UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934     For the quarterly period ended September 30, 2013

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 (State or other jurisdiction of incorporation or organization) 26-0225130 (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)

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

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

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

As of November 5, 2013 the Fund had 332.2918 shares of LLC Membership Interest outstanding.

Table of Contents

			PAGE
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements		1
		Unaudited Condensed Balance Sheets as of September 30, 2013 and December 31, 2012	1
		Unaudited Condensed Statements of Operations for the three and nine months ended September 30, 2013 and 2012	2
		Unaudited Condensed Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	3
		Notes to Unaudited Condensed Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		15
Item 4.	Controls and Procedures		15
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		16
Item 1A.	Risk Factors		16
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		16
Item 3.	Defaults Upon Senior Securities		16
Item 4.	Mine Safety Disclosures		16
Item 5.	Other Information		16
Item 6.	Exhibits		17
	SIGNATURES		17

PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

RIDGEWOOD ENERGY W FUND, LLC

UNAUDITED CONDENSED BALANCE SHEETS

(in thousands, except share data)

	September 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	9,829		$	9,220
Salvage fund		90			33
Production receivable		447			1,640
Other current assets		140			162
Total current assets		10,506			11,055
Salvage fund		1,048			1,092
Other assets		592			697
Oil and gas properties:
Proved properties		23,763			22,706
Less:  accumulated depletion and amortization		(15,633	)		(14,320	)
Total oil and gas properties, net		8,130			8,386
Total assets	$	20,276		$	21,230
Liabilities and Members' Capital
Current liabilities:
Due to operators	$	623		$	715
Accrued expenses		35			40
Asset retirement obligations		90			33
Total current liabilities		748			788
Asset retirement obligations		931			931
Total liabilities		1,679			1,719
Commitments and contingencies (Note 6)
Members' capital:
Manager:
Distributions		(6,641	)		(5,807	)
Retained earnings		6,649			5,758
Manager's total		8			(49	)
Shareholders:
Capital contributions (625 shares authorized;
332.2918 issued and outstanding)		65,965			65,965
Syndication costs		(7,823	)		(7,823	)
Distributions		(39,274	)		(34,544	)
Accumulated deficit		(279	)		(4,038	)
Shareholders' total		18,589			19,560
Total members' capital		18,597			19,511
Total liabilities and members' capital	$	20,276		$	21,230

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

1

RIDGEWOOD ENERGY W FUND, LLC

UNAUDITED CONDENSED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Revenue
Oil and gas revenue	$	2,042	$	3,775	$	8,104	$	13,016
Expenses
Depletion and amortization		379		838		1,369		2,623
Management fees to affiliate (Note 4)		258		257		774		808
Operating expenses		313		360		1,120		1,308
General and administrative expenses		55		79		204		197
Total expenses		1,005		1,534		3,467		4,936
Gain on sale of oil and gas properties		-		50		-		50
Income from operations		1,037		2,291		4,637		8,130
Other income (loss)		4		7		13		(114	)
Net income	$	1,041	$	2,298	$	4,650	$	8,016
Manager Interest
Net income	$	210	$	457	$	891	$	1,580
Shareholder Interest
Net income	$	831	$	1,841	$	3,759	$	6,436
Net income per share	$	2,500	$	5,543	$	11,313	$	19,368

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

2

RIDGEWOOD ENERGY W FUND, LLC

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine months ended September 30,
	2013			2012
Cash flows from operating activities
Net income	$	4,650		$	8,016
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion and amortization		1,369			2,623
Gain on sale of oil and gas properties		-			(50	)
Derivative instrument loss		-			131
Derivative instrument settlements		-			11
Changes in assets and liabilities:
Decrease in production receivable		1,193			565
Increase in other current assets		(15	)		(40	)
Decrease in due to operators		(98	)		(159	)
(Decrease) increase in accrued expenses		(5	)		68
Net cash provided by operating activities		7,094			11,165
Cash flows from investing activities
Capital expenditures for oil and gas properties		(908	)		(1,777	)
Proceeds from maturity of investments		-			5,002
Interest reinvested in salvage fund		(13	)		(16	)
Net cash (used in) provided by investing activities		(921	)		3,209
Cash flows from financing activities
Distributions		(5,564	)		(11,388	)
Net cash used in financing activities		(5,564	)		(11,388	)
Net increase in cash and cash equivalents		609			2,986
Cash and cash equivalents, beginning of period		9,220			5,635
Cash and cash equivalents, end of period	$	9,829		$	8,621
Supplemental schedule of non-cash operating activities
Adjustments to asset retirement obligations	$	-		$	50

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

3

RIDGEWOOD ENERGY W FUND, LLC

NOTES TO UNAUDITED CONDENSED 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, 5 and 6.

Basis of Presentation

These unaudited interim condensed financial statements have been prepared by the Fund’s management in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Fund’s financial position, results of operations and cash flows for the periods presented.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted in these unaudited interim condensed financial statements.  The results of operations, financial position, and cash flows for the periods presented herein are not necessarily indicative of future financial results.  These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2012 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”).  The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Use of Estimates

The preparation of financial statements in accordance with 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.

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. Cash and cash equivalents approximate fair value based on Level 1 inputs.  Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.

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, which are $250 thousand per insured financial institution.  At September 30, 2013, the Fund’s bank balances exceeded federally insured limits by $10.6 million, of which $0.9 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

4

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 September 30, 2013 and December 31, 2012, the Fund had investments in federal agency mortgage-backed securities within its salvage fund that are classified as available-for-sale of $0.3 million and $0.7 million, respectively, which mature in January 2042.  Available-for-sale securities are carried in the financial statements at fair value.  At September 30, 2013 and December 31, 2012, the fair market value approximated the Fund’s carrying value, therefore there was no unrealized gain or loss related to the Fund’s available-for-sale investments.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  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 September 30, 2013 and December 31, 2012, $0.6 million and $0.7 million, respectively, of debt discounts and deferred financing costs were unamortized.  Amortization expense was $35 thousand and $0.1 million during the three and nine months ended September 30, 2013, respectively.  There was no amortization expense during the three and nine months ended September 30, 2012.  During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “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, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.

At September 30, 2013 and December 31, 2012, amounts recorded in due to operators totaling $0.4 million 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. As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

5

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.

6

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.

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.  The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.

The Fund had no derivative contracts during the three and nine months ended September 30, 2013 and during the three months ended September 30, 2012.  For the nine months ended September 30, 2012, the Fund’s derivative instrument income consisted of realized losses of $0.1 million.

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.

During the three and nine months ended September 30, 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.  There were no such amounts recorded during the three and nine months ended September 30, 2013.

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 to certain wells from their respective operators upon review and audit of the wells’ costs.

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 each of the three months ended September 30, 2013 and 2012 were $0.3 million.  Management fees for each of the nine months ended September 30, 2013 and 2012 were $0.8 million.

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 three and nine months ended September 30, 2013 were $0.1 million and $0.8 million, respectively.  Distributions paid to the Manager for the three and nine months ended September 30, 2012 were $0.5 million and $1.7 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.

7

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.

5.           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.

As of September 30, 2013, 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, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interests in the Beta Project to the Lenders.  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.  At September 30, 2013 and December 31, 2012, the outstanding debt discounts and deferred financing costs recorded on the balance sheet within “Other assets” were $0.6 million and $0.7 million, respectively.

The Credit Agreement contains customary covenants, for which the Fund believes it is in compliance at September 30, 2013.

6.           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.  Currently, 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 anticipates such development 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 below estimates.

As of September 30, 2013, the Fund expects to spend an additional $21.2 million related to its investments in oil and gas properties, inclusive of $21.0 million to develop the Beta Project, of which $5.0 million is expected to be spent during the next twelve months.  Total capital commitments exceed available working capital by $11.4 million at September 30, 2013, which includes projected 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 5. “Credit Agreement – Beta Project Financing,” for additional information.  The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

8

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 September 30, 2013 and December 31, 2012, 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.

9

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy W Fund, LLC (the “Fund”) has incorporated by reference into this Quarterly 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.

Critical Accounting Policies and Estimates

The following discussion and analysis of the Fund’s financial condition and operating results is based on its financial statements. The preparation of this Quarterly Report requires the Fund to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of the Fund’s financial statements, and the reported amount of revenue and expense during the reporting period. Actual results may differ from those estimates and assumptions.  See “Notes to Unaudited Condensed Financial Statements” in Part I of this Quarterly Report for a presentation of the Fund’s significant accounting policies. No changes have been made to the Fund’s critical accounting policies and estimates disclosed in its 2012 Annual Report on Form 10-K.

Overview of the Fund’s Business

The Fund is a Delaware limited liability company 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’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 Fund’s limited liability company agreement (the “LLC Agreement”).

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) is the Manager, and as such, has direct and exclusive control over the management of the Fund’s operations.  The Manager performs certain duties on the Fund’s behalf including the evaluation of projects, including ongoing management, administrative and advisory services.  For these services, the Manager receives an annual management fee equal to 2.5% of capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, payable monthly.  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.  The Manager also participates in distributions.

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 an adverse effect on the Fund’s future profitability.

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Business Update

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

		Total Spent
	Working	through		Total Fund
Project	Interest	September 30, 2013		Budget		Status
		(in thousands)
Non-producing Properties
Beta Project	3.0%	$	4,993	$	26,039	Well deemed to be a discovery in February 2012. Expected to commence production in 2016.
Producing Properties
Cobalt Project	5.0%	$	2,368	$	2,398	Production commenced in 2009.   Production rate has decreased, however, zone continues to be economic.  A recompletion is currently being evaluated for 2014 and an additional recompletion is expected in 2015 at an estimated total cost of $30 thousand.
Liberty Project	12.0%	$	13,409	$	13,529	Production commenced in 2010. Well was shut-in for several weeks during the first and third quarters of 2013 due to repairs and maintenance and storm activity.  Recompletion is planned for 2014 at an estimated cost of  $120 thousand.
Raven Project well #1	6.25%	$	1,627	$	1,627	Production commenced in 2010.  Well is currently not producing, awaiting redirection to new production facility, which is expected in December 2013.
Raven Project well #2	6.25%	$	1,091	$	1,091	Production commenced in 2011.
Fully Depleted Properties
Main Pass 283/279 well #1	9.0%	$	2,713	$	2,713	Production commenced in 2008.  The Fund is in the process of withdrawing its interest in the project.

Results of Operations

The following table summarizes the Fund’s results of operations for the three and nine months ended September 30, 2013 and 2012, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1.  “Financial Statements” in Part I in this Quarterly Report.

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	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(in thousands)
Revenue
Oil and gas revenue	$	2,042	$	3,775	$	8,104	$	13,016
Expenses
Depletion and amortization		379		838		1,369		2,623
Management fees to affiliate		258		257		774		808
Operating expenses		313		360		1,120		1,308
General and administrative expenses		55		79		204		197
Total expenses		1,005		1,534		3,467		4,936
Gain on sale of oil and gas properties		-		50		-		50
Income from operations		1,037		2,291		4,637		8,130
Other income (loss)		4		7		13		(114	)
Net income	$	1,041	$	2,298	$	4,650	$	8,016

Overview.  The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the three and nine months ended September 30, 2013 and 2012.

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Number of wells producing		3		4		4		5
Total number of production days		266		320		873		1,076
Oil sales (in thousands of barrels)		13		29		56		97
Average oil price per barrel	$	108	$	102	$	108	$	107
Gas sales (in thousands of mcfs)		155		206		540		709
Average gas price per mcf	$	3.84	$	2.98	$	3.96	$	2.48

The decreases in number of production days and sales volumes during the three months ended September 30, 2013 were primarily attributable to the Raven well #1 and Liberty projects, which were periodically shut-in during the third quarter 2013.  The decreases in the number of production days and sales volumes for the nine months ended September 30, 2013 were attributable to the Raven well #1 and Liberty projects, which were periodically shut-in during 2013, natural declines in well production and the full depletion of Main Pass 283/279 well #1 in 2012.   See additional discussion in “Business Update” section above.

Oil and Gas Revenue.  Oil and gas revenue for the three months ended September 30, 2013 was $2.0 million, a $1.7 million decrease from the three months ended September 30, 2012.  The decrease is attributable to decreased sales volumes totaling $1.8 million, partially offset by the impact of increased average prices totaling $0.2 million.  Oil and gas revenue for the nine months ended September 30, 2013 was $8.1 million, a $4.9 million decrease from the nine months ended September 30, 2012.  The decrease is attributable to decreased sales volumes totaling $5.4 million, partially offset by the impact of increased average prices totaling $0.5 million.  See “Overview” above for additional information.

Depletion and Amortization.  Depletion and amortization for the three months ended September 30, 2013 was $0.4 million, a decrease of $0.5 million from the three months ended September 30, 2012.  The decrease resulted from a decrease in production volumes totaling $0.4 million coupled with a decrease in average depletion rates totaling $0.1 million.  Depletion and amortization for the nine months ended September 30, 2013 was $1.4 million, a decrease of $1.3 million from the nine months ended September 30, 2012.  The decrease resulted from a decrease in production volumes totaling $1.0 million coupled with a decrease in average depletion rates totaling $0.3 million.  The decreases in the depletion rates were attributable to revisions in reserve estimates, primarily related to the Liberty Project.  See “Overview” above for additional information.

Management Fees to Affiliate.  Management fees for each of the three months ended September 30, 2013 and 2012 were $0.3 million.  Management fees for each of the nine months ended September 30, 2013 and 2012 were $0.8 million. 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.

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

	Three months ended September 30,					Nine months ended September 30,
	2013		2012			2013			2012
	(in thousands)
Lease operating expense	$	283	$	343		$	980		$	1,138
Workover expense		22		(1	)		117			32
Geological costs		8		21			26			73
Dry-hole costs		-		(3	)		(3	)		65
	$	313	$	360		$	1,120		$	1,308

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  The average production cost was $7.20 per barrel of oil equivalent (“BOE”) and $6.71 per BOE during the three and nine months ended September 30, 2013, respectively, compared to $4.99 per BOE and $4.83 per BOE during the three and nine months ended September 30, 2012, respectively.  Workover expense represents costs to restore or stimulate production of existing reserves of a proved property.  During the three and nine months ended September 30, 2013, workover expense related to the Liberty Project.  During the three and nine months ended September 30, 2012, workover expense primarily related to the Raven Project and Main Pass 283/279 well #1.  Geological costs, which represent costs incurred to obtain seismic data, surveys, and lease rentals, related to the Beta Project.  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.  During the nine months ended September 30, 2012, dry-hole costs, inclusive of credits, were primarily related to the Dakota Project.

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

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(in thousands)
Accounting and professional fees	$	26	$	40	$	107	$	111
Insurance expense		27		36		91		78
Other		2		3		6		8
	$	55	$	79	$	204	$	197

Accounting and professional fees represent expenses for audits, quarterly reviews, tax preparation, reserve data engineering and reporting, and administration of filings.  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.  

Gain on Sale of Oil and Gas Properties.  There was no gain on sale of oil and gas properties during the three and nine months ended September 30, 2013.  During the three and nine months ended September 30, 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.

Other Income (Loss).  Other income (loss) for the three and nine months ended September 30, 2013 and 2012 is detailed in the following table.

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
	(in thousands)
Interest income	$	4	$	7	$	13	$	17
Realized losses on derivative instruments		-		-		-		(131	)
	$	4	$	7	$	13	$	(114	)

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Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the nine months ended September 30, 2013 were $7.1 million, primarily related to revenue received of $9.3 million, partially offset by operating expenses paid of $1.2 million, management fees of $0.8 million and general and administrative expenses paid of $0.2 million.

Cash flows provided by operating activities for the nine months ended September 30, 2012 were $11.2 million, primarily related to revenue received of $13.6 million, partially offset by operating expenses paid of $1.4 million, management fees of $0.8 million and general and administrative expenses paid of $0.2 million.

Investing Cash Flows

Cash flows used in investing activities for the nine months ended September 30, 2013 were $0.9 million, primarily related to capital expenditures for oil and gas properties.

Cash flows provided by investing activities for the nine months ended September 30, 2012 were $3.2 million, primarily related to proceeds from the maturity of investments in U.S. Treasury securities of $5.0 million, partially offset by capital expenditures for oil and gas properties of $1.8 million.

Financing Cash Flows

Cash flows used in financing activities for the nine months ended September 30, 2013 were $5.6 million, related to manager and shareholder distributions.

Cash flows used in financing activities for the nine months ended September 30, 2012 were $11.4 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 September 30, 2013, 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 $21.0 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.

As of September 30, 2013, the Fund expects to spend an additional $21.2 million related to its investments in oil and gas properties, inclusive of $21.0 million to develop the Beta Project, of which $5.0 million is expected to be spent during the next twelve months.  Total capital commitments exceed available working capital by $11.4 million at September 30, 2013, which includes projected 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.

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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 have been 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 September 30, 2013, the Fund had no borrowings under this credit agreement.  See Note 5 of “Notes to Unaudited Condensed Financial Statements” – “Credit Agreement – Beta Project Financing” in Part I of this Quarterly 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 that 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 September 30, 2013.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at September 30, 2013 and December 31, 2012 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 September 30, 2013 and December 31, 2012, 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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Fund’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Fund’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of September 30, 2013.

15

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

None.

ITEM 1A.  RISK FACTORS

Not required.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  MINE SAFETY DISCLOSURES

None.

ITEM 5.  OTHER INFORMATION

None.

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ITEM 6.  EXHIBITS

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING
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
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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

				RIDGEWOOD ENERGY W FUND, LLC
Dated:	November 5, 2013	By:	/s/	ROBERT E. SWANSON
			Name:	Robert E. Swanson
			Title:	Chief Executive Officer
				(Principal Executive Officer)
Dated:	November 5, 2013	By:	/s/	KATHLEEN P. MCSHERRY
			Name:	Kathleen P. McSherry
			Title:	Executive Vice President and Chief Financial Officer
				(Principal Financial and Accounting Officer)

17