousand MCFE for the years ended December 31, 2006 and 2005, respectively.  Average sales price for oil was approximately $11.09 per MCFE and $9.68 per MCFE for the years ended December 31, 2006 and 2005, respectively.
Oil and natural gas revenues for the year ended December 31, 2005 were approximately $7.4 million. For the period May 27, 2004 (Inception) through December 31, 2004, the Fund had not recorded any oil and gas revenues
and was considered an exploratory stage enterprise.  The increase is the result of production of oil and natural gas in 2005 as compared to no production in 2004.
Investment fees.The Manager is paid a one time investment fee of 4.5% of initial capital contributions. The fee is payable for the service of investigating and evaluating
investment opportunities and affecting transactions when the capital contributions are made.  Investment fees incurred and paid for the period May 27, 2004 (Inception) through December 31, 2004 were approximately $2.3 million. There were no
investment fees incurred or paid in 2006 or 2005.
Dry-hole costs.Dry-hole costs for the year ended December 31, 2006 were approximately $4.9 million, a decrease of approximately $1.8 million, or 27% compared to
approximately $6.7 million for the year ended December 31, 2005. This decrease is predominately the result of plug and abandonment expenses incurred and paid in 2006 relating to two projects determined to be dry-holes, which were smaller in size
than the two projects that were determined to be dry-holes in 2005.
Dry-hole costs for the year ended December 31, 2005 were approximately $6.7 million, an increase of approximately $3.8 million, or 131% compared to approximately $2.9 million for the period May 27, 2004
(Inception) through December 31, 2004. This increase is predominately the result of plug and abandonment expenses incurred and paid in 2005 relating to two projects determined to be dry-holes compared to expenses incurred and paid in 2004 relating
to one project determined to be dry.
The following table summarizes dry-hole costs for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004.
39



For the period May
27, 2004
(Inception) through
December 31,
2004($ Thousands)
	
	For the year ended December 31,Dry-hole Costs:
	
	
	
	2006
	
	
	
	2005West Cameron 103
	
	$
	
	3
	
	$
	
	(86
	)
	
	$
	
	2,881Main Pass 155
	
	
	
	30
	
	
	
	958
	
	
	
	
	-East Cameron 48
	
	
	
	107
	
	
	
	5,786
	
	
	
	
	-East Breaks 157
	
	
	
	1,793
	
	
	
	-
	
	
	
	
	-West Cameron 78/95
	
	
	
	2,930
	
	
	
	-
	
	
	
	
	-Total Dry-hole Costs
	
	$
	
	4,863
	
	$
	
	6,658
	
	
	$
	
	2,881Depletion and amortization.Depletion and amortization for the year ended December 31, 2006 was approximately $4.2 million, a decrease of approximately $0.7 million, or
13.9% compared to approximately $4.9 million for the year ended December 31, 2005. This decrease is the result of decreased production reserve volumes in 2006 compared to 2005.
Depletion and amortization for the year ended December 31, 2005 was approximately $4.9 million, an increase of approximately $4.9 million, or 100% compared to nil for the period May 27, 2004 (Inception) through
December 31, 2004.  This increase is the result of increased production reserve volumes in 2005 compared to 2004 when no production occurred.
Lease operating expenses.Lease operating expenses represent the day to day cost of operating and maintaining wells and related facilities. For the year ended December 31, 2006
lease operating expenses were approximately $0.5 million, an increase of approximately $0.4 million, or 736% compared to approximately $0.1 million for the year ended December 31, 2005. This increase is predominately the result of
increased oil production activity in 2006 compared to 2005, offset by decreased natural gas production activity for the same period.
Lease operating expenses for the year ended December 31, 2005 were approximately $0.1 million, an increase of approximately $0.1 million, or 100% compared to nil for the period May 27, 2004 (Inception) through
December 31, 2004. This increase is predominately the result of increased oil and natural gas production activity in 2005 compared to 2004 when no production occurred.
Management fees.Management fees for the year ended December 31, 2006 were approximately $1.1 million, a decrease of approximately $0.2 million, or 11% compared to
approximately $1.3 million for the year ended December 31, 2005. The decrease is due to the fact that effective September 2006, the Manager has changed its policy regarding the annual management fee. Commencing in September 1, 2006, the
management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund.
Management fees for the year ended December 31, 2005 were approximately $1.3 million, an increase of approximately $0.8 million, or 134% compared to approximately $0.5 million for the period May 27, 2004
(Inception) through December 31, 2004. This increase is the result of the Fund having management fees for twelve months in 2005 compared to only five months in 2004.
40



Other operating expenses.Other operating expenses for the year ended December 31, 2006 was approximately $0.2 million, primarily for the casualty loss for the West Cameron
78/95 property and accretion expense.
Other operating expenses for the year ended December 31, 2005 was approximately $10 thousand, related to accretion expense.
The following table summarizes other operating expenses for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004.

For the period May
27, 2004
(Inception) through
December 31, 2004($ Thousands)
	
	For the year ended December 31,Other operating expenses:
	
	
	
	2006
	
	
	
	2005Accretion expense
	
	$
	
	16
	
	$
	
	10
	
	$
	
	-Geological costs
	
	
	
	4
	
	
	
	-
	
	
	
	-Casualty loss
	
	
	
	133
	
	
	
	-
	
	
	
	-Other operating expenses:
	
	$
	
	153
	
	$
	
	10
	
	$
	
	-Other general and administrative expenses.Other general and administrative expenses for the year ended December 31, 2006 were approximately $280 thousand, a decrease of
approximately $23 thousand, or 7.6% compared to approximately $303 thousand for the year ended December 31, 2005.  This decrease is predominately the result of a decrease in insurance costs in 2006 offset by an increase in accounting and legal fees.
Other general and administrative expenses for the year ended December 31, 2005 were approximately $303 thousand, an increase of approximately $258 thousand, or 575% compared to approximately $45 thousand for the
period May 27, 2004 (Inception) through December 31, 2004.  This increase is predominately the result of an increase in both insurance costs and accounting fees.
The following table summarizes other general and administrative expenses for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004.
41



For the period May
27, 2004
(Inception) through
December 31, 2004($ Thousands)
	
	For the year ended December 31,Other general and administrative expenses:
	
	
	
	2006
	
	
	
	2005Accounting and legal fees
	
	$
	
	158
	
	$
	
	98
	
	$
	
	26Insurance
	
	
	
	119
	
	
	
	204
	
	
	
	16Trust fees
	
	
	
	2
	
	
	
	-
	
	
	
	-Other general and administrative expenses
	
	
	
	1
	
	
	
	1
	
	
	
	3Other general and administrative expenses
	
	$
	
	280
	
	$
	
	303
	
	$
	
	45Other Income.Other income for the year ended December 31, 2006 was approximately $0.9 million, an increase of approximately $0.2 million, or 22% as compared to
approximately $0.7 million for the year ended December 31, 2005. The increase is the result of higher interest rates in 2006 compared to 2005.
Other income for the year ended December 31, 2005 was approximately $0.7 million, an increase of approximately $0.6 million, or 570% as compared to approximately $0.1 million for the period May 27, 2004
(Inception) through December 31, 2004. Other income is comprised of interest income on money market funds. In 2005, the average monthly interest income increased as a result of higher interest rates in 2005 compared to 2004. Additionally, interest
was earned for twelve months in 2005 compared to only five months in 2004.
Capital Resources and LiquidityOperating Cash Flows
Cash flow provided by operating activities for the year ended December 31, 2006 was approximately $9.9 million, primarily related to cash receipts from oil and natural gas production and a decrease in production
receivable partially offset by cash expenditures for operating expenses.
Cash flows provided by operating activities for the year ended December 31, 2005 were approximately $0.3 million, primarily related to cash receipts from oil and natural gas production partially offset by cash
expenditures for operating expenses.
Cash flows used in operating activities for the period May 27, 2004 (Inception) through December 31, 2004 were approximately $2.8 million, primarily related to the payment of the one time investment fee of approximately
$2.3 million and payments for management fees.
Investing Cash Flows
Cash flow used in investing activities for the year ended December 31, 2006 was approximately $9.7 million, primarily related to capital expenditures for oil and gas properties.  Investing activities for oil and gas
properties relate to the actual purchase of wells, infrastructure and other capital items unrelated to operating activities which occurs after a well has begun producing.
42



Cash flows used in investing activities for the year ended December 31, 2005 were approximately $12.8 million, primarily related to capital expenditures for oil and gas properties.
Cash flows used in investing activities for the period May 27, 2004 (Inception) through December 31, 2004 were approximately $7.7 million, primarily related to $3.1 million, $3.6 million and $1.0 million of
capital expenditures for oil and gas properties, payments to operators for working interests and expenditure and funding of the salvage fund, respectively.
Financing Cash Flows
Cash flows used in financing activities for the year ended December 31, 2006 were approximately $9.0 million, related to distributions to shareholders and the Manager.
Cash flows used in financing activities for the year ended December 31, 2005 were approximately $0.8 million, related to distributions to shareholders and the Manager.
Cash flows provided by financing activities for the period May 27, 2004 (Inception) through December 31, 2004 were approximately $45.9 million, primarily related to contributions from shareholders offset by syndication
costs paid for of approximately $51.4 million and $5.5 million, respectively.
We expect to meet our cash commitments for the next twelve months from our cash and investments on hand.
Estimated Capital Expenditures
The Fund has entered into multiple operating agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements can vary depending on the stage of
development on a property-by-property basis. As of December 31, 2006, such estimated capital expenditures to be spent totaled approximately $12.5 million, all of which is expected to be paid out of unspent capital contributions within the
following 12 months.
The table below presents exploration and development capital expenditures from inception as well as estimated budgeted amounts for future periods:
43





($ Thousands)Estimated Capital Expenditures:As of December 31, 2006
Projects
	
	
	
	Total Project
Costs
	
	
	
	Spent through
December 31, 2006
	
	
	
	To be Spent Next
12 MonthsEugene Island 337 (i)
	
	$
	
	4,670
	
	$
	
	3,456
	
	$
	
	1,214Galveston 248 (ii) (v)
	
	
	
	1,815
	
	
	
	-
	
	
	
	1,815Ship Shoal 81(iii) (v)
	
	
	
	1,425
	
	
	
	-
	
	
	
	1,425South Marsh Island 111 (ii) (v)
	
	
	
	1,410
	
	
	
	-
	
	
	
	1,410Vermilion 344 (iv)
	
	
	
	1,620
	
	
	
	147
	
	
	
	1,473West Delta 67 (ii) (v)
	
	
	
	1,290
	
	
	
	-
	
	
	
	1,290West Delta 68 (iv)
	
	
	
	1,380
	
	
	
	-
	
	
	
	1,380Main Pass 275 (iv)
	
	
	
	2,534
	
	
	
	67
	
	
	
	2,467$
	
	16,144
	
	$
	
	3,670
	
	$
	
	12,474(i)
	Project completion in progress, waiting on production.(ii)
	Project scheduled to begin drilling in 2nd quarter of 2007.(iii)
	Project scheduled to begin drilling in 3rd quarter of 2007.(iv)
	Project successful during 1st quarter of 2007.(v)
	Total project costs assume that the wells are commercially successful. If one of the budgeted exploratory projects are unsuccesful, budgeted development capital will be reallocated to one or more new unspecified
projects.Liquidity Needs
The Funds primary short-term liquidity needs are to fund its 2007 operations, including management fees and capital expenditures, with existing cash on-hand and income earned from its short-term investments and cash
and cash equivalents. The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. Commencing in September 2006, the management fee payable was equal to 2.5% of the total
shareholder capital contributions, net of dry-hole expenses incurred by the Fund.
Distributions, if any, are funded from cash flow from operations, and the frequency and amount are within the Managers discretion subject to available cash from operations, reserve requirements and Fund operations.
The capital raised by the Fund in its private placement is more than likely all the capital that it will be able to obtain for investments in projects. The number of projects in which the Fund can invest will naturally be
limited and each unsuccessful project the Fund experiences, if any, will not only reduce its ability to generate revenue, but also exhaust its limited supply of capital.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements as of December 31, 2006 and 2005 and does not anticipate the use of such arrangements in the future.
Contractual Obligations
The Fund enters into operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not
discuss or negotiate any such contracts. No contractual obligations exist at December 31, 2006 and 2005.
44



ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Projects drilled may not have commercially productive oil and natural gas reservoirs. In such an event, the Funds' revenue, future results of operations and financial condition would be adversely impacted.
The Fund does not have or use, any derivative instruments nor does it have any plans to enter into such derivative arrangements. The Fund will generally invest cash in high-quality credit instruments consisting primarily of
money market funds, bankers acceptance notes and government agency securities with maturities of six months or less. The Fund does not expect any material loss from cash equivalents and therefore believes its potential interest rate exposure
is not material. The Fund has no plan to conduct any international activities and therefore believes it is not subject to foreign currency risk.
The principal market risks to which the Fund is exposed that may adversely impact the Fund's results of operations and financial position are changes in oil and natural gas prices.
Low commodity prices could have an adverse affect on our future profitability and, in such an event the Fund may be required by accounting rules to write-down the carrying value of our projects. Revenue to the Fund will be
sensitive to changes in price to be received for oil and natural 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 natural gas.
Availability of alternative fuels as well as seasonal risks such as hurricanes can also impact the supply and demand.



High oil and natural gas prices have resulted in a strong demand for and a tight supply of drilling rigs necessary to drill new projects. The increased cost in daily rig rates could have a negative impact on the return to
shareholders in the Fund. The shortage of drilling rigs could delay the application of capital to such projects and thus delay revenue from operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15 and filed as
part of this report.
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING FINANCIAL DISCLOSURE
45



As reported on a Form 8-K filed with the SEC on June 14, 2006, the Manager of the Fund dismissed Perelson Weiner, LLP as the Funds independent registered public accountants effective June 8, 2006.
The Fund was formed on May 27, 2004 and filed its Registration Statement on Form 10 in April 2005; thus, the period beginning May 27, 2004 and ended December 31, 2004 was the Fund's first audited reporting period. Perelson
Weiner's audit report on the financial statements of the Fund for the period May 27, 2004 (Inception) through December 31, 2004 did not contain an adverse opinion or disclaimer of opinion, nor was such report qualified or modified as to uncertainty,
audit scope or accounting principles.
From the date of inception of the Fund through June 8, 2006, there were no disagreements with Perelson Weiner on any matter of accounting principles or practices, financial statement disclosure or auditing scope or
procedure, which disagreements, if not resolved to the satisfaction of Perelson Weiner, would have caused Perelson Weiner to make reference to the subject matter of the disagreements in their report on the Fund's financial statements for such
period.
From the date of inception of the Fund through June 8, 2006, there were no reportable events as defined in Item 304(a)(1)(v) of Regulation S-K.
As reported on a Form 8-K filed with the SEC on July 13, 2006, the Manager of the Fund appointed Deloitte & Touche LLP (D&T) as the Funds independent registered public accountants effective July
12, 2006.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Fund maintains "disclosure controls and procedures", as such term is defined under Securities and Exchange Act of 1934 (Exchange Act) Rule 13a-15(e), that are designed to ensure that information required to be disclosed in the Funds Exchange Act reports is recorded, processed, summarized
and reported within the same time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to its management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to
allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, the Funds management recognized that any controls and procedures, no matter how well designed and operated, can provide
only reasonable assurance of achieving the desired control objectives and its management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. The Fund has carried out an
evaluation, as of December 31, 2006, under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Funds
disclosure controls and procedures. Based upon their evaluation and subject to the foregoing,
such procedures were effective.
46



Changes in Internal Controls over Financial Reporting
In previous Exchange Act filings, the Fund has disclosed material weaknesses.  Corrective actions have been implemented to address these material weaknesses. As of the period covered by this report, Management believes
these material weaknesses have been remediated.
In the fourth quarter of 2006, the following material changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) have been implemented:
Expansion of accounting and SEC reporting staff and various resources, by hiring five personnel with GAAP and/or SEC accounting and reporting
expertise;
Created detailed training programs, and policies and procedures surrounding the accounting for oil and natural gas projects and GAAP and SEC financial
reporting controls; and
Enhanced tools and added appropriate resources to perform consistent, routine analytical reviews of the GAAP financial results, including key balance sheet
and income statement account analyses.Because the Fund is not an Accelerated Filer as defined in Rule 12b-2 of the Exchange Act, the Fund is not presently required to file Managements annual report on internal control over financial reporting
and the Attestation report of the registered public accounting firm required by Item 308(a) and (b) of Regulation S-K promulgated under the Securities Act.  Under current rules, because the Fund is neither a large accelerated filer nor
an accelerated filer, the Fund is not required to provide managements report on internal control over financial reporting until the Fund files its annual report for 2007 and compliance with the auditors attestation report
requirement is not required until the Fund files its annual report for 2008. The Fund currently expects to comply with these requirements at such time as the Fund is required to do so.


ITEM 9B. OTHER INFORMATION
None.
47



PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND
CORPORATE GOVERNANCE
The Fund has engaged Ridgewood Energy as Manager. Ridgewood Energy was founded in 1982 and, as Manager, has very broad authority, including the authority to appoint the executive officers of the Fund.
Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 2006 are as follows:

Name, Age and Position with Registrant
	Officer SinceRobert E. Swanson, 59President and
	Chief Executive Officer
	1982W. Greg Tabor, 46Executive Vice President and Director of Business Development
	2004Robert L. Gold, 47Executive Vice President
	1987Kathleen P. McSherry, 41Senior Vice President and Chief Financial Officer
	2000Daniel V. Gulino, 46Senior Vice President and General Counsel
	2003Adrien Doherty, 54Executive Vice President
	2006

Set forth below is the name of and certain biographical information regarding, the executive officers of Ridgewood Energy and the Fund:
Robert E. Swansonhas served as the President, Chief Executive Officer, sole director, and sole stockholder of Ridgewood Energy since its inception. Mr. Swanson is also the
controlling member of Ridgewood Renewable Power, LLC (Ridgewood Power) and Ridgewood Capital Corporation (Ridgewood Capital), affiliates of Ridgewood Energy. Mr. Swanson has been President and registered principal of
Ridgewood Securities Management, LLC and has served as the Chairman of the Board of Ridgewood Capital since its organization in 1998. Mr. Swanson is a member of the New York State and New Jersey State Bars, the Association of the Bar of the City of
New York and the New York State Bar Association. He is a graduate of Amherst College and Fordham University Law School.
Greg Taborhas 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.
48



Robert L. Goldhas 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 State Bar. He is a graduate of Colgate University and New York University School of Law.
Kathleen P. McSherryhas 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 Chief Financial Officer in 2000. Ms. McSherry also serves as Vice President of Systems and Administration of Ridgewood Power. Ms. McSherry holds a Bachelor of
Science degree in Accounting from Kean University.
Daniel V. Gulinohas served as Senior Vice President and General Counsel of Ridgewood Energy since August 2003. Mr. Gulino also serves as Senior Vice President and General
Counsel of Ridgewood Power Management, Ridgewood Power, and Ridgewood Capital and has done so since 2000. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. He is a graduate of Fairleigh Dickinson
University and Rutgers School of Law.
Adrien Dohertyhas served as Executive Vice President of Ridgewood Energy since 2006. Mr. Doherty joined Ridgewood Energy after a thirty year career in investment banking, most
recently as Head of Barclays Capitals oil and gas banking effort. Mr. Doherty is a graduate of Amherst College and the Wharton Graduate Division of the University of Pennsylvania.
Board of Directors and Board Committees
The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure. Officers of the Fund are not
compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11 of this Form 10-K. Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager,
the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.
Section 16(a) Beneficial Ownership Reporting ComplianceSection 16(a) of the Securities Exchange Act of 1934, as amended, requires the Funds executive officers and directors, and persons who own more than 10% of a registered class of the Funds equity securities, to
file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, 2006, all filing requirements
applicable to its officers, directors and 10% beneficial owners were met.
ITEM 11. EXECUTIVE COMPENSATIONThe executive officers of the Fund do not receive compensation from the Fund. The Manager, or its affiliates, compensates the officers without additional payments by the Fund. See Item 13. Certain Relationships and
Related Party Transactions, and Director Independence for more information regarding Manager compensation and payments to affiliated entities.
49



Compensation Discussion and Analysis
The executive officers of the Fund, Mr. Swanson, Mr. Tabor, Mr. Gold, Ms. McSherry, Mr. Gulino and Mr. Doherty, are employed by, and are executive officers of, the Manager, Ridgewood Energy, and provide managerial services
to the Fund in accordance with the terms of the Funds LLC agreement. The Fund does not have any other executive officers. The Manager determines and pays the compensation of these officers. Each of the executive officers of the Fund
also serves as an executive officer of each of the other funds managed by the Manager. Because the executive officers are employees of our Manager and provide managerial services to all of the funds managed by our Manager in the course of such
employment, they do not receive additional compensation for providing managerial services to the Fund or to any one or more new funds established by the Manager than they would otherwise receive from the Manager if they did not serve in such
capacities for the Fund or any such other funds.

The Manager is fully responsible for the payment of compensation to the executive officers. The Fund does not pay any compensation to its executive officers and does not reimburse the Manager for the compensation paid to
executive officers. The Fund does, however, pay the Manager a management fee and the Manager may determine to use a portion of the proceeds from the management fee to pay compensation to executive officers of the Fund.
Report of the Manager
Because the Fund is managed by the Manager and does not have a Board of Directors or a Compensation Committee, the Manger reviewed and discussed with management the Compensation Discussion and Analysis included in the proxy
statement. Based on such review and discussion, the Manager determined that the Compensation Discussion and Analysis be included in the proxy statement for filing with the Securities and Exchange Commission.
Submitted by the ManagerRobert E. Swanson, Chairman
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED SECURITY HOLDER MATTERS
The following table sets forth information with respect to beneficial ownership of the shares as of December 31, 2006 (no person owns more than 5% of the shares) by:
each executive officer (there are no directors); and
all of the executive officers as a group.50


Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Except as indicated by footnote, and subject to applicable community
property laws, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them. Percentage of beneficial ownership is based on 350.1081 shares outstanding at December 31, 2006
and 2005. Other than the below, no officer and director owns any of the Fund's shares.
Number
of sharesName of beneficial owner
	
	
	
	
	PercentRobert E. Swanson (1), President and ChiefExecutive Officer
	
	
	
	0.6667
	
	*Executive officers as a group (1)
	
	
	
	0.6667
	
	** Represents less than one percent. (1) Includes shares owned by Mr. Swansons family members and Trusts, which he controls.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS,
AND DIRECTOR INDEPENDENCE
In connection with the sale of shares in 2004, Ridgewood Securities Corporation, an affiliate of the Manager, earned a placement fee and commissions totaling approximately $0.7 million included in syndication costs. The
Manager earned an investment fee for the services of investigating and evaluating projects for future investment totaling approximately $2.3 million.
The Manager was paid approximately $1.8 million to cover legal and syndication fees for the organization, distribution and offering expenses.
The Manager received a management fee, payable monthly, equal to 2.5% of total capital contributions, for general and administrative and management services supplied to the Fund. Additionally, when distributions are made,
the Manager is entitled to a portion of funds distributed to shareholders.
Effective September 1, 2006, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the
Fund. For the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004 the Manager was paid management fees which totaled approximately $1.1 million, $1.3 million and $0.5 million,
respectively.
Profits and losses are allocated in accordance with the LLC agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager.  The primary exception to this treatment is that
all items of expense, loss, deduction and credit attributable to the expenditure of shareholders' capital contributions are allocated 99% to shareholders and 1% to the Manager. For the years ended December 31, 2006 and 2005 and for the period May
27, 2004 (Inception) through December 31, 2004 the Manager was paid distributions which totaled $1.4 million, $0.1 million and nil, respectively.
51



ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table presents fees and services rendered by Deloitte and Touche, LLP for the year ended December 31, 2006 and Perelson Weiner, LLP for the year ended December 31, 2005 and for the period May 27, 2004
(Inception) through December 31, 2004.

For the period May
27, 2004
(Inception) through
December 31, 2004($ Thousands)
	
	For the year ended December 31,Accounting Fees and Sevices
	
	
	
	2006
	
	
	
	2005Audit fees (1)
	
	$
	
	144
	
	$
	
	86
	
	$
	
	14Tax fees (2)
	
	
	
	14
	
	
	
	12
	
	
	
	12$
	
	158
	
	$
	
	98
	
	$
	
	26(1)
	Fees for audit of finanancial statements, reviews of the related quarterly financial statements and reviews of documents filed with the SEC.(2)
	Fees related to professional services for tax compliance, tax advice and tax planning.52



PART IV.


ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS(a) Index to Financial Statements:Report of Independent Registered Public Accounting Firm
        F-1Balance Sheets as of December 31, 2006 and 2005
        F-2Statements of Operations for the years ended December 31, 2006 and 2005 and for the period May
  27, 2004   (Inception) through December 31, 2004
        F-3Statements of Changes in Members Capital for the years ended December 31, 2006 and 2005 and
			
 for the period May 27, 2004 (Inception) through December 31, 2004
        F-4Statements of Cash Flows for the years ended December 31, 2006 and 2005 and  for the period
			
  May 27, 2004   (Inception) through December 31, 2004
        F-5Notes to Audited Financial Statements
        F6-15(b) Exhibits:Exhibits required by Section 601 of Regulation S-K.Exhibit No.
        Description3
        (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 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 Main Pass project (incorporated by reference to Exhibit 10.4 of RegistrantsRegistration 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'sRegistration Statement on Form 10-12G/A
			filed with the Commission on September 2, 2005.10.6
        
        Assignment of Contractual Rights for West Cameron 556 and East Cameron 299 between Millennium Offshore Group, Inc. and Ridgewood Energy Corporation as Manager of the Registrant (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).10.7
        *
        Participation Agreement between Gryphon Exploration Company (Woodside) and Ridgewood Energy Corporation as Manager of the Registrant for East Breaks 157.10.8
        *
        Participation Agreement between Devon Energy and Ridgewood Energy Corporation as Manager of the Registrant for Eugene Island 337.10.9
        *
        Participation Agreement between El Paso Corporation and Ridgewood Energy Corporation as Manager of theRegistrant for West Cameron 95.10.10
        *
        Participation Agreement 2007 multi-well program between LLOG Exploration and Ridgewood EnergyCorporation as Manager of the Registrant for Galveston 248, Ship Shoal 81, South Marsh Island 111,Vermillion 344, West Delta 67 and West Delta 68.14
        
        Code of Ethics, adopted on
			May 27, 2004 (incorporated by reference to the Registrants Form 10-K filed with the SEC on March 14, 2006).31.1
        *
        Certification of Robert E. Swanson, Chief Executive Officer of the Registrant, pursuant to Securities Exchange Act Rule 13a-14(a).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
53



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Manager of Ridgewood Energy L Fund, LLC:
We have audited the accompanying balance sheets of Ridgewood Energy L Fund, LLC (the Fund) as of December 31, 2006 and 2005, and the related statements of operations, changes in members capital, and cash
flows for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004. These financial statements are the responsibility of the Funds management. Our responsibility is to express an opinion
on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control
over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Funds internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy L Fund, LLC
as of December 31, 2006 and 2005, and the results of its operations and its cash flows
for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004 in conformity with accounting principles generally accepted in the United States of America
/s/ Deloitte & Touche LLPMarch 30, 2007Parsippany, New Jersey
F-1


RIDGEWOOD ENERGY L FUND, LLC
BALANCE SHEETS
(in thousands, except number of shares)





December 31,2006
	
	
	
	
	2005AssetsCurrent Assets:Cash and cash equivalents
	
	$
	
	13,215
	
	
	$
	
	21,964Production receivable
	
	
	
	251
	
	
	
	
	6,067Insurance receivable
	
	
	
	2,534
	
	
	
	
	-Interest receivable
	
	
	
	-
	
	
	
	
	-Due from operators
	
	
	
	247
	
	
	
	
	250Due from affiliate (Note 6)
	
	
	
	196
	
	
	
	
	-Prepaid expenses
	
	
	
	14
	
	
	
	
	16Total current assets
	
	
	
	16,457
	
	
	
	
	28,297Salvage fund
	
	
	
	1,112
	
	
	
	
	1,033Oil and gas propertiesAdvances to operators for working interests and expenditures
	
	
	
	-
	
	
	
	
	1,256Proved properties
	
	
	
	9,379
	
	
	
	
	9,359Unproved properties
	
	
	
	3,670
	
	
	
	
	197Less: accumulated depletion and amortization-proved properties
	
	
	
	(9,082
	)
	
	
	
	(4,878
	)Total oil and gas properties, net
	
	
	
	3,967
	
	
	
	
	5,934Total assets
	
	$
	
	21,536
	
	
	$
	
	35,264Liabilities and Members' CapitalCurrent Liabilities:Due to operators
	
	$
	
	540
	
	
	$
	
	570Due to affiliate (Note 6)
	
	
	
	-
	
	
	
	
	6Accrued expenses payable
	
	
	
	142
	
	
	
	
	41Total current liabilities
	
	
	
	682
	
	
	
	
	617Non-current liabilitiesAsset retirement obligations
	
	
	
	349
	
	
	
	
	333Total non-current liabilities
	
	
	
	349
	
	
	
	
	333Total liabilities
	
	
	
	1,031
	
	
	
	
	950Commitments and contingencies (Note 8)Members' capital:Manager:Distributions
	
	
	
	(1,477
	)
	
	
	
	(126
	)Retained Earnings
	
	
	
	1,092
	
	
	
	
	642Manager's total
	
	
	
	(385
	)
	
	
	
	516Shareholders:Capital contributions(670 shares authorized; 350.1081 issued and outstanding)
	
	
	
	51,401
	
	
	
	
	51,401Distributions
	
	
	
	(8,371
	)
	
	
	
	(713
	)Syndication costs
	
	
	
	(5,502
	)
	
	
	
	(5,502
	)Accumulated deficit
	
	
	
	(16,638
	)
	
	
	
	(11,388
	)Shareholders' total
	
	
	
	20,890
	
	
	
	
	33,798Total members' capital
	
	
	
	20,505
	
	
	
	
	34,314Total liabilities and members' capital
	
	$
	
	21,536
	
	
	$
	
	35,264The accompanying notes are an integral part of these financial statements.
F-2



RIDGEWOOD ENERGY L FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
For the period May
27, 2004
(Inception) through
December 31, 2004For the Years ended December 31,2006
	
	
	
	
	2005RevenuesOil and gas revenues
	
	$
	
	5,522
	
	
	$
	
	7,432
	
	
	$
	
	-ExpensesInvestment fees to affiliate (Note 6)
	
	
	
	-
	
	
	
	
	-
	
	
	
	
	2,316Dry-hole costs
	
	
	
	4,863
	
	
	
	
	6,658
	
	
	
	
	2,881Depletion and amortization
	
	
	
	4,202
	
	
	
	
	4,879
	
	
	
	
	-Lease operating expenses
	
	
	
	535
	
	
	
	
	64
	
	
	
	
	-Management fees to affiliate (Note 6)
	
	
	
	1,149
	
	
	
	
	1,285
	
	
	
	
	549Other operating expenses
	
	
	
	153
	
	
	
	
	10
	
	
	
	
	-Other general and administrative expenses
	
	
	
	280
	
	
	
	
	303
	
	
	
	
	45Total expenses
	
	
	
	11,182
	
	
	
	
	13,199
	
	
	
	
	5,791Loss from operations
	
	
	
	(5,660
	)
	
	
	
	(5,767
	)
	
	
	
	(5,791
	)Other incomeInterest income
	
	
	
	860
	
	
	
	
	706
	
	
	
	
	106Total other income
	
	
	
	860
	
	
	
	
	706
	
	
	
	
	106Net loss
	
	$
	
	(4,800
	)
	
	$
	
	(5,061
	)
	
	$
	
	(5,685
	)Manager - Net income (loss)
	
	$
	
	450
	
	
	$
	
	759
	
	
	$
	
	(117
	)Shareholders - Net loss
	
	$
	
	(5,250
	)
	
	$
	
	(5,820
	)
	
	$
	
	(5,568
	)Net loss per share
	
	$
	
	(14,995
	)
	
	$
	
	(16,623
	)
	
	$
	
	(15,906
	)The accompanying notes are an integral part of these financial statements.

F-3



RIDGEWOOD ENERGY L FUND, LLC
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(in thousands, except number of shares)
For the period May 27, 2004 (Inception) through December 31, 2004# of Shares
	
	
	
	Manager
	
	
	Shareholders
	
	
	
	
	TotalBalances, May 27, 2004 (Inception)Shareholders capital contribution
	
	350.1081
	
	$
	
	-
	
	
	$
	
	51,401
	
	
	$
	
	51,401Syndication costs
	
	-
	
	
	
	-
	
	
	
	
	(5,502
	)
	
	
	
	(5,502
	)Net loss
	
	-
	
	
	
	(117
	)
	
	
	
	(5,568
	)
	
	
	
	(5,685
	)Balances, December 31, 2004
	
	350.1081
	
	$
	
	(117
	)
	
	$
	
	40,331
	
	
	$
	
	40,214For the year ended December 31, 2005# of Shares
	
	
	
	Manager
	
	
	
	
	Shareholders
	
	
	
	
	TotalBalances, January 1, 2005
	
	350.1081
	
	$
	
	(117
	)
	
	$
	
	40,331
	
	
	$
	
	40,214Distributions
	
	-
	
	
	
	(126
	)
	
	
	
	(713
	)
	
	
	
	(839
	)Net income (loss)
	
	-
	
	
	
	759
	
	
	
	
	(5,820
	)
	
	
	
	(5,061
	)Balances, December 31, 2005
	
	350.1081
	
	$
	
	516
	
	
	$
	
	33,798
	
	
	$
	
	34,314For the year ended December 31, 2006# of Shares
	
	
	
	Manager
	
	
	
	
	Shareholders
	
	
	
	
	TotalBalances, January 1, 2006
	
	350.1081
	
	$
	
	516
	
	
	$
	
	33,798
	
	
	$
	
	34,314Distributions
	
	-
	
	
	
	(1,351
	)
	
	
	
	(7,658
	)
	
	
	
	(9,009
	)Net income (loss)
	
	-
	
	
	
	450
	
	
	
	
	(5,250
	)
	
	
	
	(4,800
	)Balances, December 31, 2006
	
	350.1081
	
	$
	
	(385
	)
	
	$
	
	20,890
	
	
	$
	
	20,505The accompanying notes are an integral part of these financial statements.

F-4





RIDGEWOOD ENERGY L FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
For the period May
27, 2004
(Inception) through
December 31,
2004For the years ended December 31,2006
	
	
	
	
	2005Cash flows from operating activitiesNet loss
	
	$
	
	(4,800
	)
	
	$
	
	(5,061
	)
	
	$
	
	(5,685
	)Adjustments to reconcile loss to net cashprovided by (used in) operating activitiesDry-hole costs
	
	
	
	4,863
	
	
	
	
	6,658
	
	
	
	
	2,881Depletion and amortization
	
	
	
	4,202
	
	
	
	
	4,879
	
	
	
	
	-Accretion expense
	
	
	
	16
	
	
	
	
	10
	
	
	
	
	-Changes in assets and liabilitiesDecrease (Increase) in production receivable
	
	
	
	5,816
	
	
	
	
	(6,067
	)
	
	
	
	-Decrease in due from operators
	
	
	
	(247
	)
	
	
	
	(250
	)
	
	
	
	-Decrease (Increase) in interest receivable
	
	
	
	-
	
	
	
	
	17
	
	
	
	
	(17
	)Decrease in due from affiliate
	
	
	
	-
	
	
	
	
	6
	
	
	
	
	-Decrease (Increase) in prepaid expenses
	
	
	
	2
	
	
	
	
	6
	
	
	
	
	(22
	)(Decrease) Increase in due to operators
	
	
	
	(13
	)
	
	
	
	64
	
	
	
	
	-Increase in accrued expenses payable
	
	
	
	101
	
	
	
	
	25
	
	
	
	
	16Decrease in due to affiliate
	
	
	
	(6
	)
	
	
	
	-
	
	
	
	
	-Net cash provided by (used in) operating activities
	
	
	
	9,934
	
	
	
	
	287
	
	
	
	
	(2,827
	)Cash flows from investing activitiesPayments to operators for working interests and expenditures
	
	
	
	-
	
	
	
	
	(1,256
	)
	
	
	
	(3,636
	)Capital expenditures for oil and gas properties
	
	
	
	(9,596
	)
	
	
	
	(11,540
	)
	
	
	
	(3,090
	)Funding of salvage fund
	
	
	
	(30
	)
	
	
	
	-
	
	
	
	
	(1,000
	)Interest income reinvested - salvage fund
	
	
	
	(49
	)
	
	
	
	(29
	)
	
	
	
	(5
	)Net cash by used in investing activities
	
	
	
	(9,675
	)
	
	
	
	(12,825
	)
	
	
	
	(7,731
	)Cash flows from financing activitiesContributions from shareholders
	
	
	
	-
	
	
	
	
	-
	
	
	
	
	51,401Syndication costs paid
	
	
	
	-
	
	
	
	
	-
	
	
	
	
	(5,502
	)Distributions paid
	
	
	
	(9,009
	)
	
	
	
	(839
	)
	
	
	
	-Net cash (used in) provided by financing activities
	
	
	
	(9,009
	)
	
	
	
	(839
	)
	
	
	
	45,899Net (decrease) increase in cash and cash equivalents
	
	
	
	(8,750
	)
	
	
	
	(13,377
	)
	
	
	
	35,341Cash and cash equivalents, beginning of period
	
	
	
	21,964
	
	
	
	
	35,341
	
	
	
	
	-Cash and cash equivalents, end of period
	
	$
	
	13,215
	
	
	$
	
	21,964
	
	
	$
	
	35,341Supplemental schedule of non-cash investing activitiesAdvances used for capital expenditures in oil and gas propertiesreclassified to proved properties
	
	$
	
	-
	
	
	$
	
	3,636
	
	
	$
	
	-Advances used for capital expenditures in oil and gas propertiesreclassified to dry-hole
	
	$
	
	1,256
	
	
	$
	
	-
	
	
	$
	
	-The accompanying notes are an integral part of these financial statements.
F-5



RIDGEWOOD ENERGY L FUND, LLCNOTES TO FINANCIAL STATEMENTS
1. Organization and PurposeThe 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 (LLC agreement) dated as of
July 6, 2004 by and among Ridgewood Energy Corporation (Manager) and the shareholders of the Fund. Although the date of formation is May 27, 2004, the Fund did not begin business activities until July 6, 2004 when it began its private
offering of shares. The Fund had no business activities prior to July 6, 2004.
The Fund was organized to acquire, drill, construct and develop oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.  The Fund has devoted most
of its efforts to raising capital and oil and natural gas exploration activities.  The Fund began earning revenue in September 2005 from these operations and ceased to be in the exploratory stage during the fourth quarter of 2005.
The Manager performs (or arranges for the performance of) the management, administrative and advisory services required for Fund operations.  Such services include, without limitation, the administration of shareholder
accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The
Manager also engages and manages the contractual relations with outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required (Notes 2, 5 and 6).
2. Summary of Significant Accounting Policies
Use of EstimatesThe 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.
Advances to Operators for Working Interests and Expenditures
The Funds acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Funds rights, title and interest. The Fund is required to advance its share of estimated
cash outlay for the succeeding months operation.  The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are transferred to unproved properties.
F-6



Oil and natural gas propertiesInvestments in oil and natural 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 natural gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and natural gas exploration costs, excluding the costs of
drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves.  If proved commercial reserves have
not been found, exploratory drilling costs are expensed to dry-hole expense.  Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of crude oil and natural gas,
are capitalized. Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred.
Upon the sale or retirement of a proved property (i.e. a producing well), the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss, if any, 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 impairments. It is not the Managers
intention to sell any of the Funds property interests.
Capitalized acquisition costs of producing oil and natural gas properties after recognizing estimated salvage values are depleted by the unit-of-production method.
As of December 31, 2006 and 2005 amounts recorded in due to operators totaling approximately $0.5 million and $0.5 million, respectively, related to the acquisition of oil and gas property. In 2006, the December 31,
2005 due to operators balance was paid.
Revenue RecognitionOil and natural 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). At the time of transfer a
production receivable is recorded. The Fund earned revenue for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004 of approximately $5.5 million, $7.4 million and nil,
respectively.
The volume of oil and natural gas sold on the Funds behalf may differ from the volume of oil and natural gas to which the Fund is entitled. The Fund will account for such oil and natural gas production imbalances by
the entitlements method.  Under the entitlements method, the Fund will recognize a receivable from other working interest owners for volumes oversold by other working interest owners. For volumes oversold by the Fund, a payable to other working
interest owners will be recorded.  As of December 31, 2006 and 2005 there were no material oil or natural gas balancing arrangements between the Fund and other working interest owners.
F-7



Syndication Costs
Direct costs associated with offering the Funds shares including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and outside brokers are reflected as a
reduction of shareholders capital.
Asset Retirement ObligationsFor oil and natural gas properties, there are obligations to perform removal and remediation activities when the properties are retired.  When a project reaches drilling depth and is determined to be either proved or dry,
an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.

($ Thousands)
	
	
	December 31,Asset Retirement Obligations:
	
	
	2006
	
	
	
	2005Balance - Beginning of period
	
	$
	333
	
	
	$Liabilities incurred
	
	
	237
	
	
	
	620Liabilities settled
	
	
	(237
	)
	
	
	(297
	)Accretion expense
	
	
	16
	
	
	
	10Balance - End of period
	
	$
	349
	
	
	$
	333Impairment of Long-Lived AssetsIn accordance with the provisions of SFAS No. 144, Accounting for the Impairment of Long-Lived Assets, long-lived assets, such as oil and natural gas properties, are evaluated when events or changes in
circumstances indicate the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is made by comparing the carrying values of long-lived assets to the estimated future undiscounted cash
flowsattributable to the asset. The impairment loss recognized is the excess of the carrying value over the future discounted cash flows attributable to the asset or
the estimated fair value of the asset. For the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004 the Fund had no impairments of long-lived assets.
Depletion and AmortizationDepletion and amortization of the cost of proved oil and natural gas properties are calculated using the units of production method.  Proved developed reserves are used as the base for depleting the cost of successful
exploratory drilling and development costs. The sum of proved developed and proved undeveloped reserves is used as the base for depleting (or amortizing) leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline
costs. South Timbalier 77 was determined to have proved reserves in 2005. As of December 31, 2006 and 2005, the Fund had recorded accumulated depletion and amortization of approximately $9.1 million and $4.9 million, respectively.
Income TaxesNo provision is made for income taxes in the financial statements because the Fund is a limited liability corporation. The income or losses are passed through and included in the tax returns of the individual
shareholders.
F-8



Cash and cash equivalentsAll 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, 2006
and 2005, respectively, bank balances exceeded federally insured limits by approximately $13.0 million and $21.8 million, respectively.  The Fund maintains bank deposits with accredited financial institutions to mitigate such
risk.
Salvage FundThe Fund deposits in a separate interest-bearing account, or a salvage fund, money to provide for dismantling production platforms and facilities, plugging and abandoning the wells and removing the platforms, facilities and
wells after their useful lives, in accordance with applicable federal and state laws and regulations. Interest earned on the account will become part of the salvage fund.
At times, the Fund may purchase short-term investments comprised of US Treasury Notes with maturities greater than three months and as such are considered held-to-maturity investments. Held-to-maturity securities are those
investments that the Fund has the ability and intent to hold until maturity. Held-to-maturity investments are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate market value.  Interest
income is accrued as earned. Held to maturity investments of approximately $1.1 million included in the salvage fund as of December 31, 2006, matured in February 2007. There were no held to maturity investments as of December 31, 2005.
Income and Expense AllocationProfits 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 that are attributable to the
expenditure of shareholders capital contributions, which are allocated 99% to shareholders and 1% to the Manager. Effective September 2006, the Manager has changed its policy regarding the annual management fee. Commencing in September 1,
2006, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund.
3.Recent Accounting StandardsIn February 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159), which permits
entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. An entity would report unrealized gains and losses on items for which the fair value option has been
elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities
differently without having to apply complex hedge accounting provisions. The decision about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and it is applied only to
entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and
(b) between assets and liabilities in the financial statements
F-9



of an entity that selects different measurement attributes for similar assets and liabilities. SFAS No. 159 is effective for financial statements issued for
fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year provided the entity also elects to apply the provisions of SFAS No. 157, Fair Value Measurements, (SFAS No.157).
Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings. Since the provisions of SFAS No.159 are applied prospectively, any
potential impact will depend on the instruments selected for fair value measurement at the time of implementation. The Fund does not believe that its financial position, results of operations or cash flows will be impacted by the adoption of SFAS
No. 159.
In September 2006, the FASB issued SFAS No. 157, which applies under most other accounting pronouncements that require or permit fair value measurements.  SFAS No. 157 provides a common definition of fair value as the price
that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair
value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Fund does not expect this guidance to have a material impact on the financial statements.
In September 2006, the SEC Staff issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements, (SAB No. 108) in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the two methods
used for quantifying the effects of financial statement errors were the rollover and iron curtain methods. Under the rollover method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The iron
curtain method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a dual approach which requires the quantification of the
effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the dual approach method in the first year ending after November
16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the
nature and amount of each error being corrected and how and when they arose. The Fund has adopted the provisions of SAB No. 108 and there was no impact to its financial position, results of operations and cash flows as a result of this
pronouncement.
4. Unproved Properties - Capitalized Exploratory Well Costs
Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if
sufficient progress is made on assessing the reserves. Capitalization costs are expensed as dry-hole costs in the event that reserves are not found or are
not in sufficient quantities to complete the well and develop the
F-10



field.  Dry-hole costs were approximately $4.9 million, $6.7 million and $2.9 million for the years ended December 31, 2006 and 2005 and for the
period May 27, 2004 (Inception) through December 31, 2004, respectively.
The following table reflects the net changes in unproved properties as of December 31, 2006 and 2005. As of December 31, 2006 and 2005, the Fund had no capitalized exploratory well costs greater than one year.

($ Thousands)
	December 31,Exploratory Drilling Costs:
	
	
	2006
	
	
	
	2005Balance - Beginning of period
	
	$
	197
	
	
	$
	209Additions to capitalized exploratory well costs pending thedetermination of proved reserves
	
	
	3,542
	
	
	
	9,347Reclassification to proved properties based on thedetermination of proved reserves
	
	
	-
	
	
	
	(9,359
	)Capitalized exploratory well costs charged to dry-hole costs
	
	
	(69
	)
	
	
	-Balance - End of period
	
	$
	3,670
	
	
	$
	1975.DistributionsDistributions to shareholders are allocated in proportion to the number of shares held.
The Manager will determine whether Available Cash from Operations, as defined in the Funds LLC agreement, is to be distributed.  Such distribution would be allocated 85% to the shareholders and 15% to the Manager, as
defined in the Funds LLC agreement.
Available Cash from Dispositions, as defined in the Fund's LLC agreement, 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 shareholders received distributions of approximately $7.7 million and $0.7 million for the years ended December 31, 2006 and 2005, respectively.
The Manager received distributions of approximately $1.4 million and $0.1 million for the years ended December 31, 2006 and 2005, respectively.
There were no distributions in the period May 27, 2004 (Inception) through December 31, 2004.
6. Related PartiesThe Manager was 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 approximately $2.3 million were paid for the period May 27, 2004 (Inception) through December 31, 2004. There were no investment fees incurred or paid in 2006 or 2005.


F-11


The Funds LLC agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager receives an annual management fee, payable monthly, of 2.5% of total capital
contributions.  Effective September 2006, the Manager has changed its policy regarding the annual management fee. Commencing on September 1, 2006, the management fee, payable monthly, will be equal to 2.5% of the total shareholder capital
contributions, net of dry-hole expenses incurred by the Fund.  Management fees of approximately $1.1 million, $1.3 million, and $0.5 million were incurred and paid for the years ended December 31, 2006 and 2005 and for the period May 27, 2004 (Inception) through December 31, 2004, respectively.
From time to time, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.  As of December 31, 2006 and 2005 approximately $0.2
million and nil was due from the Manager. As of December 31, 2006 and 2005 nil and approximately $6 thousand was due to the Manager.
None of the compensation to be received by the Manager has been derived as a result of arms length negotiations.
The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
7. Fair Value of Financial InstrumentsAt December 31, 2006 and 2005, the carrying value of cash and cash equivalents, and salvage fund, approximate fair value.
8. Commitments and ContingenciesEnvironmental ConsiderationsThe exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The
Manager and the Operators are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental
regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and natural gas industry. However, due to the significant public and governmental interest in
environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims.  At December 31, 2006 and 2005 there were no known environmental issues that
required the Fund to record a liability.
Insurance CoverageThe Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from
F-12




uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event which is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a
package covering all of the Managers investment programs. Claims made by other such programs can reduce or eliminate insurance for the Fund.
The Fund records receivables for insured costs when the expected insurance proceeds are estimable and probable of receipt. On May 22, 2006, the Fund reported a claim to its insurance carrier for cost recovery related to
the West Cameron 78/95 project. The project was determined to be a dry-hole.  An insurance recovery receivable of approximately $2.5 million has been recorded at December 31, 2006 relative to this claim, net of its approximate $0.1 million deductible.
9. Information About Oil and Natural Gas Producing Activities
In accordance SFAS No. 69, Disclosures About Oil and Gas Producing Activities, this section provides supplemental information on oil and natural gas exploration and producing activities of the Fund.
The Fund is engaged solely in oil and natural gas activities, all of which are located in the United States offshore waters of Texas, Louisiana Alabama in the Gulf of Mexico.

Table I - Capitalized Costs Related to Oil and Gas Exploration and Producing Activities (in thousands)
December 31,2006
	
	
	
	
	2005Proved oil and gas properties
	
	$
	
	9,379
	
	
	$
	
	9,359Unproved oil and gas properties
	
	
	
	3,670
	
	
	
	
	197Advances to operators for working interests and expenditures
	
	
	
	-
	
	
	
	
	1,256Total oil and gas properties
	
	$
	
	13,049
	
	
	$
	
	10,812Accumulated depletion and amortization - proved properties
	
	
	
	(9,082
	)
	
	
	
	(4,878
	)Oil and gas properties - net
	
	$
	
	3,967
	
	
	$
	
	5,934Table II - Costs Incurred in Exploration, Property Acquisitions and Development 
	(in thousands)

For the period May
27, 2004
(Inception) through
December 31, 2004For the year ended December 31,2006
	
	
	2005Exploratory drilling costs - capitalized
	
	$
	3,492
	
	$
	6,968
	
	$
	
	3,845Exploratory drilling costs - expensed
	
	
	3,607
	
	
	6,658
	
	
	
	2,881$
	7,099
	
	$
	13,626
	
	$
	
	6,726F-13




Table III - Reserve Quantity Information (Unaudited)
Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer for the years ended December 31, 2006 and 2005. The Fund had no proved developed and undeveloped reserves prior to 2005. The reserve
estimates for December 31, 2006 and 2005 were based on estimated future reserves as of September 30, 2006 and 2005 further adjusted for fourth quarter production and year end pricing. These reserves have been prepared in compliance with the
Securities and Exchange Commission rules.
Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
United StatesFor the year ended December 31,2006
	
	2005Oil
	
	
	Gas
	
	
	Oil
	
	
	Gas(BBLS)
	
	
	(MCF)
	
	
	(BBLS)
	
	
	(MCF)Proved developed reserves:Beginning of Year
	
	15,801
	
	
	325,496
	
	
	-
	
	
	-Discoveries
	
	-
	
	
	-
	
	
	30,335
	
	
	850,418Revisions of previous estimates
	
	38,934
	
	
	338,062
	
	
	-
	
	
	-Production
	
	(25,480
	)
	
	(446,280
	)
	
	(14,534
	)
	
	(524,922
	)End of Year
	
	29,255
	
	
	217,278
	
	
	15,801
	
	
	325,496Due to the inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

Table IV - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Unaudited) (in thousands)
Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by
applying year-end prices of oil and gas relating to the Fund's proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming
continuation of existing economic conditions. The Fund had no proved oil and natural gas reserves prior to 2005.
For the year ended December 31,2006
	
	
	
	2005Future estimated revenue
	$
	3,013
	
	
	$
	5,182Future estimated production costs
	
	(542
	)
	
	
	(568
	)Future estimated development costs
	
	(160
	)
	
	
	-Future net cash flows
	
	2,311
	
	
	
	4,61410% annual discount for estimated timing of cash flows
	
	(485
	)
	
	
	(225
	)Standardized measure of discounted future estimated net cash flows
	$
	1,826
	
	
	$
	4,389F-14



Table V - Changes in the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Unaudited) (in thousands)
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 Fund had no
proved oil and natural gas reserves prior to 2005.
For the year ended December 31,2006
	
	
	
	2005Standardized measure beginning of the year
	
	$
	4,389
	
	
	$
	-Sales of oil and gas production, net of production costs
	
	
	(4,988
	)
	
	
	(7,368
	)Net changes in prices and production costs
	
	
	-
	
	
	
	-Extensions, discoveries, and improved recovery andtechniques, less related costs
	
	
	-
	
	
	
	11,365Revision of development costs
	
	
	(160
	)
	
	
	-Revision of previous reserve quantities estimate
	
	
	2,763
	
	
	
	-Accretion of discount
	
	
	147
	
	
	
	392Timing and other
	
	
	(325
	)
	
	
	-Standard measure end of the year
	
	$
	1,826
	
	
	$
	4,389It 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 arbitrary assumptions. Reserve quantities cannot be measured with revision 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 limitation inherent therein.

F-15



SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
RIDGEWOOD ENERGY L FUND, LLCDate: March 30, 2007By:
		/s/
ROBERT E. SWANSONName:
		
		Robert E. SwansonTitle:
		
		Chief Executive Officer(Principal Executive Officer)Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
	
	Capacity
	
	Date/s/ ROBERT E. SWANSON
	
	Chief Executive Officer
	
	March 30, 2007Robert E. Swanson
	
	(Principal Executive Officer)/s/ KATHLEEN P. MCSHERRY
	
	Senior Vice President and Chief Financial
	
	March 30, 2007Kathleen P. McSherry
	
	Officer (Principal Accounting Officer)54