UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2011~~2012

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-51267

~~RIDGEWOOD~~Ridgewood ~~ENERGY~~Energy L ~~FUND~~Fund, LLC

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

11-3719724

(I.R.S. Employer

Identification No.)

14 Philips Parkway, Montvale, NJ 07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

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

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

Shares of LLC Membership Interest

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨o

Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

Large accelerated filer ¨o Accelerated filer ¨o Non-accelerated filer (Do not check if a smaller reporting company) ¨o Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨o No x

There is no market for the shares of LLC Membership Interest in the Fund. As of March 3011, ~~2012~~2013 there are 350.1081 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY L FUND, LLC

~~2011~~2012 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	9
	ITEM 1B	UNRESOLVED STAFF COMMENTS	9
	ITEM 2	PROPERTIES	9
	ITEM 3	LEGAL PROCEEDINGS	10
	ITEM 4	MINE SAFETY DISCLOSURES	10
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	1110
	ITEM 6	SELECTED FINANCIAL DATA	1110
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	15
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	15
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	15
	ITEM 9A	CONTROLS AND PROCEDURES	1615
	ITEM 9B	OTHER INFORMATION	16
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	1716
	ITEM 11	EXECUTIVE COMPENSATION	18
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	18
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	1918
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	19
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	1920
		SIGNATURES	21

Table of Contents

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy L Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections, statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995 that are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing and production of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations. Examples of forward-looking statements made herein include statements regarding ~~future~~ projects, investments, insurance, capital expenditures and ~~insurance~~liquidity. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Table of Contents

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on May 27, 2004 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on July 6, 2004, selling whole and fractional shares of LLC membership interests (“Shares”), primarily at $150 thousand per whole Share. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund's limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on September 30, 2004. The Fund raised $51.4 million and after payment of $7.8 million in offering fees, commissions and investment fees, the Fund had $43.6 million for investments and operating expenses.

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investment, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions in which the investments are made. This includes review of existing title documents, reserve information, and other technical specifications regarding a project, and review and preparation of participation agreements and other agreements relating to an investment. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Form 10-K.

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

The Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing and printing periodic reports for shareholders and the Securities Exchange Commission (“SEC”), commission fees, taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses. The Fund is required to reimburse the Manager for all such expenses paid on its behalf.

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of the total shareholder capital. During 2007, the Manager waived its management fee for the remaining life of the Fund. Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. During 2010, the Manager waived its right to distributions of available cash from operations for the remaining life of the Fund.

The Manager is entitled to a 15% interest in cash distributions made by the Fund. Effective October 2010, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. Distributions paid to the Manager for the year ended December 31, 2010 were $0.1 million.

Business Strategy

The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects. Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion, subject to available cash from operations, reserve requirements and Fund operations. A ~~working~~The ~~interest~~Fund ishas ainvested ~~percentage of ownership~~ in ~~an oil and natural gas lease granting its owner~~ the ~~right~~drilling ~~to explore, drill~~ and ~~produce~~development of oil and natural gas ~~from~~ projects onin ~~that~~the ~~lease block~~U. ~~The~~S. ~~Fund~~offshore ~~has~~waters ~~focused~~of onTexas, ~~projects~~Louisiana, ~~that have significant reserve potential~~ and ~~are~~Alabama ~~projected~~in ~~to have~~ the ~~shortest~~Gulf ~~time~~of ~~period~~Mexico, ~~from~~in ~~investment~~partnership towith ~~first~~exploration and production companies. ~~The~~ ~~Fund~~At ~~does~~December ~~not operate these projects~~31, ~~and although it has a vote~~2012, itthe isFund’s ~~not~~participation in ~~control~~investments ofin ~~the~~oil ~~schedule~~and ~~pursuant~~natural togas ~~which~~properties ~~its~~have ~~projects~~been ~~are~~completely ~~developed~~identified and ~~completed. Working~~contracted ~~interest~~and ~~owners~~the ~~are~~balance ~~obligated to pay a corresponding percentage~~ of the ~~cost~~Fund’s ofcapital ~~leasing,~~has ~~drilling,~~been ~~producing~~fully ~~and~~allocated ~~operating~~to acomplete ~~well~~such projects. ~~After royalties are paid~~Accordingly, the ~~working~~Fund ~~interest~~does ~~also~~not ~~entitles~~expect ~~its~~to ~~owner~~investigate toor ~~share~~invest in ~~production~~any ~~revenues~~additional ~~with~~projects, other ~~working~~than ~~interest~~those ~~owners,~~in ~~based~~which on the ~~percentage~~Fund ofcurrently has a working interest ~~owned~~.

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Investment Strategy

The Fund ~~invests~~has invested its capital with operators through working interest joint ventures with such operators and, in some cases, other energy companies that also own or acquire working interests in the projects. A working interest is an undivided fractional interest in a lease block acquired from the U.S. government or from an operator that has acquired the working interest. A working interest includes the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production. Operators will generally retain 25% to 50% interests in multiple drilling projects, rather than 100% interests in a few projects, in order to share risk, obtain independent technical validation and stretch exploration budgets that are split across numerous regions of the world. Ridgewood Energy evaluates each project and their operators on an individual project basis, allowing the Fund to invest in what Ridgewood Energy believes are the projects with the most attractive risk/reward ratios. Critical to the success of this approach is the ability of Ridgewood Energy to diversify the Fund’s portfolio across project types and operators. Attributes sought in projects for investment include: depth of scientific analysis and preparation; strong potential project economics and favorable operating agreement terms; similarity to existing producing properties; and expertise of the operator in the proposed region/geology/technical environment. Attractive characteristics of potential and existing operators include industry contacts and relationships, ~~sophisticated~~ geological and geophysical teams and a ~~strong~~ track record of success. For certain of the Fund’s investments, the Fund may pay the operator a “promote” on the cost of the initial exploratory well, representing a larger share of the drilling costs. For a successful well, all of the Fund’s subsequent costs, including completion costs for the exploratory well, the costs of all development wells, infrastructure costs such as production platforms and pipelines, and day-to-day operating costs for the life of the project, would be paid on a proportionate basis to its working interest ownership.

Investment Process

Although Ridgewood Energy’s model of investing fund capital with operators affords it access to ~~industry~~third-~~leading~~party technical and engineering resources, Ridgewood Energy performs its own due diligence on, and independently evaluates, all of the projects in which the Fund may invest. Ridgewood Energy conducts an initial screening process to identify new project investment opportunities and is selective as to which projects it pursues. Key criteria that form part of the detailed evaluation include the identity of the operator and other partners, the technical quality of the project, access to existing infrastructure, drilling schedule and rig availability and project economics and terms.

Ridgewood Energy maintains an investment committee consisting of five members, which provides operational, financial, scientific and technical oil and gas expertise to the Fund (the “Investment Committee”). Four members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and one member is based out of the Manager’s Houston, Texas office. Once the technical and economic analyses of a potential project are complete and a project has been deemed to satisfy Ridgewood Energy’s technical criteria, ~~provide an attractive~~ economic risk/reward ratio, and fit within Ridgewood Energy’s diversification strategy, final investment approval is made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee seeks to balance the economics of the projects, the potential sizes of the projects, project location, the diversity of the operators, and the likely timing of new projects. The Investment Committee also considers the geological, financial and operating risks of the proposed project and compares these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further focuses on the initial well cost relative to the overall revenue potential of the project.

Participation and Joint Operating Agreements

Once Ridgewood Energy decides that a project is an appropriate investment for the Fund, the Fund ~~will~~enters ~~seek to enter~~ into participation and joint operating agreements with the other working interest owners in a lease. Ridgewood Energy negotiates these agreements with the goal of achieving the best possible economics and governance rights for the Fund in connection with acquiring the interest. Under the joint operating agreement, proposals and decisions are made based on percentage ownership approvals and although an operator’s percentage ownership may constitute a majority ownership, operators generally seek consensus relating to project decisions. As a result, Ridgewood Energy and other partners generally retain the right to make proposals and influence decisions involving certain operational matters associated with a project. This approval discretion and the operator’s desire to execute the project efficiently and expeditiously can function to limit the operator’s inclination to act on its own, or against the interests of the participants in the project.

Post-Investment Activities

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

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Project Information

Existing projects, ~~and future projects, if any,~~ are located in the waters of the Gulf of Mexico, offshore ~~from~~ Texas, ~~Louisiana~~ and ~~Alabama~~Louisiana, on the Outer Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“OCSLA”), which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS. See further discussion under the heading “Regulation” in this Item 1. “Business” of this Annual Report.

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. During a primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee, or third-party operator for a project, may conduct additional geological studies and may determine to drill additional exploratory 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.

Royalty Payments

Generally, working interests in an offshore oil and natural gas lease under the OCSLA pay a 12.5%, 16.67% or 18.75% royalty to the Bureau of Ocean Energy Management (“BOEM”). Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 87.5% of the total revenue, depending on the nature of the project. The net revenue interest is further reduced by any other royalty burdens that apply to a lease block, such as those imposed by override interest owners. Other than BOEM royalties, the Fund does not have material royalty burdens.

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned an interest as of December 31, ~~2011~~2012. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

	Total Productive Wells
	Gross		Net

Oil and natural gas		5		0.30

Acreage Data

Developed Acres
Gross		Net
	10,041		609

The following table sets forth the Fund’s interests in developed oil and gas acreage as of December 31, 2012. The Fund did not have any interests in undeveloped oil and gas acreage as of December 31, 2012. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and gas leases that have varying terms. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

Developed Acres
Gross		Net
	7,541		422

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Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table.

~~Total Spent~~

Total Spent

~~Total~~

Total

~~Working~~

Working

~~through~~

through

~~Fund~~

Fund

Lease Block

Interest

December 31,2011

Budget

Status

Project

Interest

December 31, 2012

Budget

Status

~~(in thousands)~~

(in thousands)

Producing Properties

~~Emerald Project well #1~~

Emerald Project well #1

~~2.5%~~

2.5%

~~1,622~~

1,654

~~1,637~~

~~Production commenced 2009. Work to install a compressor was completed in February 2012 at an estimated cost of $15 thousand.~~1,654

Production commenced in 2009. Work to install a compressor was completed in February 2012 at a cost of $41 thousand.

~~Emerald Project well #2~~

Emerald Project well #2

~~2.5%~~

2.5%

~~378~~

378

~~387~~

~~Production commenced July 2010. Recompletion efforts to access behind the pipe reserves are planned for 2013 at an estimated cost of $9 thousand.~~387

Production commenced in 2010. Well was recompleted in February 2013 at an estimated cost of $9 thousand.

~~Main Pass 275~~

Main Pass 275

~~10.0%~~

10.0%

~~1,923~~

1,923

~~1,933~~

~~Production commenced in 2007. Minor recompletion is planned for 2013 at an estimated cost of $10 thousand.~~1,933

Production commenced in 2007. Recompletion is planned for 2014 at an estimated cost of $10 thousand.

~~South Marsh Island 111~~

South Marsh Island 111

~~7.5%~~

7.5%

~~2,366~~

2,367

~~2,374~~

Production commenced in 2009. Recompletion efforts to access behind the pipe reserves commenced in April 2011 and completed in May 2011 at a cost of $0.3 million. Well was shut-in for pipeline maintenance from August 2011 through late-October 2011. Minor recompletion is also planned for 2013 at an estimated cost of $8 thousand.2,367

Production commenced in 2009. Well underwent a recompletion during second quarter 2012 at a cost of $4 thousand.

~~West Delta 68~~

West Delta 68

~~7.5%~~

7.5%

~~1,777~~

1,777

~~1,785~~

~~Production commenced in 2008. Recompletion planned for 2014 at an estimated cost of $8 thousand.~~1,800

Production commenced in 2008. Recompletion is planned for 2013 at an estimated cost of $23 thousand.

Fully Depleted

~~West Delta 67~~

West Delta 67

~~7.5%~~

7.5%

~~1,126~~

1,124

~~N/A~~

~~Production commenced in 2008. Determined to be fully depleted during second quarter 2011.~~1,124

Production commenced in 2008. Determined to be fully depleted during second quarter 2011. Well plugged and abandoned in fourth quarter 2012.

Marketing/Customers

The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to ~~sell~~market the Fund’s oil and natural gas. ~~Currently~~The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. During 2012, the Fund had six major customers in the public market and currently, the Fund has ~~five~~two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations.

The Fund’s current producing projects are near existing transportation infrastructure and pipelines. The Manager believes that it is likely that oil and natural gas from the Fund’s ~~future~~ projects will have access to pipeline transportation and ~~can~~will be marketed through Energy Upgrade, Inc.

Natural gas is sold in the spot market at prevailing prices, which fluctuate with demand as a result of related industry variables. Oil is generally sold one month at a time at prevailing market prices. Historically, the markets for, and prices of, oil and natural gas have been extremely volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence; therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse effect on the Fund’s future profitability. In the past, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production.

Seasonality

Generally, the Fund's business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund's oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is producing, the operator of the project extracts oil and natural gas reserves throughout the year. Once extracted, oil and natural gas can be sold at any time during the year.

The Fund’s properties are located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any damage, or shut-ins, or production stoppages, due to hurricane activity in ~~2011~~2012.

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Operator

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's ~~producing~~ properties are operated by LLOG Exploration ~~Offshore~~Company, ~~Inc.~~LLC and McMoRan Oil & Gas LLC.

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

Insurance

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

Salvage Fund

AsThe ~~to projects in which the~~ Fund ~~owns a working interest, the Fund~~ deposits in a separate interest-bearing account, or salvage fund, cash to provide for the Fund’s proportionate share of the anticipated cost of dismantling production platforms and facilities, plugging and abandoning the wells, and removing the platforms, facilities and wells in respect of the projects after the end of their useful lives, in accordance with applicable federal and state laws and regulations. The Fund has deposited $1.0 million from capital contributions into a salvage fund, which, along with interest earned on this account, the Fund currently estimates to be sufficient to meet the Fund’s potential requirements. If, at any time, the Manager determines the salvage fund will not be sufficient to cover the Fund’s proportionate share of expense, the Fund may transfer amounts from capital contributions or operating income to fund the deficit. Further contributions to the salvage fund may reduce the amount of cash distributions that may be made to investors by the Fund. Any portion of a salvage fund that remains after the Fund pays its share of the actual salvage cost will be distributed to the shareholders. There are no legal restrictions on the withdrawal or use of the salvage fund.

Competition

Strong competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. ~~Although~~The ~~the~~ Fund, ~~itself~~through ~~does~~its ~~not~~Manager ~~compete~~has ~~for~~competed ~~lease acquisitions from the BOEM, it does compete~~ with other companies for the acquisition of leases as well as percentage ownership interests in oil and natural gas working interests in the secondary market. The Fund does not anticipate the acquisition of any additional ownership interests in oil and natural gas working interests as its capital has been fully allocated to current and past projects.

In many instances, the Fund competes for working interests in projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and may have more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position to outbid the Fund. Nevertheless, the Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, and (ii) Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint.

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Employees

The Fund has no employees. The ~~as the~~ Manager operates and manages the Fund.

Offices

The principal executive office of both the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 1254 Enclave Parkway, Houston, TX 77077 and also owns additional office space at 79 Turtle Point, Tuxedo Park, NY, 10987. In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.

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Regulation

Oil and natural gas exploration, development and production activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to regulations. The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations.

The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations. The Fund may own interests in properties located in state waters of the Gulf of Mexico, for which such states regulate drilling and operating activities by requiring, among other things, drilling permits, bonds and reports concerning operations. The laws of such states also govern a number of environmental and conservation matters, including the handling and disposing of waste materials, unitization and pooling of natural gas and oil properties, and the levels of production from natural gas and oil wells.

Outer Continental Shelf Lands Act

Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOEM, an agency of the United States Department of Interior (the “Department of Interior”). Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”) pursuant to regulations promulgated under the OCSLA. Lessees must obtain 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. The Fund is not involved in the process of obtaining any such approvals or permits. Offshore operations are subject to numerous regulatory requirements, including stringent engineering and construction specifications related to offshore production facilities and pipelines and safety-related regulations concerning the design and operating procedures of these facilities and pipelines. Regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

Offshore operations are subject to regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Effective ~~Under~~October ~~certain~~22, ~~circumstances~~2012, ~~operations~~the onDepartment ~~federal~~of ~~leases~~Interior, ~~may~~acting bethrough ~~suspended~~the orBSEE, ~~terminated~~implemented the Final Drilling Safety Rule (the “Final Rule”), which refined certain interim rules imposed in the immediate wake of the 2010 Deepwater Horizon oil spill. The ~~Any~~Final ~~such~~Rule ~~suspension~~was orpromulgated ~~termination~~for ~~could~~the ~~adversely~~prevention ~~affect~~of waste and for the ~~Fund’s~~conservation of natural resources of the OCS under the rulemaking authority of the OCSLA. Among other things, the Final Rule (1) enhances the description and classification of well-control barriers, (2) defines testing requirements for cement, (3) clarifies requirements for the installation of dual mechanical barriers, (4) extends requirements for blowout preventers and well-control fluids to well-completions, workovers and decommissioning operations, and ~~interests~~(5) requires independent third-party verification of certain safety measures and enhanced documentation for blowout preventer inspections and maintenance.

The BOEM 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 duration of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a limited 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. Under certain circumstances, operations on federal leases may be suspended or terminated. Any such suspension or termination could adversely affect the Fund’s operations and interests.

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Sales and Transportation of Oil and Natural Gas

The Fund sells its proportionate share of oil and natural gas to the market through a marketer or a joint operating agreement and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). The rates, terms and conditions are regulated by FERC pursuant to a variety of statutes, including the OCSLA, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different than the impact upon other oil or natural gas producers and marketers.

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Environmental Matters and Regulation

The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water and the protection of aquatic species and habitats. However, although it shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that may be caused by the Fund’s projects.

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

The Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez spill, that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to, and increases penalties for, such spills. The OPA establishes a new liability regime for oil pollution incidents in the aquatic environment. Essentially, the OPA provides that a responsible party for a vessel or facility from which oil is discharged or that poses a substantial threat of a discharge could be liable for certain specified damages resulting from a discharge of oil, including clean-up and remediation, loss of subsistence use of natural resources, real or personal property damages, as well as certain public and private damages. A responsible party includes a lessee of an offshore facility.

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages. In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier, the Fund has not been required to make any such showing to the BOEM, as the operators are responsible for such compliance. However, notwithstanding the operators’ responsibility for compliance, in the event of an oil spill, the Fund, along with the operators and other working interest owners, could be liable under the OPA for the resulting environmental damage.

Clean Water Act. Generally, the Clean Water Act imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal, or state, if applicable, agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

Federal Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act.

Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act of 1976, as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation and Liability Act, as amended, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment.

The above represents a brief outline of the significant environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated thereunder. The Fund does not believe that its environmental, health and safety risks are materially different from those of comparable companies in the United States in the offshore oil and gas industry. However, there are no assurances that the environmental regulations described above will not result in curtailment of production or material increases in the costs of production, development or exploration, or otherwise have a material adverse effect on the Fund’s operating results and cash flows.

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~~Other Environmental Laws~~Dodd-Frank Act. The InDodd-Frank ~~addition to the above~~Act, ~~the~~signed ~~Fund’s~~into ~~operations~~law ~~may~~in beJuly ~~subject to the Resource Conservation and Recovery Act of 1976~~2010, asamong ~~amended,~~other ~~which regulates the generation~~provisions, ~~transportation,~~establishes ~~treatment,~~federal ~~storage,~~oversight ~~disposal~~ and ~~cleanup~~regulation of ~~certain~~the ~~hazardous~~over-the-counter ~~wastes,~~derivatives asmarket ~~well~~and asentities ~~the~~that ~~Comprehensive~~participate ~~Environmental~~in ~~Response,~~that ~~Compensation~~market and, ~~Liability~~in ~~Act~~addition, ~~which~~requires ~~imposes~~certain ~~joint~~additional ~~and~~SEC ~~several~~reporting ~~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~~requirements.

The ~~above~~Fund ~~represents~~has athe ~~brief~~authority ~~outline~~to ofutilize derivative instruments to manage the ~~significant~~price ~~environmental~~risk ~~laws~~attributable to its oil and gas production. Dodd-Frank mandates that ~~may~~many ~~apply~~derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. Derivatives will be subject to minimum daily margin requirements set by the ~~Fund’s~~relevant ~~operations~~clearinghouse and, potentially, by the SEC or the CFTC, and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums. In ~~The~~addition, ~~Fund~~as ~~believes~~required by Dodd-Frank, the CFTC has set “speculative position limits” (limits imposed on the maximum net long or net short speculative positions that ~~its~~a ~~operators~~person ~~are~~may inhold ~~compliance~~or control with ~~each~~respect ofto ~~these~~futures ~~environmental~~or ~~laws~~options ~~and~~contracts traded on the ~~regulations~~U.S. ~~promulgated~~commodities ~~thereunder~~exchange) with respect to most energy contracts. ~~The~~These ~~Fund~~requirements ~~does~~under ~~not~~Dodd-Frank ~~believe~~could ~~that~~significantly increase the ~~costs~~cost of ~~compliance~~any ~~with~~derivatives ~~applicable~~transactions ~~environmental~~of ~~laws,~~the Fund (including ~~federal~~through requirements to post collateral, ~~state~~which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and ~~local~~make ~~laws~~it more difficult for the Fund to enter into customized transactions, ~~will~~cause ~~have~~the aFund ~~material~~to ~~adverse~~liquidate ~~impact~~certain onpositions ~~its~~it ~~financial~~may ~~condition~~hold, reduce the ability of the Fund to protect against price volatility and/ other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties. If the Fund alters any hedging program as a result of the legislation and regulations, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance.

Dodd-Frank also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals. Resource extraction issuers are required to comply with the new rules, adopted by the SEC in August 2012, for fiscal years ending after September 30, 2013. Accordingly, in 2014, the Fund will be required to provide information about the type and total amount of payments made to the U.S. federal government for each project related to the commercial development of oil and natural gas. The Fund is evaluating the new resource extraction rules to determine any impact on the business. These rules are currently being challenged in federal court.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

The information regarding the Fund’s properties that is contained in Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties,” is incorporated herein by reference.

Drilling Activity

The Fund had no drilling activity during the ~~year~~years ended December 31, ~~2011. The~~2012 ~~following~~or ~~table sets forth the Fund’s drilling activity for development wells for the year ended December 31, 2010~~2011. The Fund had no drilling activity for exploratory wells during the year ended December 31, 2010. Gross wells are the total number of wells in which the Fund has an interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico.

	2010
	Gross		Net
Development wells:
Productive		1		0.03

Unaudited Oil and Gas Reserve Quantities

The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation. The Fund’s management controls over proved reserve estimation include: 1) verification of input data that is provided to an independent petroleum engineering firm; 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines; and 3) a review of the reserve estimates by the Manager.

The Manager’s primary technical person in charge of overseeing the Fund’s ~~reserves~~reserve estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over twenty years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation of exploration and development opportunities, and the oversight of drilling and production operations.

The Fund’s reserve estimates at December 31, 2011 and 2010 were prepared by Ryder Scott Company, L.P., (“Ryder Scott”) an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from Ryder Scott, which is filed as Exhibit 99 to this Annual Report, and is incorporated herein by reference.

Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The information regarding the Fund’s proved reserves, which is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Critical Accounting Estimates – Proved Reserves”, is incorporated herein by reference. The information regarding the Fund’s unaudited net quantities of proved developed and undeveloped reserves, which is contained in Table III in the “Supplementary Financial Information – Information about Oil and Gas Producing Activities – Unaudited” included in Item 15. “Exhibits, Financial Statement Schedules” of this Annual Report, is incorporated herein by reference.

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~~Proved~~The ~~Undeveloped~~Fund’s ~~Reserves~~reserve estimates at December 31, 2012 were prepared by Netherland, Sewell & Associates, Inc. At(“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference. The Fund’s reserve estimates at December 31, 2011 ~~and~~were ~~2010~~prepared by Ryder Scott Company, L.P., (“Ryder Scott”), an independent petroleum engineering firm. The information regarding the ~~Fund~~qualifications ~~had~~of nothe ~~proved~~petroleum ~~undeveloped~~engineer ~~oil~~is included within the report from Ryder Scott, which is filed as Exhibit 99.2 to this Annual Report, and ~~natural~~is ~~gas~~incorporated ~~reserves~~herein by reference.

Proved Undeveloped Reserves. At December 31, 2012 and 2011, the Fund had no proved undeveloped oil and natural gas reserves.

Production and Prices

The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, ~~2011~~2012 and ~~2010~~2011 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference.

Delivery Commitments

As of December 31, ~~2011~~2012, the Fund had no obligations or delivery commitments under any existing contracts.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is currently no established public trading market for the Shares. As of the date of this filing, there were ~~563~~571 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash as defined in the LLC Agreement, for distribution to shareholders. There is, ~~however,~~ no requirement to distribute available cash and as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. ~~Effective~~During ~~October~~ 2010, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. During the years ended December 31, ~~2011~~2012 and ~~2010~~2011, the Fund paid distributions totaling $10.58 million and $1.15 million, respectively.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

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

Overview of the Fund’s Business

The Fund was organized to primarily to acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects. However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.

The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing management, administrative and advisory services associated with these projects. The Fund does not currently, nor is there any plan to, operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as appropriate. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.

Revenues are subject to market pricing for oil and natural gas, which has been volatile, and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have ana material adverse effect on the Fund’s future profitability.

Critical Accounting Estimates

The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented. The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” ~~contained~~within in this Annual Report for a discussion of the Fund’s significant accounting policies.

Accounting for Exploration, Development and Acquisition Costs

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. ~~Costs~~ Development costs, including costs of drilling and equipping productive wells and related production facilities are capitalized. ~~Annual~~ ~~lease~~Exploratory ~~rentals~~costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, ~~exploration~~exploratory ~~expenses~~drilling ~~and~~costs are expensed as dry-hole costs. Annual lease rentals and exploration expenses are expensed as incurred.

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

Unproved Property

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

Proved Reserves

Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization. Annually, the Fund engages an independent petroleum engineer, ~~Ryder Scott,~~ to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change. ~~Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization.~~

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Asset Retirement Obligations

~~For~~Asset ~~oil~~retirement ~~and~~obligations ~~gas~~include ~~properties,~~costs ~~there~~to ~~are~~plug ~~obligations~~and toabandon ~~perform~~the ~~removal~~Fund’s wells and ~~remediation~~to ~~activities~~dismantle ~~when~~and ~~the~~relocate ~~properties~~or ~~are~~dispose ~~retired. When~~of athe ~~project~~Fund’s ~~reaches~~production ~~drilling~~platforms ~~depth~~and related structures and isrestoration ~~determined~~costs toof beland ~~either~~and ~~proved~~seabed. The orFund ~~dry,~~develops aestimates ~~liability~~of isthese ~~recognized~~costs ~~for~~based upon the ~~present~~type ~~value~~ of ~~asset~~production ~~retirement~~structure, ~~obligations~~water ~~once~~depth, ~~reasonably~~reservoir ~~estimable. The~~depth ~~Fund~~and ~~capitalizes~~characteristics, and ongoing discussions with the ~~associated~~wells’ ~~asset~~operators. Because ~~retirement~~these costs astypically ~~part~~extend ofmany years into the ~~carrying~~future, ~~amount~~estimating ofthese ~~its~~future ~~proved~~costs ~~properties.~~is ~~Plug~~difficult and ~~abandonment~~requires ~~costs~~significant ~~associated~~judgment ~~with~~that ~~unsuccessful~~is ~~projects~~subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. Estimates are ~~expensed~~reviewed ason ~~dry~~a bi-~~hole~~annual ~~costs~~basis, or more frequently if an event occurs that would dictate a change in assumptions or estimates.

Impairment of Long-Lived Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of ~~producing~~proved properties are determined by comparing future net undiscounted cash flows to the net book value at the ~~end~~time of ~~each~~the ~~period~~review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to “fair value,” which is determined using net discounted future cash flows from the ~~producing~~ property. ~~Different~~ ~~pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.~~ The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, ~~2011~~2012 and ~~2010~~2011, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.

	Year ended December 31,
	2012			2011
	(in thousands)
Revenue
Oil and gas revenue	$	984		$	1,987

Expenses
Depletion and amortization		585			837
Impairment of oil and gas properties		1,141			(26	)
Dry-hole costs		3			(52	)
Operating expenses		271			183
General and administrative expenses		189			200
Total expenses		2,189			1,142
(Loss) income from operations		(1,205	)		845
Interest income		23			28
Net (loss) income	$	(1,182	)	$	873

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	Year ended December 31,
	2011			2010
	(in thousands)
Revenue
Oil and gas revenue	$	1,987		$	1,637
Expenses
Depletion and amortization		837			928
Impairment of oil and gas properties		(26	)		781
Dry-hole costs		(52	)		(81	)
Operating expenses		183			293
General and administrative expenses		200			315
Total expenses		1,142			2,236
Income (loss) from operations		845			(599	)
Interest income		28			30
Net income (loss)	$	873		$	(569	)

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 2012 and 2011.

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 2011 and 2010.

	Year ended December 31,
	2012		2011
Number of wells producing		5		6
Total number of production days		1,674		1,569
Oil sales (in thousands of barrels)		3		6
Average oil price per barrel	$	108	$	106
Natural gas sales (in thousands of mcfs)		183		273
Average natural gas price per mcf	$	2.69	$	3.71
Natural gas liquid ("NGL") sales (in thousands of gallons)		177		331
Average NGL price per gallon	$	0.82	$	1.09

	Year ended December 31,
	2011		2010
Number of wells producing		6		6
Total number of production days		1,569		1,494
Average mcfe per production day		226		213
Oil sales (in thousands of barrels)		6		5
Average oil price per barrel	$	106	$	78
Gas sales (in thousands of mcfs)		273		253
Average gas price per mcf	$	3.71	$	4.07

The increase in production days were principally attributable to a decrease in the number of non-productive days related to maintenance activities. The decreases in sales volumes were principally attributable to natural declines in the Fund’s wells’ production. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

~~The~~Oil ~~increases~~and inGas ~~production~~Revenue. Oil ~~days,~~and ~~average~~gas ~~production~~revenue ~~rate~~for ~~and~~the ~~oil~~year ~~and~~ended ~~gas~~December ~~volumes~~31, ~~were~~2012 ~~principally~~was ~~attributable~~$1.0 tomillion, ~~the~~a ~~composite~~decrease of ~~productive~~$1.0 ~~wells~~million ~~coupled~~from ~~with~~the ayear ~~decrease~~ended inDecember ~~the~~31, ~~number~~2011. The ofdecrease ~~non-productive~~is ~~days~~attributable ~~related~~ to ~~maintenance~~decreased ~~activities. See~~sales ~~Item~~volume 1totaling $0.8 ~~“Business”~~million ofcoupled ~~this~~with ~~Annual~~the ~~Report~~impact ~~under~~of the ~~heading~~change in average prices totaling $0.2 million. See “~~Properties~~Overview” above for ~~more~~additional information.

~~Oil~~Depletion and ~~Gas Revenue~~Amortization. ~~Oil~~ Depletion and ~~gas~~amortization ~~revenue~~ for the year ended December 31, ~~2011~~2012 was $2.0.6 million, a decrease of $0.43 million ~~increase~~ from the year ended December 31, ~~2010~~2011. The ~~increase~~decrease isresulted ~~attributable~~from toa ~~increased~~decrease ~~sales~~in in production volumes totaling $0.23 million, ~~coupled~~partially ~~with~~offset ~~the~~by ~~impact~~an ofincrease ~~increased~~in average ~~prices~~depletion rates totaling $0.21 million. The increase in average depletion rates was principally attributable to revisions to reserve estimates. See “Overview” above for additional information.

~~Depletion~~Impairment ~~and~~of ~~Amortization. Depletion~~Oil and ~~amortization~~Gas ~~for~~Properties. During the year ended December 31, ~~2011~~2012 ~~was~~the ~~$0.8~~Fund ~~million,~~recorded aimpairments ~~decrease~~totaling of $01.1 million, ~~from~~relating ~~the~~to ~~year~~South ~~ended~~Marsh ~~December~~Island 31111 and West Delta 68, ~~2010. The~~which ~~decrease~~were ~~resulted~~attributable ~~from~~to arevisions ~~decrease~~to inreserve ~~average~~estimates ~~depletion~~as ~~rates~~provided ~~totaling~~by ~~$0.2~~the ~~million,~~Fund’s ~~partially~~independent ~~offset~~petroleum byengineers, ancoupled ~~increase~~with declines in ~~production~~future ~~volumes~~oil ~~totaling~~and ~~$0.1~~gas ~~million~~prices. During ~~The~~the ~~decrease~~year inended ~~depletion~~December ~~rates~~31, ~~was~~2011, ~~primarily~~ the ~~result~~Fund ofrecorded ~~the~~credits ~~composite~~to ofimpairments ~~productive~~totaling ~~wells~~$26 ~~coupled~~thousand, ~~with~~which were primarily attributable to revisions to ~~reserve~~asset ~~estimates~~retirement obligations for fully depleted wells.

~~Impairment~~Dry-hole ofCosts. Dry-hole ~~Oil~~costs ~~and~~are ~~Gas~~those ~~Properties. During~~costs ~~the~~incurred ~~year~~to ~~ended~~drill ~~December~~and ~~31,~~develop ~~2011,~~a ~~the~~well ~~Fund~~that ~~recorded~~is ~~credits~~ultimately found to ~~impairments~~be ~~totaling~~incapable ~~$26~~of ~~thousand,~~producing ~~which~~either ~~were~~oil ~~primarily~~or ~~attributable~~natural togas ~~revisions~~in tosufficient ~~asset~~quantities ~~retirement~~to ~~obligations~~justify ~~for~~completion ~~fully~~of ~~depleted~~the ~~wells~~well. ~~During~~At times, the ~~year~~Fund ~~ended~~receives ~~December~~adjustments ~~31,~~to ~~2010,~~certain wells from their respective operators upon review and audit of the ~~Fund~~wells’ ~~recorded~~costs. Dry-hole ~~impairments~~costs ~~totaling~~were $~~0.8~~3 ~~million,~~thousand ~~principally~~and ~~related~~credits to ~~South~~dry-hole ~~Marsh~~costs ~~Island~~were ~~111,~~$52 ~~which~~thousand ~~were~~during ~~attributable~~the toyears ~~revisions~~ended toDecember ~~reserve~~31, ~~estimates~~2012 and 2011, respectively.

Dry-hole Costs. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. The Fund recorded credits to dry-hole costs of $52 thousand and $81 thousand during the years ended December 31, 2011 and 2010, respectively.

Operating Expenses. Operating expenses represent costs specifically identifiable or allocable to the Fund's wells, as detailed in the following table.

	Year ended December 31,
	2012		2011
	(in thousands)
Lease operating expense	$	252	$	182
Workover expense		11		(7	)
Accretion expense		8		8
	$	271	$	183

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $1.12 per mcfe during the year ended December 31, 2012 compared to $0.51 per mcfe during the year ended December 31, 2011. Workover expenses represent costs to restore or stimulate production of existing reserves. During the years ended December 31, 2012 and 2011, workover expenses related to West Delta 68 and the Emerald Project, respectively. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.

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	Year ended December 31,
	2011			2010
	(in thousands)
Lease operating expense	$	182		$	254
Accretion expense		8			13
Workover expense		(7	)		26
	$	183		$	293

Lease operating expense was related to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $0.51 per mcfe during the year ended December 31, 2011 compared to $0.80 per mcfe during the year ended December 31, 2010. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties. Workover costs include costs and credits attributable to the Emerald Project, which required maintenance to increase its rate of production.

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

	Year ended December 31,
	2011		2010
	2012		2011
	(in thousands)
Accounting fees	$	~~105~~114	$	~~124~~105
Insurance expense		52		111
Management reimbursement and other		40		43
Management reimbursement and other		43		80
Insurance expense		35		52
	$	~~200~~189	$	~~315~~200

Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund. Management reimbursement relates to reimbursements for various administrative costs incurred on the Fund’s behalf. Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance. ~~Management reimbursement relates to reimbursements for various administrative costs incurred on the Fund’s behalf.~~

Interest Income. Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities. Interest income for the year ended December 31, ~~2011~~2012 was $2823 thousand, a $25 thousand decrease from the year ended December 31, ~~2010~~2011.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, 2012 were $0.6 million, primarily related to revenue received of $1.1 million, partially offset by operating expenses paid of $0.2 million, general and administrative expenses paid of $0.2 million and the settlements of asset retirement obligations totaling $0.1 million.

Cash flows provided by operating activities for the year ended December 31, 2011 were $1.3 million, primarily related to revenue received of $2.0 million, partially offset by operating expenses paid of $0.2 million, general and administrative expenses paid of $0.2 million and the settlements of asset retirement obligations totaling $0.2 million.

Cash flows provided by operating activities for the year ended December 31, 2010 were $0.5 million, primarily related to revenue received of $1.6 million, partially offset by the settlement of asset retirement obligations of $0.4 million, general and administrative expenses paid of $0.3 million and operating expenses paid of $0.3 million.

Investing Cash Flows

Cash flows provided by investing activities for the year ended December 31, 2012 were $10 thousand, primarily related to proceeds from the salvage fund of $51 thousand, partially offset by capital expenditures for oil and gas properties totaling $41 thousand.

Cash flows used in investing activities for the year ended December 31, 2011 were $0.2 million, primarily related to capital expenditures for oil and gas properties totaling $0.3 million, partially offset by proceeds from the salvage fund of $0.1 million.

Cash flows used in investing activities for the year ended December 31, 2010 were $0.8 million, primarily related to capital expenditures for oil and gas properties of $0.9 million, inclusive of advances, partially offset by proceeds from the salvage fund of $0.1 million.

Financing Cash Flows

Cash flows used in financing activities for the year ended December 31, 2012 were $0.8 million, related to shareholder distributions.

Cash flows used in financing activities for the year ended December 31, 2011 were $1.5 million, related to shareholder distributions.

~~Cash~~Estimated ~~flows~~Capital ~~used in financing activities for the year ended December 31, 2010 were $1.1 million, related to manager and shareholder distributions.~~Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2012, the Fund had committed to spend an additional $42 thousand related to its investments in oil and gas properties, of which $32 thousand is expected to be spent during 2013.

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~~Estimated~~ Capital ~~Expenditures~~expenditures for investment properties have been funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain. The number of projects in which the Fund can invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.

The Fund has entered into multiple agreements for the acquisition, 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, 2011, the Fund had committed to spend an additional $50 thousand related to its investment properties, of which $15 thousand is expected to be spent during the next twelve months.

Capital expenditures for investment properties were funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain. The number of projects in which the Fund can invest was limited and each unsuccessful project the Fund experienced reduced its ability to generate revenue and exhausted its capital.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its operations, ~~inclusive~~and ofcapital expenditures for its investment properties. Operations are funded utilizing operating income, existing cash on-hand and income earned therefrom. The Fund has reached the end of its investment cycle. Based upon its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. InAt such time the ~~event~~Manager ofdetermines athat ~~temporary~~there ~~production~~is ~~stoppage,~~uncertainty ~~causing~~surrounding the Fund’s ~~wells~~ability to ~~not~~continue ~~produce~~to ~~cash~~fund ~~flow~~its ~~from~~ operations, ~~the~~or ~~Fund~~that ~~may~~terminating ~~borrow from~~ the ~~Manager~~Fund ~~until~~would ~~such~~be ~~time~~in ~~that~~the ~~production~~best iseconomic ~~resumed.~~interests Atof ~~such~~its ~~time~~shareholders, the Manager ~~determines~~would ~~that~~take ~~the~~any ~~Fund~~such isactions nothat ~~longer~~are ~~capable~~necessary ~~of continuing~~ to ~~fund~~bring ~~its~~about ~~operations,~~ the ~~Manager~~dissolution ~~would~~of ~~elect to dissolve~~ the Fund.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at December 31, ~~2011~~2012 and ~~2010~~2011 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund ~~has~~enters ~~entered~~ into participation and joint operating agreements with operators. On behalf of the Fund, an operator ~~has~~enters ~~entered~~ into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate such contracts. No contractual obligations exist at December 31, ~~2011~~2012 and ~~2010~~2011 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, ~~2011~~2012. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

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Management's Report on Internal Control over Financial Reporting

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

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

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, ~~2011~~2012. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework. Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, ~~2011~~2012, the Fund’s internal control over financial reporting is effective.

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

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, ~~2011~~2012 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of Ridgewood Energy and the Fund and their ages at December 31, ~~2011~~2012 are as follows:

Name, Age and Position with Registrant	Officer of Ridgewood Energy Corporation Since
Robert E. Swanson, 64 Chief Executive Officer	1982
Robert E. Swanson, 65 Chief Executive Officer	1982
Kenneth W. Lang, 57 President and Chief Operating Officer	2009
Kenneth W. Lang, 58 President and Chief Operating Officer	2009
Kathleen P. McSherry, 46 Executive Vice President and Chief Financial Officer	2001
Kathleen P. McSherry, 47 Executive Vice President and Chief Financial Officer	2001
Robert L. Gold, 53 Executive Vice President	1987
Robert L. Gold, 54 Executive Vice President	1987
Daniel V. Gulino, 51 Senior Vice President and General Counsel	2003
Daniel V. Gulino, 52 Senior Vice President and General Counsel	2003

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The officers in the above table have also been officers of the Fund since May 27, 2004, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of Ridgewood Energy and the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC, and President of Ridgewood Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is an inactive member of the New York and New Jersey State Bars. He is a graduate of Amherst College and Fordham University Law School.

Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President – Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.

Kathleen P. McSherry has served as the Executive Vice President and Chief Financial Officer of Ridgewood Energy since 2001 and is a member of the Investment Committee. Ms. McSherry holds a Bachelor of Science degree in Accounting.

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

Daniel V. Gulino is Senior Vice President of Legal Affairs for Ridgewood Energy and has served as counsel for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management and Senior Vice President & General Counsel of Ridgewood Securities Corporation. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.

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Board of Directors and Board Committees

The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure. Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11. “Executive Compensation” of this Annual Report. Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager, the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.

Code of Ethics

The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on ~~our~~the Manager’s website or in a current report on Form 8-K. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN: General Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, ~~2011~~2012, all filing requirements applicable to its officers, directors and 10% beneficial owners were met on a timely basis.

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ITEM 11. EXECUTIVE COMPENSATION

The executive officers of the Fund do not receive compensation from the Fund. The Manager and its affiliates compensate the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report for more information regarding Manager compensation and payments to affiliated entities.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 350.1081 shares outstanding at March 11, 2013. The following table sets forth information with respect to beneficial ownership of the Shares as of March 3011, ~~2012~~2013 (no person owns more than 5% of the Shares). 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. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

• each executive officer (there are no directors); and

Name of beneficial owner	Number of shares		Percent
Robert E. Swanson, Chief Executive Officer (1)		8.98		2.56%
Executive officers as a group (1)		8.98		2.56%

•(1) ~~all~~Includes ofShares ~~the~~owned ~~executive~~by ~~officers~~Mr. asSwanson’s afamily ~~group~~members.

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 March 30, 2012. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

Name of beneficial owner	Number of shares	Percent
Robert E. Swanson, Chief Executive Officer (1)	8.3133	2.37%
Executive officers as a group (1)	8.3133	2.37%
(1) Includes Shares owned by Mr. Swanson’s family members.

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

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of the total shareholder capital. During 2007, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs, which are included in general and administrative expenses, totaled $40 thousand ~~and~~for ~~$80~~each ~~thousand~~of ~~for~~ the years ended December 31, ~~2011~~2012 and ~~2010, respectively~~2011.

The Manager is entitled to receive a 15% interest in ~~the~~ cash distributions from operations made by the Fund. ~~Effective~~During ~~October~~ 2010, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. ~~Distributions paid to the Manager for the year ended December 31, 2010 were $0.1 million.~~

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.

None of the amounts paid to the Manager have 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.

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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, ~~2011~~2012 and ~~2010~~2011.

	Year ended December 31,
	2011		2010
	2012		2011
	(in thousands)
Audit fees (1)	$	80	$	9080

(1)	Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1)

Financial Statements

See “Index to Financial Statements” set forth on page F-1.

(a) (2)

Financial Statement Schedules

None.

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(a) (3)

EXHIBIT NUMBER	TITLE OF EXHIBIT	~~TITLE OF EXHIBIT~~	METHOD OF FILING	~~METHOD OF FILING~~
3.1	Certificate of Formation of Ridgewood Energy L Fund, LLC dated May 27, 2004	~~Certificate of Formation of Ridgewood Energy L Fund, LLC dated May 27, 2004~~	Incorporated by reference to the Fund's Form 10 filed on April 29, 2005	~~Incorporated by reference to the Fund's Form 10 filed on April 29, 2005~~
3.2	Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy L Fund, LLC dated July 6, 2004	~~Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy L Fund, LLC dated July 6, 2004~~	Incorporated by reference to the Fund's Form 10 filed on April 29, 2005	~~Incorporated by reference to the Fund's Form 10 filed on April 29, 2005~~
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	~~Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)~~	Filed herewith	~~Filed herewith~~
31.2	Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	~~Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)~~	Filed herewith	~~Filed herewith~~
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 Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund.	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund.	Filed herewith	~~Filed herewith~~
99		Report of Ryder Scott Company, L.P.		Filed herewith
99.1	Report of Netherland, Sewell & Associates, Inc.		Filed herewith
101.INS		XBRL Instance Document		*
99.2	Report of Ryder Scott Company, L.P.		Incorporated by reference to the Fund’s Form 10-K filed on March 30, 2012
101.SCH		XBRL Taxonomy Extension Schema		*
101.INS	XBRL Instance Document		*
101.CAL		XBRL Taxonomy Extension Calculation Linkbase		*
101.SCH	XBRL Taxonomy Extension Schema		*
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document		*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase		*
101.LAB		XBRL Taxonomy Extension Label Linkbase		*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document		*
101.PRE		XBRL Taxonomy Extension Presentation Linkbase		*
101.LAB	XBRL Taxonomy Extension Label Linkbase		*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase		*

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Act of 1934 and otherwise are not subject to liability.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	RIDGEWOOD ENERGY L FUND, LLC
Date: March 30, 2012	By:	/s/ ROBERT E. SWANSON
Date: March 11, 2013	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson
		Chief Executive Officer
		(Principal Executive Officer)

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

Signature	~~Capacity~~	~~Date~~Capacity	Date
/s/ ROBERT E. SWANSON	~~Chief Executive Officer (Principal~~	~~March~~Chief ~~30,~~Executive ~~2012~~Officer (Principal Executive Officer)	March 11, 2013
Robert E. Swanson	~~Executive Officer)~~
/s/ KATHLEEN P. MCSHERRY	~~Executive Vice President and~~	~~March~~Executive ~~30,~~Vice ~~2012~~President and Chief	March 11, 2013
Kathleen P. McSherry	~~Chief Financial Officer (Principal Financial and Accounting Officer)~~	Financial Officer (Principal Financial and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
BY: /s/ ROBERT E. SWANSON	~~Chief Executive Officer of the~~	~~March~~Chief ~~30,~~Executive ~~2012~~Officer of the Manager	March 11, 2013
Robert E. Swanson	~~Manager~~

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INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2011 and 2010	F-3
Balance Sheets as of December 31, 2012 and 2011	F-3
Statements of Operations for the years ended December 31, 2011 and 2010	F-4
Statements of Operations for the years ended December 31, 2012 and 2011	F-4
Statements of Changes in Members' Capital for the years ended December 31, 2011 and 2010	F-5
Statements of Changes in Members' Capital for the years ended December 31, 2012 and 2011	F-5
Statements of Cash Flows for the years ended December 31, 2011 and 2010	F-6
Statements of Cash Flows for the years ended December 31, 2012 and 2011	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-12

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~shareholders~~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, ~~2011~~2012 and ~~2010~~2011, and the related statements of operations, changes in members'’ capital, and cash flows for the years ~~ended~~then ~~December 31, 2011 and 2010~~ended. 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, ~~2011~~2012 and ~~2010~~2011, and the results of its operations and its cash flows for the years ~~ended~~then ~~December 31~~ended, ~~2011 and 2010,~~ in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

March 3011, ~~2012~~2013

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RIDGEWOOD ENERGY L FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2011			2010
	2012			2011
ASSETS
Assets
Current assets:
Cash and cash equivalents	$	~~229~~85		$	~~590~~229
Salvage fund		6760			-67
Production receivable		~~179~~98			~~178~~179
Other current assets		5625			2456
Total current assets		~~531~~268			~~792~~531
Salvage fund		~~999~~955			~~1,149~~999
Oil and gas properties:
Advances to operators for working interests and expenditures		-			134
Proved properties		9,785			9,755
Proved properties		9,755			9,249
Less: accumulated depletion and amortization		(7,419	)		(5,693	)
Less: accumulated depletion and amortization		(5,693	)		(4,856	)
Total oil and gas properties, net		2,366			4,062
Total oil and gas properties, net		4,062			4,527
Total assets	$	3,589		$	5,592
Total assets	$	5,592		$	6,468
Liabilities and Members' Capital
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Accrued expenses	$	~~111~~127		$	~~198~~111
Asset retirement obligations		6760			~~304~~67
Total current liabilities		~~178~~187			~~502~~178
Asset retirement obligations		~~594~~516			~~515~~594
Total liabilities		~~772~~703			~~1,017~~772
Commitments and contingencies (Note 5)
Members' capital:
Manager:
Distributions		(2,453	)		(2,453	)
Retained earnings		1,~~931~~994			1,~~697~~931
Manager's total		(~~522~~459	)		(~~756~~522	)
Shareholders:
Capital contributions (670 shares authorized; 350.1081 issued and outstanding)		51,401			51,401
Capital contributions (670 shares authorized;
350.1081 issued and outstanding)		51,401			51,401
Syndication costs		(5,502	)		(5,502	)
Distributions		(1516,~~739~~491	)		(1415,~~235~~739	)
Accumulated deficit		(2426,~~818~~063	)		(2524,~~457~~818	)
Shareholders' total		53,~~342~~345			65,~~207~~342
Total members' capital		42,~~820~~886			54,~~451~~820
Total liabilities and members' capital	$	53,~~592~~589		$	65,~~468~~592

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

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RIDGEWOOD ENERGY L FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2011			2010
	2012			2011
Revenue
Oil and gas revenue	$	~~1,987~~984		$	1,~~637~~987
Expenses
Depletion and amortization		~~837~~585			~~928~~837
Impairment of oil and gas properties		~~(26~~1,141	)		~~781~~(26	)
Dry-hole costs		~~(52~~3	)		(8152	)
Operating expenses		~~183~~271			~~293~~183
General and administrative expenses		~~200~~189			~~315~~200
Total expenses		12,~~142~~189			21,~~236~~142
Income (loss) from operations		845			(599	)
(Loss) income from operations		(1,205	)		845
Interest income		2823			3028
Net income (loss)	$	873		$	(569	)
Net (loss) income	$	(1,182	)	$	873
Manager Interest
Net income	$	~~234~~63		$	~~140~~234
Shareholder Interest
Net income (loss)	$	639		$	(709	)
Net (loss) income	$	(1,245	)	$	639
Net income (loss) per share	$	1,825		$	(2,025	)
Net (loss) income per share	$	(3,557	)	$	1,825

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

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RIDGEWOOD ENERGY L FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2009		350.1081	$	(788	)	$	7,864		$	7,076
Balances, December 31, 2010		350.1081	$	(756	)	$	6,207		$	5,451
Net income (loss)		-		140			(709	)		(569	)
Distributions		-		(108	)		(948	)		(1,056	)
Balances, December 31, 2010		350.1081		(756	)		6,207			5,451
Net income		-		234			639			873
Distributions		-		-			(1,504	)		(1,504	)
Balances, December 31, 2011		350.1081	$	(522	)	$	5,342		$	4,820
Net income		-		234			639			873
Balances, December 31, 2011		350.1081		(522	)		5,342			4,820
Distributions		-		-			(752	)		(752	)
Net income (loss)		-		63			(1,245	)		(1,182	)
Balances, December 31, 2012		350.1081	$	(459	)	$	3,345		$	2,886

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

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RIDGEWOOD ENERGY L FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2011			2010
	2012			2011
Cash flows from operating activities
Net income (loss)	$	873		$	(569	)
Net (loss) income	$	(1,182	)	$	873
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments to reconcile net (loss) income to net cash
Depletion and amortization		837			928
provided by operating activities:
Impairment of oil and gas properties		(26	)		781
Depletion and amortization		585			837
Dry-hole costs		(52	)		(81	)
Impairment of oil and gas properties		1,141			(26	)
Accretion expense		8			13
Dry-hole costs		3			(52	)
Accretion expense		8			8
Changes in assets and liabilities:
Increase in production receivable		(1	)		(23	)
Decrease (increase) in production receivable		81			(1	)
Decrease in other current assets		231			32
Decrease in accrued expenses		(67	)		(70	)
Increase (decrease) in accrued expenses		16			(67	)
Settlements of asset retirement obligations		(~~249~~85	)		(~~449~~249	)
Net cash provided by operating activities		~~1,325~~598			~~533~~1,325
Cash flows from investing activities
Payments to operators for working interests and expenditures		-			(134	)
Capital expenditures for oil and gas properties		(41	)		(265	)
Capital expenditures for oil and gas properties		(265	)		(772	)
Proceeds from salvage fund, net		51			83
Proceeds from salvage fund, net		83			72
Net cash provided by (used in) investing activities		10			(182	)
Net cash used in investing activities		(182	)		(834	)
Cash flows from financing activities
Distributions		(~~1,504~~752	)		(1,~~056~~504	)
Net cash used in financing activities		(~~1,504~~752	)		(1,~~056~~504	)
Net decrease in cash and cash equivalents		(~~361~~144	)		(~~1,357~~361	)
Cash and cash equivalents, beginning of year		~~590~~229			~~1,947~~590
Cash and cash equivalents, end of year	$	~~229~~85		$	~~590~~229
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$	~~134~~-		$	-134

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

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RIDGEWOOD ENERGY L FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy L Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on May 27, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated July 6, 2004 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico.

The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 3 and 5.

Use of Estimates

The preparation of financial statements in ~~conformity~~accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents. At times, deposits may be in excess of federally insured limits. Effective January 1, ~~which~~2013, ~~for~~the ~~interest~~federally ~~bearing~~insured limits of the Fund’s deposits, are $250 thousand per insured financial institution. Based ~~Additionally,~~upon ~~non-interest~~these ~~bearing~~limits, ~~deposits~~at ~~are fully insured through~~ December 31, 2012, ~~after which they will be included within~~ the ~~$250 thousand limit. At December 31, 2011, the~~ Fund’s bank balances exceeded federally insured limits by $40.2 ~~thousand~~million, all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations. At December 31, ~~2011~~2012, the Fund had investments in ~~U.S.~~federal ~~Treasury~~agency mortgage-backed securities within its salvage fund that are classified as ~~held~~available-tofor-~~maturity~~sale of $10.17 million, which ~~matured~~mature in ~~February~~January ~~2012~~2042. ~~Held~~Available-tofor-~~maturity~~sale ~~investments~~securities are ~~those~~carried ~~securities~~in ~~that~~ the ~~Fund~~financial ~~has~~statements ~~the ability and intent to hold until maturity, and are recorded~~ at ~~cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates~~ fair value. At ~~For~~December ~~all~~31, ~~investments~~2012, ~~interest~~there ~~income~~was isno ~~accrued~~unrealized asgain ~~earned and amortization of premium~~ or ~~discount,~~loss ifrelated ~~any,~~to ~~is included in interest income. Interest earned on~~ the ~~account~~Fund’s ~~will~~available-for-sale ~~become part of the salvage fund~~investments. The ~~There~~Fund ~~are~~had no ~~restrictions~~investments onin ~~withdrawals~~available-for-sale ~~from~~securities ~~the~~at ~~salvage~~December ~~fund~~31, 2011.

~~Oil~~At December 31, 2012 and ~~Gas~~2011, ~~Properties~~the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $0.1 million and $1.1 million, respectively. The held-to-maturity investments at December 31, 2012 mature in June 2013. Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund's portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory drilling costs are expensed as dry-hole costs. Annual lease rentals and exploration expenses are expensed as incurred.

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Table of Contents

Oil and Gas Properties

The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory drilling costs are expensed as dry-hole costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity and workover efforts are expensed as incurred.

Upon the sale or retirement of a proved property, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized.

At December 31, ~~2011~~2012 and ~~2010~~2011, amounts recorded in accrued expenses totaling $40 thousand ~~and $60 thousand, respectively,~~ related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund may be required to advance its share of estimated cash expenditures for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, ~~2011~~2012 and ~~2010~~2011.

	2011			2010
	2012			2011
	(in thousands)
Balance, beginning of year	$	~~819~~661		$	~~1,248~~819
Liabilities incurred		-			7
Liabilities settled		(85	)		(249	)
Liabilities settled		(249	)		(449	)
Accretion expense		8			8
Accretion expense		8			13
Revisions in estimated cash flows		(8	)		83
Revisions in estimated cash flows		83			-
Balance, end of year	$	576		$	661
Balance, end of year	$	661		$	819

As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

Syndication Costs

Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if ~~collectibility~~collectability of the revenue is probable. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.

Impairment of Long-Lived Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

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Table of Contents

~~During~~Impairment ~~the~~of year ended December 31, 2011, the Fund recorded credits to impairments totaling $26 thousand, which were primarily attributable to revisions to asset retirement obligations for fully depleted wells. During the year ended December 31, 2010, the Fund recorded impairments totaling $0.8 million, principally related to South Marsh Island 111, which were attributable to revisions to reserve estimates. Prior to such writeLong-~~down,~~Lived South Marsh Island 111 had a carrying value of $1.7 million. The fair value of the impaired well at December 31, 2010 was $0.9 million, which was determined based on level 3 inputs, which include projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of proved properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

During the year ended December 31, 2012, the Fund recorded impairments of $0.4 million and $0.7 million, relating to South Marsh Island 111 and West Delta 68, respectively, which were attributable to revisions to reserve estimates and declines in future prices. The aggregate fair value of the impaired properties at the date of impairment was $1.7 million. Such amounts were determined based on level 3 inputs, which included projected income from reserves utilizing forward price curves, net of anticipated costs, discounted. During the year ended December 31, 2011, the Fund recorded credits to impairments totaling $26 thousand, which were primarily attributable to revisions to asset retirement obligations for fully depleted wells. See Note 5. “Fair Value Measurements”.

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.

Income and Expense Allocation

Profits and losses are allocated ~~85%~~ to shareholders ~~in proportion to their relative capital contributions~~ and ~~15% to~~ the Manager, ~~except~~in ~~for~~accordance ~~interest~~with ~~income and certain expenses such as dry-hole costs, trust fees, depletion and amortization, which are allocated 99% to shareholders and 1% to~~ the ~~Manager~~LLC agreement.

Distributions

Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement. ~~Effective~~During ~~October~~ 2010, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

2. Oil and Gas Properties

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. The Fund recorded credits to dry-hole costs of $52 thousand and $81 thousand during the years ended December 31, 2011 and 2010, respectively.

3. Related Parties

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of the total shareholder capital. During 2007, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs, which are included in general and administrative expenses, totaled $40 thousand and $80 thousand for the years ended December 31, 2011 and 2010, respectively.

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Table of Contents

~~The Manager is entitled to receive a 15% interest in cash distributions made by the Fund~~2. ~~Effective~~Oil ~~October~~and ~~2010,~~Gas the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. Distributions paid to the Manager for the year ended December 31, 2010 were $0.1 million.Properties

3. Related Parties

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of the total shareholder capital. During 2007, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs, which are included in general and administrative expenses, totaled $40 thousand for each of the years ended December 31, 2012 and 2011, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. During 2010, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.

None of the amounts paid to the Manager have 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.

4. Fair Value Measurements

The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. At December 31, ~~2011~~2012 and ~~2010~~2011, cash and cash equivalents, approximate fair value based on Level 1 inputs. The fair value of the Fund’s mortgage-backed securities within the salvage fund, ~~production~~are ~~receivable~~recorded based on Level 2 inputs, ~~and~~as ~~accrued~~such ~~expenses~~instruments ~~approximate~~trade ~~fair~~in ~~value~~over-the-counter markets.

5. Commitments and Contingencies

Capital Commitments

The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. The Fund has reached the end of its investment cycle. As of December 31, ~~2011~~2012, the Fund had committed to spend an additional $5042 thousand related to its ~~investment~~investments in oil and gas properties, of which $1532 thousand is expected to be spent during ~~the next twelve months~~2013. Based upon its current reserve estimates, the Fund expects cash ~~flow~~flows from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. InAt such time the ~~event~~Manager ofdetermines athat ~~temporary~~there ~~production~~is ~~stoppage,~~uncertainty ~~causing~~surrounding the Fund’s ~~wells~~ability to ~~not~~continue ~~produce~~to ~~cash~~fund ~~flow~~its ~~from~~ operations, ~~the~~or ~~Fund~~that ~~may~~terminating ~~borrow from~~ the ~~Manager~~Fund ~~until~~would ~~such~~be ~~time~~in ~~that~~the ~~production~~best iseconomic ~~resumed.~~interests Atof ~~such~~its ~~time~~shareholders, the Manager ~~determines~~would ~~that~~take ~~the~~any ~~Fund~~such isactions nothat ~~longer~~are ~~capable~~necessary ~~of continuing~~ to ~~fund~~bring ~~its~~about ~~operations,~~ the ~~Manager~~dissolution ~~would~~of ~~elect to dissolve~~ the Fund.

Environmental Considerations

The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At December 31, ~~2011~~2012 and ~~2010~~2011, there were no known environmental contingencies that required the Fund to record a liability.

In response to the April 2010 oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore. Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

Insurance Coverage

The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.

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6Effective October 22, 2012, the United States Department of Interior, acting through the Bureau of Safety and Environmental Enforcement, implemented the Final Drilling Safety Rule (the “Final Rule”) which refined certain interim rules imposed in the immediate wake of the 2010 Deepwater Horizon oil spill. ~~Subsequent~~The ~~Events~~Final Rule was promulgated for the prevention of waste and for the conservation of natural resources of the Outer Continental Shelf under the rulemaking authority of the Outer Continental Shelf Lands Act. The United States Congress continues to consider a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore, in addition to the Final Rule. Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

~~The~~Insurance Fund has assessed the impact of subsequent events through the date of issuance of its financial statements, and has concluded that there were no such events that require adjustment to, or disclosure in, the notes to the financial statements.Coverage

The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.

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Ridgewood Energy L Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities - Unaudited

In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are ~~currently~~ located in the United States offshore waters of Texas and Louisiana in the Gulf of Mexico.

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
	December 31,
	2011			2010
	2012			2011
	(in thousands)
Advances to operators for working interests and expenditures	$	-		$	134
Proved properties	$	9,785		$	9,755
Proved properties		9,755			9,249
Accumulated depletion and amortization		(7,419	)		(5,693	)
Total oil and gas properties		9,755			9,383
Oil and gas properties, net	$	2,366		$	4,062
Accumulated depletion and amortization		(5,693	)		(4,856	)
Oil and gas properties, net	$	4,062		$	4,527

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
	Year ended December 31,
		2011			2010
	2012			2011
	(in thousands)
Exploration costs	$	(873	)	$	~~397~~(87	)
Development costs		~~416~~36			~~398~~416
	$	~~329~~33		$	~~795~~329

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Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by an independent petroleum ~~engineer~~engineers, Netherland, Sewell & Associates, Inc. at December 31, 2012 and Ryder Scott Company, L.P. at December 31, 2011 ~~and 2010~~. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

December 31, 2011

December 31, 2010

December 31, 2012

December 31, 2011

United States

Oil (BBLS)

Gas (MCF)

Oil (BBLS)

Gas (MCF)

Proved developed and undeveloped reserves:

Beginning of year

4426,~~677~~796

1869,~~099,797~~751

4844,~~863~~677

1,~~378~~099,~~268~~797

Revisions of previous estimates (a)

(127,~~108~~885

)

99(117,~~507~~724

)

~~520~~(12,108

)

1799,~~817~~507

Production

(53,~~773~~233

)

(~~329~~186,~~553~~348

)

(45,~~706~~773

)

(~~296~~329,~~288~~553

)

End of year

2615,~~796~~678

~~869~~565,~~751~~679

4426,~~677~~796

1869,~~099,797~~751

Proved developed reserves:

Beginning of year

4426,~~677~~796

1869,~~099,797~~751

4744,~~717~~677

1,~~106~~099,~~694~~797

End of year

2615,~~796~~678

~~869~~565,~~751~~679

4426,~~677~~796

1869,~~099,797~~751

Proved undeveloped reserves:

Beginning of year

~~1,146~~-

~~271,574~~-

End of year

(a) Revisions of previous estimates during the ~~year~~years ended December 31, ~~2011~~2012 ~~were~~and ~~primarily~~2011 attributable to the determination that one of the Fund's wells was fully depleted coupled with revisions due to well performance. Revisions of previous estimates during the year ended December 31, 2010 were ~~primarily~~ attributable to well performance.

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Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. At December 31, 2011 and 2010, future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

	December 31,
	2011			2010
	(in thousands)
Future cash inflows	$	7,168		$	8,768
Future production costs		(1,074	)		(961	)
Future development costs		(736	)		(1,232	)
Future net cash flows		5,358			6,575
10% annual discount for estimated timing of cash flows		(902	)		(1,090	)
Standardized measure of discounted future net cash flows	$	4,456		$	5,485

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 were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

Table V - Changes in the Standardized Measure for Discounted Cash Flows 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.

	December 31,
	2012			2011
	(in thousands)
Future cash inflows	$	3,886		$	7,168
Future production costs		(1,131	)		(1,074	)
Future development costs		(663	)		(736	)
Future net cash flows		2,092			5,358
10% annual discount for estimated timing of cash flows		(251	)		(902	)
Standardized measure of discounted future net cash flows	$	1,841		$	4,456

	Year ended December 31,
	2011			2010
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	315		$	1,498
Sales and transfers of oil and gas produced during the period		(1,805	)		(1,383	)
Changes in estimated future development costs		496			207
Net change due to revisions in quantities estimates		(343	)		220
Accretion of discount		549			477
Other		(241	)		(308	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(1,029	)	$	711

Table V - Changes in the Standardized Measure for Discounted Cash Flows

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

	Year ended December 31,
	2012			2011
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	(1,615	)	$	315
Sales and transfers of oil and gas produced during the period		(732	)		(1,805	)
Changes in estimated future development costs		73			496
Net change due to revisions in quantities estimates		(388	)		(343	)
Accretion of discount		446			549
Other		(399	)		(241	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(2,615	)	$	(1,029	)

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

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