10-K

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, 2012

or

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-53177

Ridgewood Energy W Fund, LLC

(Exact name of registrant as specified in its charter)

Delaware	26-0225130
(State or other jurisdiction of incorporation or organization)	(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	o            (Do not check if a smaller reporting company)	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 oNo x

There is no market for the shares of LLC Membership Interest in the Fund.  As of February 26, 2013 there are 332.2918 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY W FUND, LLC

2012 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	10
	ITEM 1B	UNRESOLVED STAFF COMMENTS	10
	ITEM 2	PROPERTIES	11
	ITEM 3	LEGAL PROCEEDINGS	12
	ITEM 4	MINE SAFETY DISCLOSURES	12
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	13
	ITEM 6	SELECTED FINANCIAL DATA	13
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	18
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	19
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	19
	ITEM 9A	CONTROLS AND PROCEDURES	19
	ITEM 9B	OTHER INFORMATION	19
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	20
	ITEM 11	EXECUTIVE COMPENSATION	21
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	21
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	21
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	22
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	23
		SIGNATURES	24

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy W 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 projects, investments, insurance, capital expenditures and 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.

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PART I

ITEM 1.  BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on May 17, 2007 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 June 15, 2007, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  On January 31, 2011, pursuant to the LLC Agreement, Ridgewood Energy Corporation, as manager of the Fund converted all then outstanding Investor GP Shares to Limited Liability Shares.  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 December 17, 2007.  The Fund raised $66.0 million and, after payment of $10.8 million in offering fees, commissions and investment fees, the Fund had $55.2 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.

As compensation for its services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund.  The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Management fees for the years ended December 31, 2012 and 2011 were $1.1 million and $1.2 million, respectively.  Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2012 and 2011 were $2.1 million and $2.7 million, respectively.

In addition to the management fee, 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.

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.  The Fund has invested in the drilling and development of both shallow and deepwater oil and natural gas projects in the U.S. offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico, in partnership with exploration and production companies.  At December 31, 2012, the Fund’s participation in investments in oil and natural gas properties have been completely identified and contracted and the balance of the Fund’s capital has been fully allocated to complete such projects.  Accordingly, the Fund does not expect to investigate or invest in any additional projects, other than those in which the Fund currently has a working interest.

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Investment Strategy

The Fund 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.    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, geological and geophysical teams and a 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 third-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, 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 enters 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.

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Project Information

Existing projects are located in Louisiana state waters and the waters of the Gulf of Mexico offshore from 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.  In certain circumstances, as described below, the BOEM has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects.  The Fund’s working interests in leases located in state waters of the Gulf of Mexico, offshore Louisiana, are not subject to BOEM royalties, rather, such working interests pay a 25% royalty and certain additional taxes to the State of Louisiana. Other than the foregoing royalties, the Fund does not have material royalty burdens other than as provided by the terms of the Fund’s credit agreement, which requires the Fund to pay royalties from the Beta Project to the lender. See Note 6 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

Deep Gas Royalty Relief

On January 26, 2004, the BOEM promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the "Royalty Relief Rule"). Under the Royalty Relief Rule, lessees are eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief is available for wells drilled and perforated deeper than 18,000 feet subsea. The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the Continental Shelf nor does it apply if the price of natural gas exceeds $11.01 (estimated) Million British Thermal Units (“mmbtu”), adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production.  The Deepwater Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater.  For purposes of royalty relief, under the Deepwater Relief Act, the BOEM defines deepwater as depths in excess of 656 feet, or 200 meters.  In order for a lease to be eligible for royalty relief under the Deepwater Relief Act, it must be located in the Gulf of Mexico and west of 87 degrees and 30 minutes West longitude (essentially the Florida-Alabama boundary).

Currently, for leases entered into after November 2000, the BOEM assigns a lease a specific volume of royalty suspension based on how the suspension amount would affect the economics of the lease’s development.  Any such royalty suspension applicable to a particular lease is generally set forth in the lease auction materials prepared by the BOEM.  The amount of the suspension, if any, is not determined by water depth levels (as it had been in the past) but rather based upon the BOEM’s view of the characteristics and economics of the project.  For example, a project deemed relatively secure and safe, such as those near existing transportation infrastructure, may receive no royalty relief while a similar project far away from any such infrastructure or in an area deemed more risky may receive significant royalty relief.  As a result, unlike the royalty relief associated with deep drilling in shallow waters, there is no formulaic or predictable means of determining in advance whether, and to what extent, royalty relief would be available for a potential deepwater project.

4

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, 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		4		0.30

Acreage Data

The following table sets forth the Fund’s interests in developed and 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				Undeveloped Acres
Gross		Net		Gross		Net
	12,118		1,026		6,124		184

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.

5

		Total Spent
	Working	through		Total Fund
Project	Interest	December 31, 2012		Budget		Status
		(in thousands)
Non-producing Properties
Beta Project	3.0%	$	4,020	$	25,207	Well deemed to be a discovery in February 2012. Completion efforts are ongoing and production is expected to commence in 2016.  Financing arrangements finalized in fourth quarter 2012.
Producing Properties
Cobalt Project	5.0%	$	2,368	$	2,398	Production commenced in 2009.   Recompletions are planned for 2015 and 2016 at an estimated cost of $30 thousand.
Liberty Project	12.0%	$	13,424	$	13,544	Production commenced in 2010. Recompletion is planned for 2014 at an estimated cost of  $0.1 million.
Raven Project well #1	6.25%	$	1,627	$	1,627	Production commenced 2010.
Raven Project well #2	6.25%	$	1,097	$	1,097	Production commenced in July 2011.
Fully Depleted Properties
Main Pass 283/279 well #1	9.0%	$	2,712	$	2,712	Production commenced in 2008.  Workover at a cost of $10 thousand was completed during first quarter 2012, which resulted in modest additional production.  The Fund elected to go non-consent on any additional workovers for this well and is in the process of withdrawing its interest in the project.
Conveyances
West Cameron 57	20.0%	$	7,579	$	7,579	Production commenced in 2008.  Working interest conveyed to operator effective February 1, 2011.

Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in West Cameron 57 to Marlin Coastal, L.L.C. (“Marlin”), the operator of the well, in exchange for Marlin’s assumption of all future obligations and liabilities of the well.

Marketing/Customers

The Manager, on behalf of the Fund has engaged Energy Upgrade, Inc. to market the Fund’s oil and natural gas. 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 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 projects will have access to pipeline transportation and 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.   

6

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, shut-ins, or production stoppages due to hurricane activity in 2012.

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 properties are operated by Apache Corporation, LLOG Exploration Company, LLC, Walter Oil & Gas Corporation and W&T Offshore, Inc.

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.  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

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.  As a result of the significant capital required and number of wells anticipated for the Beta Project, any further contributions to the salvage fund will 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. The Fund through its Manager has competed 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.

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Employees

The Fund has no employees.  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.

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 also owns 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 October 22, 2012, the Department of Interior, acting through the BSEE, 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 Final Rule was promulgated for the prevention of waste and for the 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 (5) requires independent third-party verification of certain safety measures and enhanced documentation for blowout preventer inspections and maintenance.

8

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.

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.

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.

9

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.

Dodd-FrankAct.  The Dodd-Frank Act, signed into law in July 2010, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market and, in addition, requires certain additional SEC reporting requirements.

The Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Dodd-Frank mandates that many 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 relevant 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 addition, as required by Dodd-Frank, the CFTC has set “speculative position limits” (limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts.  These requirements under Dodd-Frank could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may 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.

10

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 following table sets forth the Fund’s drilling activity for the years ended December 31, 2012 and 2011.  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, which produce both oil and natural gas, are located in the offshore waters of the Gulf of Mexico.  During the years ended December 31, 2012 and 2011, the Fund had no drilling activity for developmental wells.  See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about wells in-progress at December 31, 2012.

	2012				2011
	Gross		Net		Gross		Net
Exploratory wells:
Productive		-		-		1		0.06
In-progress		1		0.03		1		0.03
Exploratory well total		1		0.03		2		0.09

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 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, 2012 were prepared by Netherland, Sewell & Associates, Inc. (“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 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 99.2 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. 

Proved Undeveloped Reserves.At December 31, 2012 the Fund had approximately 418 thousand barrels and 1.4 million mcf of proved undeveloped oil and natural gas reserves, respectively, which are related to the Beta Project, which was determined to be a discovery during 2012, and the Raven Project.  At December 31, 2011 the Fund had approximately 6 thousand barrels and 0.8 million mcf of proved undeveloped oil and natural gas reserves, respectively, relating to the Raven Project.  The development of the Beta Project is ongoing and production is expected to commence in 2015.  The Fund will evaluate the development alternatives for the Raven Project’s proved undeveloped reserves during 2013.

11

Costs incurred to advance the development of proved undeveloped reserves were approximately $0.8 million during the year ended December 31, 2012, which principally related to the Beta Project.  Information regarding estimated future development costs relating to the development of the Fund’s non-producing properties, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.

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, 2012 and 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, 2012, the Fund had no obligations or delivery commitments under any existing contracts.

ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4.  MINE SAFETY DISCLOSURES

None.

12

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 824 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.  Due to the significant capital required to develop the Beta Project, future distributions may be impacted by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations. There is 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. During the years ended December 31, 2012 and 2011, the Fund paid distributions totaling $13.9 million and $18.1 million, respectively.

ITEM 6.  SELECTED FINANCIAL DATA

Not required.

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

Overview of the Fund’s Business

The Fund was organized 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 a 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” within this Annual Report for a discussion of the Fund’s significant accounting policies.

13

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. Development costs including 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. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”

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 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.

Asset Retirement Obligations

Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed.  The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics, and ongoing discussions with the wells’ operators.  Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment.  Estimates are reviewed on a bi-annual 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 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.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, 2012 and 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.

14

	Year ended December 31,
	2012			2011
	(in thousands)
Revenue
Oil and gas revenue	$	17,144		$	23,966
Expenses
Depletion and amortization		3,269			7,456
Dry-hole costs		51			42
Management fees to affiliate		1,066			1,151
Operating expenses		1,598			1,858
General and administrative expenses		326			308
Total expenses		6,310			10,815
Gain (loss) on sale of oil and gas properties		50			(25	)
Income from operations		10,884			13,126
Other loss		(107	)		(261	)
Net income	$	10,777		$	12,865

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.

	Year ended December 31,
	2012		2011
Number of wells producing		4		5
Total number of production days		1,444		1,506
Oil sales (in thousands of barrels)		128		168
Average oil price per barrel	$	106	$	106
Natural gas sales (in thousands of mcfs)		933		1,031
Average natural gas price per mcf	$	2.72	$	3.97
Natural gas liquid ("NGL") sales (in thousands of barrels)		1,035		1,633
Average NGL price per gallon	$	0.93	$	1.18

The decreases in number of wells producing and total production days were principally attributable to Main Pass 283/279 well #1, which reached the end of its economic life in the first quarter 2012. The decreases in sales volumes were principally attributable to natural declines in well production, primarily related to the Liberty and Cobalt projects, coupled with the impact of Main Pass 283/279 well #1.  See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

Oil and Gas Revenue.   Oil and gas revenue for the year ended December 31, 2012 was $17.1 million, a $6.8 million decrease from the year ended December 31, 2011.  The decrease is attributable to a decrease in sales volumes totaling $5.4 million coupled with the impact of decreased average prices totaling $1.4 million.  See “Overview” above for additional information.

Depletion and Amortization.  Depletion and amortization for the year ended December 31, 2012 was $3.3 million, a decrease of $4.2 million from the year ended December 31, 2011.  The decrease resulted from a decrease in average depletion rates totaling $3.0 million coupled with a decrease in production volumes totaling $1.4 million. Additionally, during the prior year, the Fund recorded a credit to depletion and amortization of $0.3 million resulting from the relief of the asset retirement obligation for West Cameron 57. The decrease in the average depletion rates was primarily due to the composite of productive wells. See “Overview” above for additional information.

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 adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.  Dry-hole costs, inclusive of such credits, are detailed in the following table:

15

	Year ended December 31,
Project	2012			2011
	(in thousands)
Dakota Project	$	54		$	57
Other wells		(3	)		(15	)
	$	51		$	42

Management Fees to Affiliate.   Management fees for the years ended December 31, 2012 and 2011 were $1.1 million and $1.2 million, respectively.  An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.

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	$	1,463	$	1,819
Geological costs		100		2
Workover expense		22		24
Accretion expense		13		13
	$	1,598	$	1,858

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  During the year ended December 31, 2012, the average production cost was $0.79 per mcfe compared to $0.80 per mcfe during the year ended December 31, 2011.  Geological costs, which were primarily related to the Beta Project, represent costs incurred to obtain seismic data, surveys and lease rentals.  Workover expenses represent costs to restore or stimulate production of existing reserves of a proved property.  Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.  

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,
	2012		2011
	(in thousands)
Accounting fees	$	125	$	126
Insurance expense		113		173
Legal costs and other		88		9
	$	326	$	308

Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  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.  During the year ended December 31, 2012, legal costs represent fees incurred in connection with obtaining financing for the Beta Project.  See Note 6 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the debt acquisition costs.

Gain (Loss) on Sale of Oil and Gas Properties.  During the year ended December 31, 2012, the Fund recorded a gain on sale of oil and gas properties of $50 thousand as a result of the relief of asset retirement obligations for the Ajax Project, which the Fund sold in June 2010.  During the year ended December 31, 2011, the Fund recorded a loss on sale of oil and gas properties of $25 thousand as a result of a revision to estimated asset retirement obligations for the Ajax Project.

Other Loss.  Other loss for the years ended December 31, 2012 and 2011 is detailed in the following table.

16

	Year ended December 31,
	2012			2011
	(in thousands)
Interest income	$	24		$	27
Realized losses on derivative instruments		(131	)		(293	)
Unrealized gains on derivative instruments		-			5
	$	(107	)	$	(261	)

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, 2012 were $14.5 million, primarily related to revenue received of $17.5 million, partially offset by operating expenses paid of $1.7 million, management fees of $1.1 million, and general and administrative expenses paid of $0.3 million.

Cash flows provided by operating activities for the year ended December 31, 2011 were $20.6 million, primarily related to revenue received of $24.4 million, partially offset by operating expenses paid of $1.8 million, management fees of $1.2 million, purchases of derivative instruments of $0.4 million, and general and administrative expenses paid of $0.4 million.

Investing Cash Flows

Cash flows provided by investing activities for the year ended December 31, 2012 were $3.1 million, primarily related to proceeds from the maturity of U.S. Treasury securities totaling $5.0 million, partially offset by capital expenditures for oil and gas properties of $1.9 million.

Cash flows used in investing activities for the year ended December 31, 2011 were $1.1 million, primarily related to investments in U.S. Treasury securities totaling $5.0 million and capital expenditures for oil and gas properties of $1.1 million, partially offset by proceeds from the maturity of U.S. Treasury securities totaling $5.0 million.

Financing Cash Flows

Cash flows used in financing activities for the year ended December 31, 2012 were $14.0 million, primarily related to manager and shareholder distributions of $13.9 million and debt acquisition costs of $0.1 million.  See Note 6 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the debt acquisition costs.

Cash flows used in financing activities for the year ended December 31, 2011 were $18.1 million, related to manager and shareholder distributions.

Estimated Capital 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 has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $21.2 million related to the development of this project, which the Fund anticipates will include a four-well development with related platform and pipeline infrastructure. It is also possible that full development of the Beta Project will entail the drilling of additional wells beyond the four projected wells, the cost of which is not included in the above estimates. See “Liquidity Needs” below for additional information.

Capital expenditures for investment properties have been funded with the capital raised by the Fund in its private placement offering, and in certain circumstances, through debt financing. 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.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its operations and capital expenditures for its investment properties. Operations are funded utilizing operating income, short-term investments, if any, existing cash on-hand and income earned therefrom.

17

As of December 31, 2012, the Fund expects to spend an additional $21.3 million related to its investments in oil and gas properties, inclusive of $21.2 million to develop the Beta Project, of which $4.4 million is expected to be spent during 2013.  Total capital commitments exceed available working capital by $11.1 million at December 31, 2012, which includes interest costs and asset retirement obligations for the Beta Project.  In November 2012, the Fund entered into a credit agreement that provides for an aggregate loan commitment of up to $9.4 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  Principal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2020.  See “Credit Agreement” below for additional information.  The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, all or a portion of the management fee is paid from operating income.

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. Due to the significant capital required to develop the Beta Project, distributions may be impacted by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations.

Credit Agreement

In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as administrative agent and lender (and any other banks or financial institutions that may in the future become a party thereto) that provides for an aggregate loan commitment to the Fund of approximately $9.4 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of December 31, 2012, the Fund had no borrowings under this credit agreement.  See Note 6 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding this credit agreement.

The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warrants and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the Lenders under the Credit Agreement may accelerate the maturity of the loans and require full and immediate repayment of all borrowings under the Credit Agreement. Finally, the Lenders obligation to make the Loan is subject to customary conditions precedent including the delivery to Lenders of effective corporate organizational documents, pro forma financial statements, evidence of defensible title to the Beta Project and the payment of fees.  The Fund believes it is in compliance with all covenants under the Credit Agreement at December 31, 2012.

Off-Balance Sheet Arrangements

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

Contractual Obligations

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

18

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.

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, 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.

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, 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, 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, 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.

19

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, 2012 are as follows:

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

The officers in the above table have also been officers of the Fund since May 17, 2007, 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.

20

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 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, 2012, all filing requirements applicable to its officers, directors and 10% beneficial owners were met on a timely basis.

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 332.2918 shares outstanding at February 26, 2013. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.

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

The LLC Agreement provides that the Manager render management, administrative and advisory services.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for the years ended December 31, 2012 and 2011 were $1.1 million and $1.2 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2012 and 2011 were $2.1 million and $2.7 million, respectively.

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.

21

In November 2012, the Fund entered into a credit agreement along with other entities managed by the Manager.  See Note 6 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

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, 2012 and 2011.

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

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

22

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.

(a) (3)    

EXHIBIT TABLE	TITLE OF EXHIBIT	METHOD OF FILING
3.1	Certificate of Formation of Ridgewood Energy W Fund, LLC dated May 17, 2007	Incorporated by reference to the Fund’s Form 10 filed on April 18, 2008
3.2	Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy W Fund, LLC dated April 13, 2011	Incorporated by reference to the Fund’s Form 10Q filed on May 12, 2011
10.1	Credit Agreement dated as of November 27, 2012 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund's Form 8-K filed on December 3, 2012
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	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)	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	Filed herewith
99.1	Report of Netherland, Sewell & Associates, Inc.	Filed herewith
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.INS	XBRL Instance Document	*
101.SCH	XBRL Taxonomy Extension Schema	*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*
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.

23

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 W FUND, LLC
Date:  February 26, 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
/s/ ROBERT E. SWANSON	Chief Executive Officer	February 26, 2013
Robert E. Swanson	(Principal Executive Officer)
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer	February 26, 2013
Kathleen P. McSherry	(Principal Financial and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
BY:  /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	February 26, 2013
Robert E. Swanson

24

INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2012 and  2011	F-3
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, 2012 and 2011	F-5
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-14

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Manager of Ridgewood Energy W Fund, LLC:

We have audited the accompanying balance sheets of Ridgewood Energy W Fund, LLC (the "Fund") as of December 31, 2012 and 2011, and the related statements of operations, changes in members’ capital, and cash flows for the years then 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 W Fund, LLC as of December 31, 2012 and 2011, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Parsippany, New Jersey

February 26, 2013

F-2

RIDGEWOOD ENERGY W FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	9,220		$	5,635
Salvage fund		33			-
Short-term investments in marketable securities		-			5,001
Production receivable		1,640			2,045
Other current assets		162			253
Total current assets		11,055			12,934
Salvage fund		1,092			1,103
Other assets		697			-
Oil and gas properties:
Unproved properties		-			2,087
Proved properties		22,706			22,248
Less:  accumulated depletion and amortization		(14,320	)		(13,807	)
Total oil and gas properties, net		8,386			10,528
Total assets	$	21,230		$	24,565
Liabilities and Members' Capital
Current liabilities:
Due to operators	$	715		$	918
Accrued expenses		40			34
Asset retirement obligations		33			-
Total current liabilities		788			952
Asset retirement obligations		931			994
Total liabilities		1,719			1,946
Commitments and contingencies (Note 7)
Members' capital:
Manager:
Distributions		(5,807	)		(3,724	)
Retained earnings		5,758			3,671
Manager's total		(49	)		(53	)
Shareholders:
Capital contributions (625 shares authorized;
332.2918 issued and outstanding)		65,965			65,965
Syndication costs		(7,823	)		(7,823	)
Distributions		(34,544	)		(22,742	)
Accumulated deficit		(4,038	)		(12,728	)
Shareholders' total		19,560			22,672
Total members' capital		19,511			22,619
Total liabilities and members' capital	$	21,230		$	24,565

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

F-3

RIDGEWOOD ENERGY W FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2012			2011
Revenue
Oil and gas revenue	$	17,144		$	23,966
Expenses
Depletion and amortization		3,269			7,456
Dry-hole costs		51			42
Management fees to affiliate (Note 4)		1,066			1,151
Operating expenses		1,598			1,858
General and administrative expenses		326			308
Total expenses		6,310			10,815
Gain (loss) on sale of oil and gas properties		50			(25	)
Income from operations		10,884			13,126
Other loss		(107	)		(261	)
Net income	$	10,777		$	12,865
Manager Interest
Net income	$	2,087		$	2,983
Shareholder Interest
Net income	$	8,690		$	9,882
Net income per share	$	26,150		$	29,740

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

F-4

RIDGEWOOD ENERGY W FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2010		332.2918	$	(327	)	$	28,141		$	27,814
Distributions		-		(2,709	)		(15,351	)		(18,060	)
Net income		-		2,983			9,882			12,865
Balances, December 31, 2011		332.2918		(53	)		22,672			22,619
Distributions		-		(2,083	)		(11,802	)		(13,885	)
Net income		-		2,087			8,690			10,777
Balances, December 31, 2012		332.2918	$	(49	)	$	19,560		$	19,511

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

F-5

RIDGEWOOD ENERGY W FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2012			2011
Cash flows from operating activities
Net income	$	10,777		$	12,865
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion and amortization		3,269			7,456
Dry-hole costs		51			42
Accretion expense		13			13
(Gain) loss on sale of oil and gas properties		(50	)		25
Interest earned on marketable securities		(1	)		(5	)
Derivative instrument loss		131			288
Derivative instrument settlements		11			13
Debt acquisition costs		80			-
Changes in assets and liabilities:
Decrease in production receivable		405			389
Increase in other current assets		(51	)		(454	)
(Decrease) increase in due to operators		(145	)		42
Increase (decrease) in accrued expenses		6			(92	)
Net cash provided by operating activities		14,496			20,582
Cash flows from investing activities
Capital expenditures for oil and gas properties		(1,926	)		(1,108	)
Proceeds from maturity of investments		5,002			5,003
Investments in marketable securities		-			(4,999	)
Interest reinvested in salvage fund		(22	)		(20	)
Net cash provided by (used in) investing activities		3,054			(1,124	)
Cash flows from financing activities
Distributions		(13,885	)		(18,060	)
Debt acquisition costs		(80	)		-
Net cash used in financing activities		(13,965	)		(18,060	)
Net increase in cash and cash equivalents		3,585			1,398
Cash and cash equivalents, beginning of year		5,635			4,237
Cash and cash equivalents, end of year	$	9,220		$	5,635
Supplemental schedule of non-cash operating activities
Adjustments to asset retirement obligations	$	50		$	-
Supplemental schedule of non-cash financing activities
Deferred financing charges related to the conveyance of overriding royalty interest in the Beta Project	$	697		$	-

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

F-6

RIDGEWOOD ENERGY W FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy W Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on May 17, 2007  and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of June 15, 2007 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 4, 6 and 7.

Use of Estimates

The preparation of financial statements in 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 the fair value of financial instruments, 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, 2013, the federally insured limits of the Fund’s deposits are $250 thousand per insured financial institution.  Based upon these limits, at December 31, 2012, the Fund’s bank balances exceeded federally insured limits by $9.4 million, of which $0.4 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Investments in Marketable Securities

At times, the Fund may invest in U.S. Treasury bills and notes.  These investments are considered short-term when their maturities are one year or less, and long-term when their maturities are greater than one year.  For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  At December 31, 2011, the Fund’s investments in marketable securities were classified as held-to-maturity.  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.

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, 2012, the Fund had investments in federal agency mortgage-backed securities within its salvage fund of $0.7 million, which mature in January 2042, that are classified as available-for-sale. Available-for-sale securities are carried in the financial statements at fair value.  At December 31, 2012, there was no unrealized gain or loss related to the Fund’s available-for-sale investments.  At December 31, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $0.9 million. The Fund had no investments in available-for-sale securities at December 31, 2011. Interest earned on the account will become part of the salvage fund.  There are no restrictions on withdrawals from the salvage fund.

F-7

Debt Discounts and Deferred Financing Costs

Debt discounts and deferred financing costs include lender fees and other costs of the credit agreement such as the conveyance of override royalty interests related to the Beta Project.  These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”.  At December 31, 2012, $0.7 million of debt discounts and deferred financing costs remained unamortized.  There was no amortization expense during the years ended December 31, 2012 and 2011.

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, 2012 and 2011, amounts recorded in due to operators totaling $0.4 million and $0.5 million, 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, 2012 and 2011.

	2012			2011
	(in thousands)
Balance - Beginning of year	$	994		$	905
Liabilities incurred		20			42
Liabilities settled/conveyed		(50	)		(262	)
Accretion expense		13			13
Revisions in estimated cash flows		(13	)		296
Balance - End of year	$	964		$	994

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.

F-8

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 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.

Derivative Instruments    

The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Derivative instruments are carried on the balance sheet at fair value and recorded as either an asset or liability.  Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met.  At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as other income on the statement of operations.  The estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.  See Note 2.  “Derivative Instruments”.

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 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.

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 to shareholders and the Manager in accordance with the 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.

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.

F-9

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.  Derivative Instruments

The Fund periodically enters into derivative contracts relating to its oil or gas production. The use of such derivative instruments limits the downside risk of adverse price movements.  The estimated fair value of such contracts is based upon various factors, including reported prices on NYMEX and ICE, volatility, and the time value of options. See Note 5. “Fair Value Measurements.”  The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.

At December 31, 2012, the Fund had no outstanding derivative contracts with respect to its future production. At December 31, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil that were not designated for hedge accounting as detailed in the following table.

Production Period	Type of Contract	Volume in barrels		ICE Contract Price per barrel		Estimated  Fair Value  Asset
						(in thousands)
January 1, 2012 - April 30, 2012	Put Options		12,571	$	105.00	$	61
January 1, 2012 - April 30, 2012	Put Options		5,966	$	112.00	$	52
January 1, 2012 - April 30, 2012	Put Options		5,966	$	100.00	$	18

For the years ended December 31, 2012 and 2011, the Fund’s derivative instrument income consisted of the following:

	Year ended December 31,
	2012			2011
	(in thousands)
Realized losses on derivative instruments	$	(131	)	$	(293	)
Unrealized gains on derivative instruments		-			5
	$	(131	)	$	(288	)

3.  Oil and Gas Properties

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves.  Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves.  The following table reflects the net changes in unproved properties for the years ended December 31, 2012 and 2011.

	December 31,
	2012			2011
	(in thousands)
Balance - Beginning of year	$	2,087		$	1,791
Additions to capitalized exploratory well costs
pending the determination of proved reserves		-			1,093
Reclassifications to proved properties based on
the determination of proved reserves		(2,087	)		(797	)
Capitalized exploratory well costs charged to
expense		-			-
Balance - End of year	$	-		$	2,087

Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in West Cameron 57 to Marlin Coastal, L.L.C. (“Marlin”), the operator of the well, in exchange for Marlin’s assumption of all future obligations and liabilities of the well. As a result of the conveyance, during the first quarter 2011, the Fund relieved the asset retirement obligation of $0.3 million that it had previously established for the well. Such amount was included in the statement of operations within “Depletion and amortization.”

F-10

During the year ended December 31, 2012, the Fund recorded a gain on sale of oil and gas properties of $50 thousand as a result of the relief of its asset retirement obligations for the Ajax Project.  During the year ended December 31, 2011, the Fund recorded a loss on sale of oil and gas properties of $25 thousand as a result of additional estimated costs related to asset retirement obligations for the Ajax Project.

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 adjustments on certain wells from their respective operators upon review and audit of the wells’ costs.  Dry-hole costs, inclusive of such credits, are detailed in the following table.

	Year ended December 31,
Project	2012			2011
	(in thousands)
Dakota Project	$	54		$	57
Other wells		(3	)		(15	)
	$	51		$	42

4.  Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services to the Fund.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for the years ended December 31, 2012 and 2011 were $1.1 million and $1.2 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2012 and 2011were $2.1 million and $2.7 million, respectively.

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.

In November 2012, the Fund entered into a credit agreement along with other entities managed by the Manager.  See Note 6. “Credit Agreement – Beta Project Financing,” for additional information.

5.  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, 2012 and 2011, cash and cash equivalents and short-term investments in marketable securities approximate fair value based on Level 1 inputs.  At December 31, 2012, the fair value of the Fund’s mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.   At December 31, 2011, derivative instruments were recorded at fair value based on Level 2 inputs, as the instruments are over-the-counter derivatives with a third party.

F-11

6. Credit Agreement – Beta Project Financing

In November 2012, the Fund, entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $9.4 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. In addition to the Fund’s execution of the Credit Agreement, Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy A-1 Fund, LLC and Ridgewood Energy B-1 Fund, LLC (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Fund. The Manager serves as the manager for each Ridgewood Participating Fund.

As of December 31, 2012, the Fund had no borrowings under the Credit Agreement.

The Fund anticipates it will borrow approximately $9.4 million over the development period of the Beta Project, which will bear interest at 8% compounded annually and accrue only on Loan proceeds as they are drawn. Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected to occur in 2016. At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund’s total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund’s total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020.  The Loan may be prepaid by the Fund without premium or penalty.

As additional consideration to the Lenders, each Ridgewood Participating Fund has agreed to convey an overriding royalty interest (“ORRI”) to the Lenders in their working interests in the Beta Project. Each Ridgewood Participating Fund’s share of the Lender’s aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Using these principles, the Fund’s percentage ORRI to be granted to the Lenders equals 12.24% of the Fund’s production until the Fund’s share of Beta Project’s cumulative production equals approximately 0.78 million barrels of oil (“MMBO”), net of royalties. Upon reaching that milestone, the Fund’s ORRI percentage decreases to 8.16% of the Fund’s production until the Fund’s share of the Beta Project’s cumulative production equals approximately 1.21 MMBO, net of royalties, whereupon it decreases to, and remains at, 4.08% of the Fund’s net production. The Ridgewood Funds can collectively borrow up to $15.0 million prior to the satisfaction or waiver of certain administrative conditions precedent. The Fund recorded the additional consideration as debt discounts and deferred financing costs at a fair value of $0.7 million, which will be amortized to interest expense over the expected payoff period of the loan.  The fair value of the ORRI was determined using net discounted cash flows from the Beta Project related to the ORRI based on level 3 inputs, which include projected net income from reserves and forward pricing curves.  The outstanding debt discounts and deferred financing costs recorded on the balance sheet within “Other assets” is $0.7 million.

The Credit Agreement contains customary covenants, for which the Fund believes it is in compliance at December 31, 2012.

The expenses related to the securing of the Credit Agreement were borne by the Ridgewood Participating Funds. The Fund’s portion of such expenses was $0.1 million.

7.   Commitments and Contingencies

Capital Commitments

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 has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $21.2 million related to the development of this project, which the Fund anticipates will include a four-well development with related platform and pipeline infrastructure. It is also possible that full development of the Beta Project will entail the drilling of additional wells beyond the four projected wells, the cost of which is not included in the above estimates.

As of December 31, 2012, the Fund expects to spend an additional $21.3 million related to its investments in oil and gas properties, inclusive of $21.2 million to develop the Beta Project, of which $4.4 million is expected to be spent during 2013.  Total capital commitments exceed available working capital by $11.1 million at December 31, 2012, which includes interest costs and asset retirement obligations for the Beta Project.  In November 2012, the Fund entered into a credit agreement that provides for an aggregate loan commitment of up to $9.4 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  See Note 6. “Credit Agreement – Beta Project Financing,” for additional information.  The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

F-12

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, 2012 and 2011, there were no known environmental contingencies that required the Fund to record a liability.

Effective 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.  The 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.

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 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.

F-13

Ridgewood Energy W 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 located in Louisiana state waters and the waters of the Gulf of Mexico offshore from Louisiana on the Outer Continental Shelf.

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2012			2011
	(in thousands)
Unproved properties	$	-		$	2,087
Proved properties		22,706			22,248
Total oil and gas properties		22,706			24,335
Accumulated depletion and amortization		(14,320	)		(13,807	)
Oil and gas properties, net	$	8,386		$	10,528

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2012		2011
	(in thousands)
Exploration costs	$	1,144	$	857
Development costs		832		1,006
	$	1,976	$	1,863

F-14

Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2012 and Ryder Scott Company, L.P. at December 31, 2011.  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, 2012						December 31, 2011
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)
Proved developed and undeveloped reserves:
Beginning of year		221,785			3,625,979			294,552			3,458,370
Extensions and discoveries		410,394			307,795			3,639			747,466
Revisions of previous estimates (a)		73,063			397,225			92,117			699,846
Production		(128,567	)		(1,093,694	)		(168,523	)		(1,279,703	)
End of year		576,675			3,237,305			221,785			3,625,979
Proved developed reserves:
Beginning of year		215,855			2,795,979			290,543			2,897,245
End of year		158,590			1,815,830			215,855			2,795,979
Proved undeveloped reserves:
Beginning of year		5,930			830,000			4,009			561,125
End of year (b)		418,085			1,421,475			5,930			830,000

(a)  Revisions of estimates for the years ended December 31, 2012 and 2011 are attributable to well performance.

(b)  The increases in proved undeveloped reserves were due to discoveries relating to the Beta Project, coupled with revisions to estimates for the Raven Project, which were attributable to well performance.  The Fund will evaluate the development alternatives for the Raven’s Project’s proved undeveloped reserves during 2013.

F-15

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.  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,
	2012			2011
	(in thousands)
Future cash inflows	$	71,714		$	43,103
Future production costs		(6,453	)		(5,548	)
Future development costs		(21,285	)		(2,142	)
Future ad valorem taxes		(119	)		(50	)
Future net cash flows		43,857			35,363
10% annual discount for estimated timing of cash flows		(15,433	)		(4,982	)
Standardized measure of discounted future net cash flows	$	28,424		$	30,381

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	$	(3,234	)	$	10,414
Sales and transfers of oil and gas produced during the period		(15,681	)		(22,147	)
Net change due to extensions, discoveries, and improved recovery		10,092			2,870
Changes in estimated future development costs		83			4
Net change due to revisions in quantities estimates		7,311			8,208
Accretion of discount		3,038			2,946
Other		(3,566	)		(1,370	)
Aggregate change in the standardized measure of discounted  future net cash flows for the year	$	(1,957	)	$	925

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.

F-16

EX-31.1

 Exhibit 31.1

CERTIFICATION

I, Robert E. Swanson, certify that:

1. I have reviewed this Annual Report on Form 10-K of Ridgewood Energy W Fund, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f))  for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	February 26, 2013
/s/	ROBERT E. SWANSON
Name:	Robert E. Swanson
Title:	Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kathleen P. McSherry, certify that:

1.      I have reviewed this Annual Report on Form 10-K of Ridgewood Energy W Fund, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f))  for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	February 26, 2013
/s/	KATHLEEN P. MCSHERRY
Name:	Kathleen P. McSherry
Title:	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

EX-32

Exhibit 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Annual Report on Form 10-K of the Ridgewood Energy W Fund, LLC (the “Fund”) for the fiscal year ended December 31, 2012, as filed with the Securities and Exchange Commission on the date hereof, (the “Report”), each of the undersigned officers of the Fund hereby certifies, pursuant to 18 U.S.C. (section) 1350, as adopted pursuant to (section) 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Fund.

Dated:	February 26, 2013	/s/	ROBERT E. SWANSON
		Name:	Robert E. Swanson
		Title:	Chief Executive Officer
			(Principal Executive Officer)
Dated:	February 26, 2013	/s/	KATHLEEN P. MCSHERRY
		Name:	Kathleen P. McSherry
		Title:	Executive Vice President and Chief Financial Officer
			(Principal Financial and Accounting Officer)

A signed original of this written statement or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to the Fund and will be retained by the Fund and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this report or as a separate disclosure document.

EX-99.1

Exhibit 99.1

 

February 21, 2013

Mr. Harvey J. Dupuy, Jr.

Ridgewood Energy Corporation

1254 Enclave Parkway, Suite 600

Houston, Texas 77077

Dear Mr. Dupuy:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Ridgewood Energy W Fund, LLC (Ridgewood W Fund) interest in certain oil and gas properties located in state waters offshore Louisiana and federal waters in the Gulf of Mexico.  We completed our evaluation on or about the date of this letter.  It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Ridgewood W Fund.  The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.  Definitions are presented immediately following this letter.  This report has been prepared for Ridgewood W Fund's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Ridgewood W Fund interest in these properties, as of December 31, 2012, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	103.4	944.5	11,661.0	11,187.4
Proved Developed Non-Producing	55.2	871.3	7,852.0	5,899.7
Proved Undeveloped	418.1	1,421.5	24,344.5	11,337.0
Total Proved	576.7	3,237.3	43,857.4	28,424.2
Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate.  Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves.  As requested, probable and possible reserves that exist for these properties have not been included.  This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.  Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Ridgewood W Fund's share of the gross (100 percent) revenue from the properties prior to any deductions.  Future net revenue is after deductions for Ridgewood W Fund's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes.  The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money.  Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2012.  For oil volumes, the average Wall Street Journal West Texas Intermediate spot price of $94.71 per barrel is adjusted by field for quality, transportation fees, and regional price differentials.  For gas volumes, the average Henry Hub spot price of $2.757 per MMBTU is adjusted by field for energy content, transportation fees, and regional price differentials.  All prices are held constant throughout the lives of the properties.  The average adjusted product prices weighted by production over the remaining lives of the properties are $101.83 per barrel of oil and $4.012 per MCF of gas.

For existing developments, operating costs used in this report are based on operating expense records of Ridgewood Energy Corporation (Ridgewood Energy).  For new developments, we have estimated operating costs based on our knowledge of similar offshore properties.  Operating costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.  Since all properties are nonoperated, no headquarters general and administrative overhead expenses of Ridgewood Energy or Ridgewood W Fund are included.  Operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Ridgewood Energy and are based on authorizations for expenditure and actual costs from recent activity.  Capital costs are included as required for workovers, new development wells, and production equipment.  Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable.  Abandonment costs are Ridgewood Energy's estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value.  Capital costs and abandonment costs are held constant to the date of expenditure.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities.  We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Ridgewood W Fund interest.  Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Ridgewood W Fund receiving its net revenue interest share of estimated future gross gas production.

The reserves are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests.  The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.  A substantial portion of these reserves are for non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Ridgewood Energy, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate.  Supporting work data are on file in our office.  The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed.  The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
	/s/ C.H. (Scott) Rees III
By:
	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

	/s/ Lee E. George		/s/ Patrick L. Higgs		/s/ C. Ashley Smith
By:		By:		By:
	Lee E. George		Patrick L. Higgs		C. Ashley Smith
	Texas P.E. 95018		Texas P.G. 985		Louisiana P.E. 37102
	Vice President		Vice President		Vice President
Date Signed:  February 21, 2013		Date Signed:  February 21, 2013		Date Signed:  February 21, 2013

LEG:JLP

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by NSAI.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

Professional Qualifications of Primary Technical Person

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Lee George and Mr. Patrick Higgs.  Mr. George has been practicing consulting petroleum engineering at NSAI since 1997.  Mr. George is a Licensed Professional Engineer in the State of Texas (No. 95018) and has over 31 years of practical experience in petroleum engineering, with over 15 years’ experience in the estimation and evaluation of reserves.  He graduated from the University of Texas at Austin in 1981 with a Bachelor of Science Degree in Civil Engineering.  Mr. Higgs has been practicing consulting petroleum geology at NSAI since 1996.  Mr. Higgs is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 985) and has over 36 years of practical experience in petroleum geosciences, with over 16 years’ experience in the estimation and evaluation of reserves.  He graduated from Texas A&M University in 1976 with a Bachelor of Science Degree in Geophysics.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).  Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate.  The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.  Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.  Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons.  Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production.  In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.  More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project.  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property.  Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.  Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.  They become part of the cost of oil and gas produced.  Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities.  To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.  Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties.  Properties with proved reserves.

(24) Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30  A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31  All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows.  These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs.  These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.  If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses.  These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d. Future net cash flows.  These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

 Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

e. Discount.  This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows.  This amount is the future net cash flows less the computed discount.

(27) Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources.  Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.

(29) Service well.  A well drilled or completed for the purpose of supporting production in an existing field.  Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well.  A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition.  Such wells customarily are drilled without the intent of being completed for hydrocarbon production.  The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.  Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

Ÿ The company's historical record at completing development of comparable long-term projects;

Ÿ The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

Ÿ The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

Ÿ The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.  Properties with no proved reserves.

 Definitions - Page 6 of 6

XML

Information about Oil and Gas Producing Activities (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Information about Oil and Gas Producing Activities [Abstract]
Future cash inflows	$ 71,714	$ 43,103
Future production costs	(6,453)	(5,548)
Future development costs	(21,285)	(2,142)
Future ad valorem taxes	(119)	(50)
Future net cash flows	43,857	35,363
10% annual discount for estimated timing of cash flows	(15,433)	(4,982)
Standardized measure of discounted future net cash flows	$ 28,424	$ 30,381

XML

Oil and Gas Properties (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended				3 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Ajax Project [Member]	Dec. 31, 2011 Ajax Project [Member]	Mar. 31, 2011 West Cameron 57 Well [Member]
Impaired Assets to be Disposed of by Method Other than Sale [Line Items]
Liabilities settled/conveyed	$ (50)	$ (262)			$ 300
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on sale of oil and gas properties	$ 50	$ (25)	$ 50	$ (25)

XML

Oil and Gas Properties

12 Months Ended

Dec. 31, 2012

Oil and Gas Properties [Abstract]

Oil and Gas Properties

3. Oil and Gas Properties

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves. The following table reflects the net changes in unproved properties for the years ended December 31, 2012 and 2011.

	December 31,
	2012			2011
	(in thousands)
Balance - Beginning of year	$	2,087		$	1,791
Additions to capitalized exploratory well costs
pending the determination of proved reserves		-			1,093
Reclassifications to proved properties based on
the determination of proved reserves		(2,087	)		(797	)
Capitalized exploratory well costs charged to
expense		-			-
Balance - End of year	$	-		$	2,087

Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in West Cameron 57 to Marlin Coastal, L.L.C. ("Marlin"), the operator of the well, in exchange for Marlin's assumption of all future obligations and liabilities of the well. As a result of the conveyance, during the first quarter 2011, the Fund relieved the asset retirement obligation of $0.3 million that it had previously established for the well. Such amount was included in the statement of operations within "Depletion and amortization."

During the year ended December 31, 2012, the Fund recorded a gain on sale of oil and gas properties of $50 thousand as a result of the relief of its asset retirement obligations for the Ajax Project. During the year ended December 31, 2011, the Fund recorded a loss on sale of oil and gas properties of $25 thousand as a result of additional estimated costs related to asset retirement obligations for the Ajax Project.

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 adjustments on certain wells from their respective operators upon review and audit of the wells' costs. Dry-hole costs, inclusive of such credits, are detailed in the following table.

	Year ended December 31,
Project	2012			2011
	(in thousands)
Dakota Project	$	54		$	57
Other wells		(3	)		(15	)
	$	51		$	42

XML

Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Commitments and Contingencies [Abstract]
Commitments for the additional development of non-producing properties	$ 21.2
Commitments for the drilling and development of investment properties	21.3
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months	4.4
Commitments for the drilling and development of investment properties in excess of working capital	11.1
Credit agreement, maximum borrowing capacity	$ 9.4

XML

Credit Agreement - Beta Project Financing (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Credit Agreement - Beta Project Financing [Abstract]
Credit agreement, maximum borrowing capacity	$ 9.4
Credit agreement, interest rate	8.00%
Credit agreement, contingency repayment rate, first seven months of production	1.25%
Credit agreement, contingency repayment rate, after first seven months of production	4.50%
Credit agreement, maturity date	Dec. 31, 2020
Oil And Gas Properties Milestone [Line Items]
Collective maximum borrowing capacity	15.0
Deferred financing cost	0.7
Debt issuance expenses	$ 0.1
Milestone One [Member]
Oil And Gas Properties Milestone [Line Items]
Overriding royalty interest	12.24%
Maximum barrels of oil	780,000
Milestone Two [Member]
Oil And Gas Properties Milestone [Line Items]
Overriding royalty interest	8.16%
Maximum barrels of oil	1,210,000
Milestone Thereafter [Member]
Oil And Gas Properties Milestone [Line Items]
Overriding royalty interest	4.08%

XML

Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Information about Oil and Gas Producing Activities [Abstract]
Unproved properties		$ 2,087
Proved properties	22,706	22,248
Total oil and gas properties	22,706	24,335
Less: accumulated depletion and amortization	(14,320)	(13,807)
Total oil and gas properties, net	$ 8,386	$ 10,528

XML

Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Information about Oil and Gas Producing Activities [Abstract]
Exploration costs	$ 1,144	$ 857
Development costs	832	1,006
Total costs	$ 1,976	$ 1,863

XML

Derivative Instruments

12 Months Ended

Dec. 31, 2012

Derivative Instruments [Abstract]

Derivative Instruments

2. Derivative Instruments

The Fund periodically enters into derivative contracts relating to its oil or gas production. The use of such derivative instruments limits the downside risk of adverse price movements. The estimated fair value of such contracts is based upon various factors, including reported prices on NYMEX and ICE, volatility, and the time value of options. See Note 5. "Fair Value Measurements." The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.

At December 31, 2012, the Fund had no outstanding derivative contracts with respect to its future production. At December 31, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil that were not designated for hedge accounting as detailed in the following table.

Production Period	Type of Contract	Volume in barrels		ICE Contract Price per barrel		Estimated Fair Value Asset
						(in thousands)
January 1, 2012 - April 30, 2012	Put Options		12,571	$	105.00	$	61
January 1, 2012 - April 30, 2012	Put Options		5,966	$	112.00	$	52
January 1, 2012 - April 30, 2012	Put Options		5,966	$	100.00	$	18

For the years ended December 31, 2012 and 2011, the Fund's derivative instrument income consisted of the following:

	Year ended December 31,
	2012			2011
	(in thousands)
Realized losses on derivative instruments	$	(131	)	$	(293	)
Unrealized gains on derivative instruments		-			5
	$	(131	)	$	(288	)

XML

Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)	12 Months Ended
	Dec. 31, 2012 bbl		Dec. 31, 2011 bbl
Oil (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year	221,785		294,552
Extensions and discoveries	410,394		3,639
Revisions of previous estimates	73,063	[1]	92,117	[1]
Production	(128,567)		(168,523)
End of year	576,675		221,785
Proved developed reserves:
Beginning of year	215,855		290,543
End of year	158,590		215,855
Proved undeveloped reserves:
Beginning of year	5,930	[2]	4,009
End of year	418,085	[2]	5,930	[2]
Gas (MCF) [Member]
Proved developed and undeveloped reserves:
Beginning of year	3,625,979		3,458,370
Extensions and discoveries	307,795		747,466
Revisions of previous estimates	397,225	[1]	699,846	[1]
Production	(1,093,694)		(1,279,703)
End of year	3,237,305		3,625,979
Proved developed reserves:
Beginning of year	2,795,979		2,897,245
End of year	1,815,830		2,795,979
Proved undeveloped reserves:
Beginning of year	830,000	[2]	561,125
End of year	1,421,475	[2]	830,000	[2]

[1] Revisions of previous estimates during the years ended December 31, 2012 and 2011 were attributable to well performance.

[2] The increases in proved undeveloped reserves were due to discoveries relating to the Beta Project, coupled with revisions to estimates for the Raven Project, which were attributable to well performance. The Fund will evaluate the development alternatives for the Raven's Project's proved undeveloped reserves during 2013.

XML

BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 9,220	$ 5,635
Salvage fund	33
Short-term investments in marketable securities		5,001
Production receivable	1,640	2,045
Other current assets	162	253
Total current assets	11,055	12,934
Salvage fund	1,092	1,103
Other assets	697
Oil and gas properties:
Unproved properties		2,087
Proved properties	22,706	22,248
Less: accumulated depletion and amortization	(14,320)	(13,807)
Total oil and gas properties, net	8,386	10,528
Total assets	21,230	24,565
Current liabilities:
Due to operators	715	918
Accrued expenses	40	34
Asset retirement obligations	33
Total current liabilities	788	952
Asset retirement obligations	931	994
Total liabilities	1,719	1,946
Commitments and contingencies (Note 7)
Members' capital:
Distributions	(5,807)	(3,724)
Retained earnings	5,758	3,671
Manager's total	(49)	(53)
Capital contributions (625 shares authorized; 332.2918 shares issued and outstanding)	65,965	65,965
Syndication costs	(7,823)	(7,823)
Distributions	(34,544)	(22,742)
Accumulated deficit	(4,038)	(12,728)
Shareholders' total	19,560	22,672
Total members' capital	19,511	22,619
Total liabilities and members' capital	$ 21,230	$ 24,565

XML

STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities
Net income	$ 10,777	$ 12,865
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization	3,269	7,456
Dry-hole costs	51	42
Accretion expense	13	13
(Gain) loss on sale of oil and gas properties	(50)	25
Interest earned on marketable securities	(1)	(5)
Derivative instrument loss	131	288
Derivative instrument settlements	11	13
Debt acquisition costs	80
Changes in assets and liabilities:
Decrease in production receivable	405	389
Increase in other current assets	(51)	(454)
Decrease (increase) in due to operators	(145)	42
Increase (decrease) in accrued expenses	6	(92)
Net cash provided by operating activities	14,496	20,582
Cash flows from investing activities
Capital expenditures for oil and gas properties	(1,926)	(1,108)
Proceeds from maturity of investments	5,002	5,003
Investments in marketable securities		(4,999)
Interest reinvested in salvage fund	(22)	(20)
Net cash provided by (used in) investing activities	3,054	(1,124)
Cash flows from financing activities
Distributions	(13,885)	(18,060)
Debt acquisition costs	(80)
Net cash used in financing activities	(13,965)	(18,060)
Net increase in cash and cash equivalents	3,585	1,398
Cash and cash equivalents, beginning of year	5,635	4,237
Cash and cash equivalents, end of year	9,220	5,635
Supplemental schedule of non-cash operating activities
Adjustments to asset retirement obligations	50
Supplemental schedule of non-cash financing activities
Deferred financing charges related to the conveyance of overriding royalty interest in the Beta Project	$ 697

XML

Derivative Instruments (Schedule of Outstanding Derivative Contracts Not Designated For Hedge Accounting) (Details) (Put Options [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Contract One [Member]
Derivatives, Fair Value [Line Items]
Volume in barrels	12,571
ICE Contract Price per barrel	105.00
Estimated Fair Value Asset	61
Contract One [Member] | Minimum [Member]
Derivatives, Fair Value [Line Items]
Production Period	Jan. 01, 2012
Contract One [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Production Period	Apr. 30, 2012
Contract Two [Member]
Derivatives, Fair Value [Line Items]
Volume in barrels	5,966
ICE Contract Price per barrel	112.00
Estimated Fair Value Asset	52
Contract Two [Member] | Minimum [Member]
Derivatives, Fair Value [Line Items]
Production Period	Jan. 01, 2012
Contract Two [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Production Period	Apr. 30, 2012
Contract Three [Member]
Derivatives, Fair Value [Line Items]
Volume in barrels	5,966
ICE Contract Price per barrel	100.00
Estimated Fair Value Asset	18
Contract Three [Member] | Minimum [Member]
Derivatives, Fair Value [Line Items]
Production Period	Jan. 01, 2012
Contract Three [Member] | Maximum [Member]
Derivatives, Fair Value [Line Items]
Production Period	Apr. 30, 2012

XML

Oil and Gas Properties (Schedule of Net Changes in Unproved Oil and Gas Properties) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Properties [Abstract]
Balance - Beginning of year	$ 2,087	$ 1,791
Additions to capitalized exploratory well costs pending the determination of proved reserves		1,093
Reclassifications to proved properties based on the determination of proved reserves	(2,087)	(797)
Capitalized exploratory well costs charged to expense
Balance - End of year		$ 2,087

XML

Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Organization and Summary of Significant Accounting Policies [Abstract]

Organization and Summary of Significant Accounting Policies

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy W Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on May 17, 2007 and operates pursuant to a limited liability company agreement (the "LLC Agreement") dated as of June 15, 2007 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 4, 6 and 7.

Use of Estimates

The preparation of financial statements in 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 the fair value of financial instruments, 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, 2013, the federally insured limits of the Fund's deposits are $250 thousand per insured financial institution. Based upon these limits, at December 31, 2012, the Fund's bank balances exceeded federally insured limits by $9.4 million, of which $0.4 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Investments in Marketable Securities

At times, the Fund may invest in U.S. Treasury bills and notes. These investments are considered short-term when their maturities are one year or less, and long-term when their maturities are greater than one year. For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. At December 31, 2011, the Fund's investments in marketable securities were classified as held-to-maturity. 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.

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, 2012, the Fund had investments in federal agency mortgage-backed securities within its salvage fund of $0.7 million, which mature in January 2042, that are classified as available-for-sale. Available-for-sale securities are carried in the financial statements at fair value. At December 31, 2012, there was no unrealized gain or loss related to the Fund's available-for-sale investments. At December 31, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $0.9 million. The Fund had no investments in available-for-sale securities at December 31, 2011. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

Debt Discounts and Deferred Financing Costs

Debt discounts and deferred financing costs include lender fees and other costs of the credit agreement such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within "Other assets". At December 31, 2012, $0.7 million of debt discounts and deferred financing costs remained unamortized. There was no amortization expense during the years ended December 31, 2012 and 2011.

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, 2012 and 2011, amounts recorded in due to operators totaling $0.4 million and $0.5 million, 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, 2012 and 2011.

	2012			2011
	(in thousands)
Balance - Beginning of year	$	994		$	905
Liabilities incurred		20			42
Liabilities settled/conveyed		(50	)		(262	)
Accretion expense		13			13
Revisions in estimated cash flows		(13	)		296
Balance - End of year	$	964		$	994

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 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.

Derivative Instruments

The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production. Derivative instruments are carried on the balance sheet at fair value and recorded as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met. At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as other income on the statement of operations. The estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange ("NYMEX") and the Intercontinental Exchange ("ICE"), volatility, and the time value of options. The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows. The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions. See Note 2. "Derivative Instruments".

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 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.

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 to shareholders and the Manager in accordance with the 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.

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.

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BALANCE SHEETS (Parenthetical)	Dec. 31, 2012	Dec. 31, 2011
BALANCE SHEETS [Abstract]
Shares authorized	625	625
Shares issued	332.2918	332.2918
Shares outstanding	332.2918	332.2918

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments [Abstract]

Schedule of Outstanding Derivative Contracts Not Designated for Hedge Accounting

Production Period	Type of Contract	Volume in barrels		ICE Contract Price per barrel		Estimated Fair Value Asset
						(in thousands)
January 1, 2012 - April 30, 2012	Put Options		12,571	$	105.00	$	61
January 1, 2012 - April 30, 2012	Put Options		5,966	$	112.00	$	52
January 1, 2012 - April 30, 2012	Put Options		5,966	$	100.00	$	18

Schedule of Derivative Instrument Income

	Year ended December 31,
	2012			2011
	(in thousands)
Realized losses on derivative instruments	$	(131	)	$	(293	)
Unrealized gains on derivative instruments		-			5
	$	(131	)	$	(288	)

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Document and Entity Information (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Feb. 26, 2013
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Entity Registrant Name	Ridgewood Energy W Fund LLC
Entity Central Index Key	0001409947
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2012
Entity Filer Category	Smaller Reporting Company
Entity Units Outstanding		332.2918
Entity Public Float	$ 0
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes

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Oil And Gas Properties (Tables)

12 Months Ended

Dec. 31, 2012

Oil and Gas Properties [Abstract]

Schedule of Net Changes in Unproved Oil and Gas Properties

	December 31,
	2012			2011
	(in thousands)
Balance - Beginning of year	$	2,087		$	1,791
Additions to capitalized exploratory well costs
pending the determination of proved reserves		-			1,093
Reclassifications to proved properties based on
the determination of proved reserves		(2,087	)		(797	)
Capitalized exploratory well costs charged to
expense		-			-
Balance - End of year	$	-		$	2,087

Schedule Of Dry-hole Costs Inclusive of Credits

	Year ended December 31,
Project	2012			2011
	(in thousands)
Dakota Project	$	54		$	57
Other wells		(3	)		(15	)
	$	51		$	42

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STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Revenue
Oil and gas revenue	$ 17,144	$ 23,966
Expenses
Depletion and amortization	3,269	7,456
Dry-hole costs	51	42
Management fees to affiliate (Note 4)	1,066	1,151
Operating expenses	1,598	1,858
General and administrative expenses	326	308
Total expenses	6,310	10,815
Gain (loss) on sale of oil and gas properties	50	(25)
Income from operations	10,884	13,126
Other loss	(107)	(261)
Net income	10,777	12,865
Manager Interest
Net income	2,087	2,983
Shareholder Interest
Net income	$ 8,690	$ 9,882
Net income per share	$ 26,150	$ 29,740

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Credit Agreement - Beta Project Financing

12 Months Ended

Dec. 31, 2012

Credit Agreement - Beta Project Financing [Abstract]

Credit Agreement - Beta Project Financing

6. Credit Agreement - Beta Project Financing

In November 2012, the Fund, entered into a credit agreement (the "Credit Agreement") with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively "Lenders") that provides for an aggregate loan commitment to the Fund of approximately $9.4 million ("Loan"), to provide capital toward the funding of the Fund's share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund's other assets and secured solely by the Fund's interests in the Beta Project. In addition to the Fund's execution of the Credit Agreement, Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy A-1 Fund, LLC and Ridgewood Energy B-1 Fund, LLC ("Ridgewood Funds", and when used with the Fund the "Ridgewood Participating Funds") have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds' borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Fund. The Manager serves as the manager for each Ridgewood Participating Fund.

As of December 31, 2012, the Fund had no borrowings under the Credit Agreement.

The Fund anticipates it will borrow approximately $9.4 million over the development period of the Beta Project, which will bear interest at 8% compounded annually and accrue only on Loan proceeds as they are drawn. Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected to occur in 2016. At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund's total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund's total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020. The Loan may be prepaid by the Fund without premium or penalty.

As additional consideration to the Lenders, each Ridgewood Participating Fund has agreed to convey an overriding royalty interest ("ORRI") to the Lenders in their working interests in the Beta Project. Each Ridgewood Participating Fund's share of the Lender's aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Using these principles, the Fund's percentage ORRI to be granted to the Lenders equals 12.24% of the Fund's production until the Fund's share of Beta Project's cumulative production equals approximately 0.78 million barrels of oil ("MMBO"), net of royalties. Upon reaching that milestone, the Fund's ORRI percentage decreases to 8.16% of the Fund's production until the Fund's share of the Beta Project's cumulative production equals approximately 1.21 MMBO, net of royalties, whereupon it decreases to, and remains at, 4.08% of the Fund's net production. The Ridgewood Funds can collectively borrow up to $15.0 million prior to the satisfaction or waiver of certain administrative conditions precedent. The Fund recorded the additional consideration as debt discounts and deferred financing costs at a fair value of $0.7 million, which will be amortized to interest expense over the expected payoff period of the loan. The fair value of the ORRI was determined using net discounted cash flows from the Beta Project related to the ORRI based on level 3 inputs, which include projected net income from reserves and forward pricing curves. The outstanding debt discounts and deferred financing costs recorded on the balance sheet within "Other assets" is $0.7 million.

The Credit Agreement contains customary covenants, for which the Fund believes it is in compliance at December 31, 2012.

The expenses related to the securing of the Credit Agreement were borne by the Ridgewood Participating Funds. The Fund's portion of such expenses was $0.1 million.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements

5. 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, 2012 and 2011, cash and cash equivalents and short-term investments in marketable securities approximate fair value based on Level 1 inputs. At December 31, 2012, the fair value of the Fund's mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets. At December 31, 2011, derivative instruments were recorded at fair value based on Level 2 inputs, as the instruments are over-the-counter derivatives with a third party.

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Derivative Instruments (Schedule of Derivative Instrument Income) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments [Abstract]
Realized losses on derivative instruments	$ (131)	$ (293)
Unrealized gains on derivative instruments		5
Derivative instrument income (loss)	$ (131)	$ (288)

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Information about Oil and Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2012

Information about Oil and Gas Producing Activities [Abstract]

Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2012			2011
	(in thousands)
Unproved properties	$	-		$	2,087
Proved properties		22,706			22,248
Total oil and gas properties		22,706			24,335
Accumulated depletion and amortization		(14,320	)		(13,807	)
Oil and gas properties, net	$	8,386		$	10,528

Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2012		2011
	(in thousands)
Exploration costs	$	1,144	$	857
Development costs		832		1,006
	$	1,976	$	1,863

Schedule of Reserve Quantity Information

	December 31, 2012						December 31, 2011
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)
Proved developed and undeveloped reserves:
Beginning of year		221,785			3,625,979			294,552			3,458,370
Extensions and discoveries		410,394			307,795			3,639			747,466
Revisions of previous estimates (a)		73,063			397,225			92,117			699,846
Production		(128,567	)		(1,093,694	)		(168,523	)		(1,279,703	)
End of year		576,675			3,237,305			221,785			3,625,979
Proved developed reserves:
Beginning of year		215,855			2,795,979			290,543			2,897,245
End of year		158,590			1,815,830			215,855			2,795,979
Proved undeveloped reserves:
Beginning of year		5,930			830,000			4,009			561,125
End of year (b)		418,085			1,421,475			5,930			830,000

(a) Revisions of estimates for the years ended December 31, 2012 and 2011 are attributable to well performance.

(b) The increases in proved undeveloped reserves were due to discoveries relating to the Beta Project, coupled with revisions to estimates for the Raven Project, which were attributable to well performance. The Fund will evaluate the development alternatives for the Raven's Project's proved undeveloped reserves during 2013.

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	December 31,
	2012			2011
	(in thousands)
Future cash inflows	$	71,714		$	43,103
Future production costs		(6,453	)		(5,548	)
Future development costs		(21,285	)		(2,142	)
Future ad valorem taxes		(119	)		(50	)
Future net cash flows		43,857			35,363
10% annual discount for estimated timing of cash flows		(15,433	)		(4,982	)
Standardized measure of discounted future net cash flows	$	28,424		$	30,381

Schedule of Changes in the Standardized Measure for Discounted Cash Flows

	Year ended December 31,
	2012			2011
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	(3,234	)	$	10,414
Sales and transfers of oil and gas produced during the period		(15,681	)		(22,147	)
Net change due to extensions, discoveries, and improved recovery		10,092			2,870
Changes in estimated future development costs		83			4
Net change due to revisions in quantities estimates		7,311			8,208
Accretion of discount		3,038			2,946
Other		(3,566	)		(1,370	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(1,957	)	$	925

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Organization and Summary of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Organization and Summary of Significant Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

The preparation of financial statements in 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 the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.

Cash and Cash Equivalents

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, 2013, the federally insured limits of the Fund's deposits are $250 thousand per insured financial institution. Based upon these limits, at December 31, 2012, the Fund's bank balances exceeded federally insured limits by $9.4 million, of which $0.4 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Investments in Marketable Securities

Investments in Marketable Securities

At times, the Fund may invest in U.S. Treasury bills and notes. These investments are considered short-term when their maturities are one year or less, and long-term when their maturities are greater than one year. For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. At December 31, 2011, the Fund's investments in marketable securities were classified as held-to-maturity. 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.

Salvage Fund

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, 2012, the Fund had investments in federal agency mortgage-backed securities within its salvage fund of $0.7 million, which mature in January 2042, that are classified as available-for-sale. Available-for-sale securities are carried in the financial statements at fair value. At December 31, 2012, there was no unrealized gain or loss related to the Fund's available-for-sale investments. At December 31, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $0.9 million. The Fund had no investments in available-for-sale securities at December 31, 2011. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

Debt Discounts and Deferred Financing Costs

Debt Discounts and Deferred Financing Costs

Debt discounts and deferred financing costs include lender fees and other costs of the credit agreement such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within "Other assets". At December 31, 2012, $0.7 million of debt discounts and deferred financing costs remained unamortized. There was no amortization expense during the years ended December 31, 2012 and 2011.

Oil and Gas Properties

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, 2012 and 2011, amounts recorded in due to operators totaling $0.4 million and $0.5 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

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

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, 2012 and 2011.

	2012			2011
	(in thousands)
Balance - Beginning of year	$	994		$	905
Liabilities incurred		20			42
Liabilities settled/conveyed		(50	)		(262	)
Accretion expense		13			13
Revisions in estimated cash flows		(13	)		296
Balance - End of year	$	964		$	994

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

Syndication Costs

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

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 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.

Derivative Instruments

Derivative Instruments

The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production. Derivative instruments are carried on the balance sheet at fair value and recorded as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met. At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as other income on the statement of operations. The estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange ("NYMEX") and the Intercontinental Exchange ("ICE"), volatility, and the time value of options. The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows. The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions. See Note 2. "Derivative Instruments".

Impairment of Long-Lived Assets

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 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.

Depletion and Amortization

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

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

Income and Expense Allocation

Profits and losses are allocated to shareholders and the Manager in accordance with the LLC agreement.

Distributions

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.

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

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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

Commitments and Contingencies

7. Commitments and Contingencies

Capital Commitments

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 has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $21.2 million related to the development of this project, which the Fund anticipates will include a four-well development with related platform and pipeline infrastructure. It is also possible that full development of the Beta Project will entail the drilling of additional wells beyond the four projected wells, the cost of which is not included in the above estimates.

As of December 31, 2012, the Fund expects to spend an additional $21.3 million related to its investments in oil and gas properties, inclusive of $21.2 million to develop the Beta Project, of which $4.4 million is expected to be spent during 2013. Total capital commitments exceed available working capital by $11.1 million at December 31, 2012, which includes interest costs and asset retirement obligations for the Beta Project. In November 2012, the Fund entered into a credit agreement that provides for an aggregate loan commitment of up to $9.4 million to provide capital toward the funding of the Fund's share of development costs on the Beta Project. See Note 6. "Credit Agreement - Beta Project Financing," for additional information. The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

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, 2012 and 2011, there were no known environmental contingencies that required the Fund to record a liability.

Effective 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. The 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.

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 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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Information about Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2012

Information about Oil and Gas Producing Activities [Abstract]

Information about Oil and Gas Producing Activities

Ridgewood Energy W Fund, LLC

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 located in Louisiana state waters and the waters of the Gulf of Mexico offshore from Louisiana on the Outer Continental Shelf.

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2012			2011
	(in thousands)
Unproved properties	$	-		$	2,087
Proved properties		22,706			22,248
Total oil and gas properties		22,706			24,335
Accumulated depletion and amortization		(14,320	)		(13,807	)
Oil and gas properties, net	$	8,386		$	10,528

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2012		2011
	(in thousands)
Exploration costs	$	1,144	$	857
Development costs		832		1,006
	$	1,976	$	1,863

Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2012 and Ryder Scott Company, L.P. at December 31, 2011. 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, 2012						December 31, 2011
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)
Proved developed and undeveloped reserves:
Beginning of year		221,785			3,625,979			294,552			3,458,370
Extensions and discoveries		410,394			307,795			3,639			747,466
Revisions of previous estimates (a)		73,063			397,225			92,117			699,846
Production		(128,567	)		(1,093,694	)		(168,523	)		(1,279,703	)
End of year		576,675			3,237,305			221,785			3,625,979
Proved developed reserves:
Beginning of year		215,855			2,795,979			290,543			2,897,245
End of year		158,590			1,815,830			215,855			2,795,979
Proved undeveloped reserves:
Beginning of year		5,930			830,000			4,009			561,125
End of year (b)		418,085			1,421,475			5,930			830,000

(a) Revisions of estimates for the years ended December 31, 2012 and 2011 are attributable to well performance.

(b) The increases in proved undeveloped reserves were due to discoveries relating to the Beta Project, coupled with revisions to estimates for the Raven Project, which were attributable to well performance. The Fund will evaluate the development alternatives for the Raven's Project's proved undeveloped reserves during 2013.

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. 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,
	2012			2011
	(in thousands)
Future cash inflows	$	71,714		$	43,103
Future production costs		(6,453	)		(5,548	)
Future development costs		(21,285	)		(2,142	)
Future ad valorem taxes		(119	)		(50	)
Future net cash flows		43,857			35,363
10% annual discount for estimated timing of cash flows		(15,433	)		(4,982	)
Standardized measure of discounted future net cash flows	$	28,424		$	30,381

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	$	(3,234	)	$	10,414
Sales and transfers of oil and gas produced during the period		(15,681	)		(22,147	)
Net change due to extensions, discoveries, and improved recovery		10,092			2,870
Changes in estimated future development costs		83			4
Net change due to revisions in quantities estimates		7,311			8,208
Accretion of discount		3,038			2,946
Other		(3,566	)		(1,370	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(1,957	)	$	925

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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Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Organization and Summary of Significant Accounting Policies [Abstract]

Schedule of Changes in Asset Retirement Obligations

	2012			2011
	(in thousands)
Balance - Beginning of year	$	994		$	905
Liabilities incurred		20			42
Liabilities settled/conveyed		(50	)		(262	)
Accretion expense		13			13
Revisions in estimated cash flows		(13	)		296
Balance - End of year	$	964		$	994

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Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Information about Oil and Gas Producing Activities [Abstract]
Net change in sales and transfer prices and in production costs related to future production	$ (3,234)	$ 10,414
Sales and transfers of oil and gas produced during the period	(15,681)	(22,147)
Net change due to extensions, discoveries, and improved recovery	10,092	2,870
Changes in estimated future development costs	83	4
Net change due to revisions in quantities estimates	7,311	8,208
Accretion of discount	3,038	2,946
Other	(3,566)	(1,370)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$ (1,957)	$ 925

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Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Organization and Summary of Significant Accounting Policies [Abstract]
Balance - Beginning of year	$ 994	$ 905
Liabilities incurred	20	42
Liabilities settled/conveyed	(50)	(262)
Accretion expense	13	13
Revisions in estimated cash flows	(13)	296
Balance - End of year	$ 964	$ 994

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Oil and Gas Properties (Schedule of Dry-hole Costs Inclusive of Credits) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Dry-hole costs	$ 51	$ 42
Dakota Project [Member]
Dry-hole costs	54	57
Other Wells [Member]
Dry-hole costs	$ (3)	$ (15)

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STATEMENTS OF CHANGES IN MEMBERS' CAPITAL (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Balance	$ 22,619	$ 27,814
Balances, shares	332.2918	332.2918
Distributions	(13,885)	(18,060)
Net income	10,777	12,865
Balance	19,511	22,619
Balances, shares	332.2918	332.2918
# of Shares [Member]
Balances, shares	332.2918	332.2918
Distributions
Net income
Balances, shares	332.2918	332.2918
Manager [Member]
Balance	(53)	(327)
Distributions	(2,083)	(2,709)
Net income	2,087	2,983
Balance	(49)	(53)
Shareholders [Member]
Balance	22,672	28,141
Distributions	(11,802)	(15,351)
Net income	8,690	9,882
Balance	$ 19,560	$ 22,672

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Related Parties

12 Months Ended

Dec. 31, 2012

Related Parties [Abstract]

Related Parties

4. Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for the years ended December 31, 2012 and 2011 were $1.1 million and $1.2 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager for the years ended December 31, 2012 and 2011 were $2.1 million and $2.7 million, respectively.

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.

In November 2012, the Fund entered into a credit agreement along with other entities managed by the Manager. See Note 6. "Credit Agreement - Beta Project Financing," for additional information.

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Related Parties (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Annual management fee percentage rate	2.50%
Annual management fees paid to Fund Manager	$ 1,066	$ 1,151
Percentage of total distributions allocated to Fund Manager	15.00%
Distributions	(13,885)	(18,060)
Fund Manager [Member]
Related Party Transaction [Line Items]
Distributions	$ (2,083)	$ (2,709)

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Organization and Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Organization and Summary of Significant Accounting Policies [Abstract]
Maximum cash balance federally insured per financial institution	$ 250,000
Cash and Cash Equivalents [Line Items]
Total cash balance not insured by the FDIC	9,400,000
Value of available-for-sale securities included in salvage fund	700,000
Value of held-to-maturity securities included in salvage fund		900,000
Available-for-sale securities included in salvage fund maturity date	Jan. 01, 2042
Unamortized debt discounts and deferred financing costs	700,000
Value of capital expenditures for oil and gas properties owed to operators	400,000	500,000
Percentage of cash from operations allocated to shareholders	85.00%
Percentage of cash from operations allocated to fund manager	15.00%
Percentage of available cash from dispositions allocated to shareholders	99.00%
Percentage of available cash from dispositions allocated to fund manager	1.00%
Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions	85.00%
Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions	15.00%
Money Market Funds [Member]
Cash and Cash Equivalents [Line Items]
Total cash balance not insured by the FDIC	$ 400,000