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, 20142016
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)
 
Delaware26-0225130
(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 filero☐Accelerated filero☐
Non-accelerated filer
 
o(Do☐
 (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 o☐     No x☒

There is no market for the shares of LLC Membership Interest in the Fund.  As of March 3, 20157, 2017 there arewere 332.2918 shares of LLC Membership Interest outstanding.
 
 

RIDGEWOOD ENERGY W FUND, LLC
2014
2016 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
   PAGE
    
PART I   
 
ITEM 1
BUSINESS
2
 
ITEM 1A
RISK FACTORS
9
ITEM 1B
UNRESOLVED STAFF COMMENTS
9
ITEM 2
PROPERTIES
9
ITEM 3
LEGAL PROCEEDINGS
10
 
ITEM 1B
UNRESOLVED STAFF COMMENTS
10
ITEM 2
PROPERTIES
10
ITEM 3
LEGAL PROCEEDINGS
11
ITEM 4
MINE SAFETY DISCLOSURES
1011
PART II   
 
ITEM 5
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
1112
 
ITEM 6
SELECTED FINANCIAL DATA
1112
 
ITEM 7
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS
1112
 
ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
1618
 
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
1618
 
ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE
1718
 
ITEM 9A
CONTROLS AND PROCEDURES
1718
 
ITEM 9B
OTHER INFORMATION
1719
PART III   
 
ITEM 10
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
18
ITEM 11
EXECUTIVE COMPENSATION
19
 
ITEM 11
EXECUTIVE COMPENSATION
20
ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND

RELATED STOCKHOLDER MATTERS
1920
 
ITEM 13
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR

INDEPENDENCE
1920
 
ITEM 14
PRINCIPAL ACCOUNTING FEES AND SERVICES
2021
PART IV   
 
ITEM 15
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
2122
    
  2223
 
 
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 and 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 USU.S. 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 and other conditions affecting the pricing, production and productiondemand of oil and natural gas, the cost and availability of equipment, and changes in domestic and foreign governmental regulations.regulations, as well as other risks and uncertainties discussed in this Annual Report in Item 1. “Business” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.  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.

 
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”).  In 2011, pursuant to the LLC Agreement,limited liability company agreement (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”)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.   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.information and the management of the Fund’s investments in projects. 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. Historically, when the Fund had sought project investment, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects.  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.Annual Report.

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 forduring each of the years ended December 31, 20142016 and 20132015 were $1.0 million.  Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  The Fund did not pay distributions during the year ended December 31, 2016.  Distributions paid to the Manager for each ofduring the yearsyear ended December 31, 2014 and 20132015 were $1.0$0.2 million.

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, 2014, the Fund’s participation in investments in oil and natural gas properties had been completely identified and contracted and the balance of the Fund’s capital has been fully allocated to complete such projects and since that time, theThe Fund has not investigated or invested in, and does not expect in the future to investigate or invest in any additional projects other than those in which the Fundit currently has a working interest.interest, as discussed below under the heading “Properties” in this Item 1. “Business” of this Annual Report.  The Fund’s remaining capital has been fully allocated to complete such projects.
 

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.

Investment Committee
Ridgewood Energy maintains an investment committee consisting of five members, whichall of whom are employees of the Manager (the “Investment Committee”).  The Investment Committee provides operational, financial, scientific and technical oil and gas expertise to the Fund (the “Investment Committee”).and generally approves investments and other matters for the Fund.  Two members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and three members are based out of the Manager’s Houston, Texas office.  Currently, the Investment CommitteeCommittee’s activities surrounding the Fund are principally related to the development and operation of properties forin which it already has a working interest.

Participation and Joint Operating Agreements
On behalf of the Fund, and with respect to the Fund’s projects, Ridgewood Energy negotiatesnegotiated participation and joint operating agreements with the goal of achieving the best possible economics and governance rights for the Fund in connection with acquiring the interest.agreements.  Under the joint operating agreement, proposals and decisions with respect to a project and related activities are generally 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 non-operating 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.

Project Information

ExistingThe Fund’s existing projects are located in the waters of the Gulf of Mexico, offshore 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 BureauOffice of Ocean Energy ManagementNatural Resources Revenue (“BOEM”ONRR”) depending on the lease.  Other than BOEMthe ONRR royalties, the Fund does not have material royalty burdens other than as provided by the terms of the Fund’s credit agreement, which requireswill require the Fund to pay royalties from the Beta Project to the lender. See Note 43 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 BOEMBureau of Ocean Energy Management (“BOEM”), an agency of the United States Department of Interior, promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the "Royalty“Royalty Relief Rule"Rule”). The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the Outer Continental ShelfOCS nor does it apply if the price of natural gas exceeds $11.35$11.60 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation.  The Fund currently has two leases,one project, the Cobalt and Liberty projects,Project, which qualifyqualifies for royalty relief under the Royalty Relief Rule.

Deepwater Royalty Relief
In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Royalty 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 Royalty Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater.  The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $37.30 per barrel and $48.43 per barrel), adjusted annually for inflation.  The Deepwater Royalty Relief Act does not apply to natural gas if the prices of natural gas exceed certain thresholds (currently estimated to be between $4.66 per mmbtu and $8.07 per mmbtu) adjusted annually for inflation.  The Fund currently has one lease,two projects, the Liberty Project,and Beta projects, which qualifiesqualify for royalty relief under the Deepwater Royalty Relief Act.

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, 2014.2016.  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, each of which produces both oil and natural gas, 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   0.23 
  Total Productive Wells 
  Gross  Net 
Oil and natural gas  2   0.17 

Acreage Data
The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 2014.2016.  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
 17,240   1,135   5,760   173

Developed Acres  Undeveloped Acres
Gross  Net  Gross  Net
 10,760   941   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.  The budgetSee Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for each project is inclusiveinformation regarding the funding of estimated asset retirement obligations.the Fund’s capital commitments.

     Total Spent     
  Working  through  Total Fund  
Project Interest  December 31, 2014  Budget Status
     (in thousands)  
Non-producing Properties          
Beta Project  3.0% $12,254  $26,420 Well deemed to be a discovery in 2012.  Completion efforts are ongoing and production is expected to commence in 2016.
Producing Properties             
Cobalt Project  5.0% $2,368  $2,523 Production commenced in 2009. Recompletions are planned for third quarter 2015 and fourth quarter 2016.
Liberty Project  12.0% $13,409  $15,089 Production commenced in 2010.  Well is currently producing, however, was shut-in periodically during 2014 due to maintenance activities.  Recompletion is planned for 2016.
Sold Properties             
Raven Project well #1 & #2  6.25% $2,863  $2,863 In January 2014, the Fund sold its interest in the Raven Project.  See "Raven Sale" below for additional information.
Raven Sale
     Total Spent  Total  
   Working  through  Fund  
Project Interest  December 31, 2016  Budget Status
     (in thousands)  
Producing Properties             
Beta Project 3.0%  $21,791  $26,918 The Beta Project is expected to include the development of four wells. Well #1 commenced production during third quarter 2016. Well #2 commenced production during fourth quarter 2016. Wells #3 and #4 are expected to commence production in 2017. The Fund expects to spend $3.7 million for additional development costs and $1.4 million for asset retirement obligations.
Cobalt Project 5.0%  $2,368  $2,496 The Cobalt Project, a single-well project, commenced production in 2009. Recompletions are planned for 2017 and 2018 at an estimated total cost of $60 thousand. The Fund expects to spend $68 thousand for asset retirement obligations.
Liberty Project 12.0%  $13,387  $16,031 The Liberty Project, a single-well project, commenced production in 2010. After various shut-ins in late-2015 and early-2016, due to third-party facilities' repair and maintenance activities, the well resumed production in early-May 2016. A smart recompletion is planned for 2018 with no costs to the Fund. The Fund expects to spend $2.6 million for asset retirement obligations.

On January 17, 2014, the Fund, along with its affiliates, Ridgewood Energy Gulf of Mexico Oil and Gas Fund, L.P., Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy P Fund, LLC, and Ridgewood Energy Y Fund, LLC,  (when used with the Fund the “Ridgewood Funds”) entered into a purchase and sale agreement to sell the Ridgewood Funds’ interests in the Raven Project, located in the state waters of Louisiana, to Castex Energy Partners, L.P. for cash consideration totaling $21.7 million.  The closing of the sale transaction occurred on January 30, 2014.
The Fund had a 6.25% working interest in the Raven Project and received $2.7 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.1 million, thereby resulting in a gain to the Fund of $2.6 million, which was recognized during the year ended December 31, 2014.
Marketing/Customers

The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to marketmarkets the Fund’s oil and natural gas.gas to third parties consistent with industry practice.  During 2015, Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. During 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time.  Currently, and during 2014,2016, the Fund had twothree 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 oil and natural gas fromFund has one property, the Fund’s non-producing projects will have access to pipeline transportation and will be marketed through Energy Upgrade, Inc.   The Fund is participatingBeta Project, for which it participated in the financing of both platform and pipeline infrastructure for its non-producing project.infrastructure.

NaturalThe Fund’s natural gas and oil generally is sold in the spot marketto its customers at prevailing market 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 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.  LowDuring the year ended December 31, 2016, fluctuations in commodity prices could havehad an adverse effect on the Fund’s future profitability.  Historically,profitability and distributions.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes”, “Results of Operations – Overview” and “Results of Operations – Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue.   In the past, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production. 
 
 
Seasonality

Generally, the Fund'sFund’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'sFund’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 significant damage, shut-ins, or production stoppages due to hurricane activity in 2014.2016.

OperatorOperators

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 joint 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 LLOG Exploration Offshore, L.L.C., 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 had to bear the risk that the Manager will be able to selectwould find suitable projects, but also that, once selected, have to bear the risk that 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’sfunds’ passive investments, including those of the Fund.  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 its projects.  In addition, the Manager's pastManager’s practice has beenis 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 theits 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 insurable 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'sFund or to its affiliates, yearly insurance coverage 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’sits 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.  As of December 31, 2014,2016, the Fund has deposited $1.8$2.3 million from capital contributions and reinvested interest intoinvested in a salvage fund.  AsOn a resultmonthly basis, the Fund expects to contribute to the salvage fund a portion of the significant capital required and number of wells anticipated foroperating income from the Beta Project, any furtherto fund the asset retirement obligations of such project. Such contributions to the salvage fund will reduce the amount of cash distributions that would be made to investors by the Fund.  Any portion of athe salvage fund that remains after the Fund payshas paid for all of its share of the actual salvage costasset retirement obligations will be distributed to the shareholders and the Manager. There are no legal restrictions on the withdrawal or use ofwithdrawals from the salvage fund.
 
 
Competition

Strong competitionCompetition 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.

Employees

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

Offices

The principal administrative 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 10987.125 Worth Avenue, Suite 318, Palm Beach, Florida, 33480.  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, production and transportation 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.
 
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”).BOEM. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”(“BSEE”) pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS.  Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. The BSEE regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE has proposed stricteradopted strict requirements for subsea drilling production equipment and has indicated that there will be an additional, separate rulemakinghad proposed new requirements to govern the design, performance and maintenance ofimplement equipment reliability improvements, building upon enhanced industry standards for blowout preventers but thatand blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment.  In April 2016, BSEE adopted a final rule has not yet been published.establishing updated standards for blowout prevention systems and other well controls pertaining to offshore activities. The final rule became effective July 28, 2016; compliance with certain provisions of the final rule, however, are deferred as specified. The final rule imposes new requirements relating to, among, other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment.  BSEE has also published a draftpolicy statement of policy on safety culture with nine proposed characteristics of a robust safety culture.  The rule applies directly to operators as opposed to non-operators.  However, the costs associated with compliance, which at this time cannot be determined or estimated, will likely increase the costs of operating in the Gulf of Mexico and such costs will be imposed upon all working interest owners, including the Fund. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activities can result from either governmental or citizen prosecution.
BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the OCS (“Lessees”). Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees,  (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance.  The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured.  The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

Sales and Transportation of Oil and Natural Gas

The Fund, directly or indirectly through affiliated entities, 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 Act of 1938, The Natural Gas Policy Act of 1978 and the Energy Policy Acts of 1992 and 2005.Commission.  Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service.cost-of-service-based. 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, the handling and managing of waste materials, and the protection of aquatic species and habitats. However, although itWhile most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operators on the Fund’s behalf, the Fund shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless,damage. The 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.  OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities and deepwater ports of $350$633.85 million, while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $75$133.65 million in other damages.damages for each incident. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.  Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA, and the Fund believes that complianceOPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on itsthe Fund’s operations or financial condition.
Clean Water Act. Generally, the Clean Water Act imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal, or state, if applicable, agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

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

Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act of 1976,as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980,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 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 orproduction; material increases in the costs of production, development or exploration,exploration; enforcement actions or other penalties as a result of any non-compliance with any such regulations; or otherwise have a material adverse effect on the Fund’s operating results and cash flows.

8
Dodd-Frank Act.  The Dodd-Frank Wall Street Reform and Consumer Protection Act signed into law in July 2010,(the “Dodd-Frank Act”), 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.

On February 3, 2017, the “Presidential Executive Order on Core Principles for Regulating the United States Financial System” (the “Order”) was issued to review the Dodd-Frank Act.  The Fund cannot predict at this time what regulations or portions of the law, if any, will be changed as a result of the Order.

Under its LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Dodd-Frank Act 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,U.S. Commodity Futures Trading Commission (“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 Act, the CFTC has set “speculative position limits” (limits(which are 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 Act 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 alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance.  The Fund is not currently, and has not been during 2016, or at any time since 2012, a party to any derivative instruments or hedging programs.
Dodd-Frank Act 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.  Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013. On June 27, 2016, the SEC adopted resource extraction issuer payment disclosure rules pursuant to Section 1504 of the Dodd-Frank Act that will require resource extraction companies to publicly file with the SEC information about the type and total amount of payments made to a foreign government or to the U.S. federal government for each project related to the development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government. However, on February 14, 2017, a bill passed by the United States Congress was signed eliminating the SEC resource extraction issuer payment disclosure rules. The SEC will have one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act.

ITEM 1A.RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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 forduring the years ended December 31, 20142016 and 2013.2015.  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.  The exploratory well in-progress at December 31, 2014 and 2013 is expected toAll of the wells, which produce both oil and natural gas, and isare located in the offshore waters of the Gulf of Mexico.  During the years ended December 31, 2014 and 2013, 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 wellsthe well in-progress atas of December 31, 2014.2016.

  2016  2015 
   Gross  Net  Gross  Net 
Exploratory wells:            
Productive  1   0.03   -   - 
In-progress  -   -   1   0.03 
Exploratory well total  1   0.03   1   0.03 
                 
Development wells:                
Productive  1   0.03   -   - 
In-progress  1   0.03   -   - 
Development well total  2   0.06   -   - 
  2014  2013 
  Gross  Net  Gross  Net 
Exploratory wells:            
In-progress  1   0.03   1   0.03 

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

The Manager’s primary technical person in charge of overseeing the Fund’s 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-fivethirty 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 atas of December 31, 20142016 and 20132015 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.

Proved Reserves.  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. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  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 8. “Financial Statements and Supplementary Data” of this Annual Report, is incorporated herein by reference. 

Proved Undeveloped Reserves.  AtAs of December 31, 2014,2016, the Fund had approximately 418 thousand barrels and 314 thousand mcf of proved undeveloped oil and natural gas reserves respectively, related to the Beta Project.  AtProject totaling 27 thousand barrels of oil and 16 thousand mcf of natural gas.  As of December 31, 2013,2015, the Fund had approximately 419 thousand barrels and 1.8 million mcf of proved undeveloped oil and natural gas reserves (inclusive of natural gas liquid (“NGL”) reserves), respectively, related to the Beta Project totaling 0.4 million barrels of oil and Raven projects.0.3 million mcf of natural gas. The development of the Beta Project which was determined to be a discovery duringin 2012 is ongoing and commenced production is expected to commence in 2016.  On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, and proved developed and undeveloped gas reserves, inclusive of NGL reserves, of approximately 0.3 million mcf and 1.4 million mcf, respectively.quarter 2016.

During the year ended December 31, 2014,2016, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $5.9$3.8 million, which related to the Beta Project.  The Fund currently expects to develop the proved undeveloped reserves relating to the Beta Project during the year ending December 31, 2017. Information regarding estimated future development costs relating to the development of the Fund’s non-producing properties,Beta Project, 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 forduring the years ended December 31, 20142016 and 20132015 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, 2014,2016, the Fund had no delivery obligations or delivery commitments under any existing contracts.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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,January 31, 2017, there were 825842 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, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs, and funding of 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. DuringThe Fund did not pay distributions during the yearsyear ended December 31, 2014 and 20132016.  During the year ended December 31, 2015, the Fund paid distributions totaling $8.0$1.2 million and $6.8 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 distributionsDistributions to shareholders except as providedare made in accordance with the Fund’s LLC Agreement. The Fund does not expect in the LLC Agreement.future to investigate or invest in any additional projects other than those in which it currently has a working interest. The Fund’s remaining capital has been fully allocated to complete such projects.

The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. 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.

RevenuesCommodity Price Changes
Changes in commodity prices may significantly affect liquidity and expected operating results.  Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are subjectcommercially recoverable.  Significant declines in prices could result in non-cash charges to marketearnings due to impairment.

During fourth quarter 2014, there was a significant decline in oil and natural gas commodity prices, which continued into mid-year 2016 when oil and gas commodity prices began to show improvement. The Fund plans for price cyclicality in its planning and believes it is well positioned to withstand such price volatility. Despite operating in a sustained lower commodity price environment, the Fund continued to advance the development of the Beta Project and during the second half of 2016, two wells from the Beta Project commenced production. The Fund has suspended distributions and continues to conserve cash to complete the final phase of the Beta Project as budgeted.  See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 2016 and 2015 and the effect of such decreased average prices on the Fund’s results of operations.  If oil and natural gas prices decline, even if only for a short period of time, the Fund’s results of operations and liquidity will continue to be adversely impacted.

Market pricing for oil and natural gas which has beenis 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.

Factors affecting market pricing for oil and natural gas include:
 
·weather conditions;
·economic conditions, including demand for petroleum-based products;
·actions by OPEC, the Organization of Petroleum Exporting Countries;
·political instability in the Middle East and other major oil and gas producing regions;
·governmental regulations, both domestic and foreign;
·domestic and foreign tax policy;
·the pace adopted by foreign governments for the exploration, development, and production of their national reserves;
·the supply and price of foreign imports of oil and gas;
·the cost of exploring for, producing and delivering oil and gas;
·the discovery rate of new oil and gas reserves;
·the rate of decline of existing and new oil and gas reserves;
·available pipeline and other oil and gas transportation capacity;
·the ability of oil and gas companies to raise capital;
·the overall supply and demand for oil and gas; and
·the price and availability of alternate fuel sources.
 
Changes in commodity prices may significantly affect liquidity and expected operating results. Price changes will directly affect revenues. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment.

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 conformityaccordance 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.  The following is a discussion of the accounting policies and estimates that management believes are most significant.

Accounting for Acquisition, Exploration Development and AcquisitionDevelopment Costs
Exploration,Acquisition, exploration and 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. 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.”

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.operators and, at times, with information provided by third-party abandonment consultants specializing in the oil and gas industry.  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 such as the timing of settlements, the credit-adjusted risk-free rates used and inflation rates, 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 carrying value of its oil and gas properties wheneverannually and when 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 estimated future net undiscounted cash flows to the net bookcarrying value at the time of the review.  If the net bookcarrying value exceeds theestimated future net undiscounted cash flows, the carrying value of the propertyasset is written down to fair value, which is determined using estimated future 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.asset.  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 net discounted future net cash flows from proved oil and natural gas reserves could change in the near term.

Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have resulted in impairments of oil and gas properties as described below in this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Results of Operations - Impairment of Oil and Gas Properties”.  If oil and natural gas prices decline, significantly, even if only for a short period of time, it is possible that write-downsadditional impairments of oil and gas properties couldwill occur.

12

Results of Operations

The following table summarizes the Fund’s results of operations forduring the years ended December 31, 20142016 and 2013,2015, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.

  Year ended December 31, 
  2016  2015 
  (in thousands) 
Revenue      
Oil and gas revenue $2,725  $2,903 
Expenses        
Depletion and amortization  1,629   625 
Impairment of oil and gas properties  -   142 
Management fees to affiliate  960   960 
Operating expenses  905   1,043 
General and administrative expenses  150   146 
Total expenses  3,644   2,916 
Loss from operations  (919)  (13)
Interest (expense) income, net  (366)  7 
Net loss $(1,285) $(6)
  Year ended December 31, 
  2014  2013 
  (in thousands) 
Revenue      
Oil and gas revenue $7,842  $10,277 
         
Expenses        
Depletion, depreciation and amortization  1,006   1,790 
Impairment of oil and gas properties  -   505 
Management fees to affiliate  960   1,031 
Operating expenses  1,138   1,428 
General and administrative expenses  203   271 
Total expenses  3,307   5,025 
Gain on sale of oil and gas properties  2,599   - 
Income from operations  7,134   5,252 
Interest income  15   17 
Net income $7,149  $5,269 

 
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, 20142016 and 2013. NGL2015.  Natural gas liquid (“NGL”) sales are included within gas sales.

  Year ended December 31, 
  2016  2015 
Number of wells producing  4   2 
Total number of production days  737   614 
Oil sales (in thousands of barrels)  59   51 
Average oil price per barrel $41  $50 
Gas sales (in thousands of mcfs)  136   156 
Average gas price per mcf $2.20  $2.16 
  Year ended December 31, 
  2014  2013 
Number of wells producing  2   4 
Total number of production days  704   1,112 
Oil sales (in thousands of barrels)  73   72 
Average oil price per barrel $92  $105 
Gas sales (in thousands of mcfs)  232   696 
Average gas price per mcf $4.55  $3.99 

The decreasesincreases noted in the numberabove table were primarily related to the commencement of wells producing, production days andof the Beta Project, partially offset by the Liberty Project, which had been shut-in during the early part of 2016. The decrease in gas sales volume were primarily attributablerelated to the Raven Project, which was sold in January 2014.  The increase in oil sales volume was attributable to improved oil production rate forshut-in of the Liberty Project as a result of maintenance activities.  Project.  See Item 1. “Business”“Business” of this Annual Report under the heading “Properties” for more information.information.

Oil and Gas Revenue.  Generally, the Fund sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. In a netback agreement, the Fund receives a price, net of transportation expense incurred by the purchaser, and the Fund records revenue at the net price received. In the second type of agreement, the Fund pays transportation expense directly, and transportation expense is included within operating expense in the statements of operations.

Oil and gas revenue forduring the year ended December 31, 20142016 was $7.8$2.7 million, a decrease of $2.4$0.2 million from the year ended December 31, 2013.2015.  The decrease was primarily attributable to decreased sales volume totaling $1.7 million coupled with the impact of the change in averageoil prices totaling $0.8 million.  The decrease in sales volume related to the sale of the Raven Project,$0.5 million, partially offset by increased oil sales volume related to the Liberty Project.   totaling $0.4 million.

See “Overview” above for additional information.factors that impact the oil and gas revenue volume and rate variances.

Depletion Depreciation and Amortization.  Depletion depreciation and amortization forduring the year ended December 31, 20142016 was $1.0$1.6 million, a decreasean increase of $0.8$1.0 million from the year ended December 31, 2013.2015.  The decrease resultedincrease was primarily from a decreaseattributable to an increase in the average depletion rate.  The increase in the average depletion rate was primarily attributable to the onset of production volumes totaling $0.7 million.  of the Beta Project.  Depletion and amortization rates were also impacted by changes in reserve estimates provided annually by the Fund’s independent petroleum engineers.

See “Overview” above for additional information.certain factors that impact the depletion and amortization volume and rate variances.

13
Impairment of Oil and Gas Properties.  The Fund did not record an impairment of oil and gas properties during the year ended December 31, 2014.   2016.  During the year ended December 31, 2013,2015, the Fund recorded an impairment of oil and gas properties of $0.5$0.1 million related to the Cobalt Project, which was attributable to both declines in future oil and gas prices and an increase in estimated asset retirement costs.revisions to reserve estimates as provided by the Fund’s independent petroleum engineers.

Management Fees to Affiliate.   Management fees for each of the years ended December 31, 2014 and 2013 were $1.0 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. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term capital commitments.

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, 
  2016  2015 
  (in thousands) 
Lease operating expense $554  $669 
Insurance expense  170   257 
Accretion expense  144   90 
Other  37   27 
  $905  $1,043 
 
  Year ended December 31, 
  2014  2013 
  (in thousands) 
Lease operating expense $1,080  $1,376 
Accretion expense  37   14 
Geological costs  17   31 
Dry-hole costs  3   (110)
Workover expense  1   117 
  $1,138  $1,428 

Lease operating expense, which includes transportation expense, relates to the Fund’s producing properties.  Insurance expense represents premiums related to the Fund’s properties, during each period as outlined above in “Overview”.  which vary depending upon the number of wells producing or drilling. Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties.

The average production cost, which includes lease operating expense, transportation expense and insurance expense, was $9.63$8.85 per barrel of oil equivalent (“BOE”) during the year ended December 31, 20142016 compared to $6.94$11.96 per BOE during the year ended December 31, 2013.  Accretion2015.  The decrease was primarily attributable to lower lease operating expense related to the asset retirement obligations established for the Fund’s proved properties.  Geological costs represent costs incurred to obtain seismic data, surveys, and lease rentals.  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.  Workover expense represents costs to restore or stimulate production of existing reserves of a proved property.Liberty Project.

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

  Year ended December 31, 
  2014  2013 
  (in thousands) 
Accounting and professional fees $123  $138 
Insurance expense  75   126 
Other  5   7 
  $203  $271 

Accountingaccounting 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.  expenses.

Gain on Sale of Oil and Gas Properties.  During the year ended December 31, 2014, the Fund recorded a gain on sale of oil and gas properties of $2.6 million related to the Raven Project.  See Item 1. “Business” of this Annual Report under the heading “Properties” for additional information regarding the sale.  There were no such amounts recorded during the year ended December 31, 2013.

Interest (Expense) Income, Net.  Interest (expense) income, net is comprised of interest expense and amortization of debt discounts and deferred financing costs related to the Fund’s long-term borrowings (see “Liquidity Needs” below for additional information), and interest income earned on cash and cash equivalents and salvage fund.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities forduring the year ended December 31, 20142016 were $6.1$0.1 million, primarily related to revenue received of $8.3$2.0 million, partially offset by operating expenses paid of $1.1 million, management fees of $1.0 million, operating expenses of $0.8 million and general and administrative expenses paid of $0.2$0.1 million.

Cash flows provided by operating activities forduring the year ended December 31, 20132015 were $8.4$1.2 million, primarily related to revenue received of $11.1$3.2 million, partially offset by operating expenses paid of $1.5$1.1 million and management fees of $1.0 million and general and administrative expenses paid of $0.2 million.

Investing Cash Flows
Cash flows used in investing activities forduring the year ended December 31, 20142016 were $3.13.3 million, primarily related to capital expenditures for oil and gas properties of $5.8 million, partially offset by proceeds from the sale of the Raven Project of $2.7 million.properties.

Cash flows used in investing activities forduring the year ended December 31, 20132015 were $2.36.9 million, related to capital expenditures for oil and gas properties of $1.6$6.5 million and investments in salvage fund of $0.7$0.4 million.

Financing Cash Flows
Cash flows used inprovided by financing activities forduring the year ended December 31, 20142016 were $8.0$3.8 million, related to manager and shareholder distributions, of which $1.8 million was related to the distribution of proceeds from the sale of the Raven Project.long-term borrowings.

Cash flows used inprovided by financing activities forduring the year ended December 31, 20132015 were $6.8$4.5 million, related to proceeds from long-term borrowings of $5.7 million, partially offset by manager and shareholder distributions.
distributions totaling $1.2 million.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas 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, 2014, 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 $14.2 million related to the developmentSee Item 1. “Business” of this project, whichAnnual Report under the Fund anticipates will include a four-well development with related platformheading “Properties” and pipeline infrastructure.  See “Liquidity Needs” below for additional information.

Capital expenditures for oil and gas 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 could 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 oil and gas properties.properties and borrowing repayments. Such needs are funded utilizing operating income and existing cash on-hand and income earned therefrom.on-hand.

As of December 31, 2014,2016, the Fund’s estimated capital commitments related to its oil and gas properties were $16.1$7.9 million (which include asset retirement obligations for the Fund’s projects of $4.0 million and projected interest costs of $2.4 million for the Beta Project)$4.1 million), of which $5.0$3.3 million is expected to be spent during the year ending December 31, 2015. These expected capital commitments exceed available working capital and salvage fund by $12.0 million at December 31, 2014. In November 2012,2017, which is primarily related to complete the Fund entered into a credit agreement that provides for an aggregate loan commitmentfinal phase of up to $9.4 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. PrincipalFuture results of operations and interest amountscash flows are contracted to be repaid upondependent on the onset ofcontinued successful development and the related production of oil and gas revenues from 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.
Project.  Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations and borrowings to be sufficient to cover its commitments, borrowing repayments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s capital commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term capital commitments if needed.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments.

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, and will be impacted in the future, 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(as amended on September 30, 2016, 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, 20142016 and 2013,2015, the Fund had borrowed $9.4 million and $5.7 million, respectively, under the Credit Agreement wherein no borrowings remain.

The loan bears interest at 8% compounded annually. Principal and interest are repaid at the lesser of (i) a monthly rate of 1.25% of the Fund’s total principal outstanding as of July 31, 2016 for the first seven months beginning October 2016, and increases to a monthly rate of 4.5% thereafter until the loan is repaid in full, and (ii) debt service amount as defined in the Credit Agreement, 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 interest in the Beta Project to the lenders.  The 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 the other participating funds managed by the Manager. Such ORRI will not accrue or become payable to the Lenders until after the Loan is repaid in full.

Unamortized debt discounts and deferred financing costs of $0.1 million as of December 31, 2016 and $0.3 million as of December 31, 2015 are presented as a reduction of “Long-term borrowings” on the balance sheets.

Principal and interest amounts are contracted to be repaid beginning October 2016, over a period not to extend beyond December 31, 2020.  The Fund expects operating income from the Beta Project will be sufficient to cover the principal and interest payments required under the Credit Agreement.  See Note 43 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.

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 Lenderslenders under the Credit Agreement may accelerate the maturity of the Loanloan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund believes it is in compliance with all covenants under the Credit Agreement atas of December 31, 20142016 and 2013.2015.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements atas of December 31, 20142016 and 20132015 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 atas of December 31, 20142016 and 20132015, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs”Needs – Credit AgreementAgreement” above.
 
Recent Accounting Pronouncements
 
The Fund has consideredSee 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 recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.pronouncements.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.
 
ITEM 8.                FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 and 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
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, 2014.2016.  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, 2014.2016.  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 (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2014,2016, 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, 20142016 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B.OTHER INFORMATION

None.

PART III

ITEM 10.              DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 the Fund and their ages atas of December 31, 20142016 are as follows:
 
Name, Age and Position with Registrant
 
Robert E. Swanson, 6769
  Chief Executive Officer
 
Kenneth W. Lang, 6062
  President and Chief Operating Officer
 
Kathleen P. McSherry, 4951
  Executive Vice President and Chief Financial Officer
 
Robert L. Gold, 5658
  Executive Vice President
 
Daniel V. Gulino, 5456
  Senior Vice President, General Counsel and Secretary

The officers in the above table have 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 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 Ridgewood Private Equity Partners, 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.  Ms. McSherry holds a Bachelor of Science degree in Accounting.Accounting from Kean University.

Robert L. Gold has served as a senior officer 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 - Legal Affairs and Secretary for Ridgewood Energy and has served as counselin that capacity for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management, LLC and Ridgewood Private Equity Partners, LLC 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.

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.

18

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, 2014,2016, 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 as of the date of this filing.January 31, 2017. 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
 
Pursuant to the terms of the LLC Agreement, the Manager renders 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 forduring each of the years ended December 31, 20142016 and 20132015 were $1.0 million.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  The Fund did not pay distributions during the year ended December 31, 2016.  Distributions paid to the Manager forduring each of the yearsyear ended December 31, 20142015 were $0.2 million.

None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.

During 2015, Beta S&T, a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and 2013 were $1.0 million.as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. During 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the agreement or under any other agreements it enters into with regard to the oil and gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations.  These revenues and operating expenses allocable to the Fund are based on the Fund’s working interest ownership in the Beta Project.

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.
 
ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
 
The following table presents fees for services rendered by Deloitte & Touche LLP forduring the years ended December 31, 20142016 and 2013.2015.
 
  Year ended December 31, 
  2014  2013 
  (in thousands) 
Audit fees (1)
 $85  $85 
  Year ended December 31, 
  2016  2015 
  (in thousands) 
Audit fees (1)
 $88  $88 
 
 (1)Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.

PART IV

ITEM 15. EXHIBITS AND 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
NUMBER
TITLE OF EXHIBIT
 
METHOD OF FILING
    
3.1Certificate 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
    
3.2Amended 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
    
10.1Credit 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
10.2First Amendment to Credit Agreement dated September 30, 2016 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 theretoFiled herewith
    
31.1Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) Filed herewith
    
31.2Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) Filed herewith
    
32Certifications 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
    
99.1Report of Netherland, Sewell & Associates, Inc. Filed herewith

101.INSXBRL Instance Document Filed herewith
    
101.SCHXBRL Taxonomy Extension Schema Filed herewith
    
101.CALXBRL Taxonomy Extension Calculation Linkbase Filed herewith
    
101.DEFXBRL Taxonomy Extension Definition Linkbase Document Filed herewith
    
101.LABXBRL Taxonomy Extension Label Linkbase Filed herewith
    
101.PREXBRL Taxonomy Extension Presentation Linkbase Filed herewith
 
 
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:  March 3, 20157, 2017By:/s/ ROBERT E. SWANSON 
  
Robert E. Swanson
Chief Executive Officer
 (Principal
(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. SWANSONChief Executive OfficerMarch 3, 20157, 2017
Robert E. Swanson  (Principal Executive Officer) 
   
   
/s/ KATHLEEN P. MCSHERRY Executive Vice President and Chief Financial OfficerMarch 3, 20157, 2017
Kathleen P. McSherry(Principal Financial and Accounting Officer) 
   
   
RIDGEWOOD ENERGY CORPORATION  
   
BY:  /s/ ROBERT E. SWANSON Chief Executive Officer of the ManagerMarch 3, 20157, 2017
Robert E. Swanson  
 
 
INDEX TO FINANCIAL STATEMENTSPAGE
  
Report of Independent Registered Public Accounting Firm
F-2
Balance Sheets as of December 31, 20142016 and 20132015
F-3
Statements of Operations for the years ended December 31, 20142016 and 20132015
F-4
Statements of Changes in Members' Capital for the years ended December 31, 20142016 and 20132015
F-5
Statements of Cash Flows for the years ended December 31, 20142016 and 20132015
F-6
Notes to Financial Statements
F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited
F-13
 
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, 20142016 and 2013,2015, and the related statements of operations, changes in members’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’sFund's internal control over financial reporting. Accordingly, we express no such opinion.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, 20142016 and 2013,2015, 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
March 3, 20157, 2017
 
RIDGEWOOD ENERGY W FUND, LLC
BALANCE SHEETS
(in thousands, except share data)


  December 31, 
  2016  2015 
Assets      
Current assets:      
Cash and cash equivalents $2,794  $2,191 
Production receivable  606   2 
Other current assets  137   - 
Total current assets  3,537   2,193 
Salvage fund  2,251   2,250 
Oil and gas properties:        
Proved properties  39,513   36,018 
Less:  accumulated depletion and amortization  (17,453)  (15,824)
Total oil and gas properties, net  22,060   20,194 
Total assets $27,848  $24,637 
         
Liabilities and Members' Capital        
Current liabilities:        
Due to operators $787  $263 
Accrued expenses  623   341 
Current portion of long-term borrowings  1,753   106 
Total current liabilities  3,163   710 
Long-term borrowings  7,513   5,265 
Asset retirement obligations  2,550   2,815 
Other liabilities  60   - 
Total liabilities  13,286   8,790 
Commitments and contingencies (Note 4)        
Members' capital:        
Manager:        
Distributions  (7,964)  (7,964)
Retained earnings  7,944   7,834 
Manager's total  (20)  (130)
Shareholders:        
Capital contributions (625 shares authorized;        
332.2918 issued and outstanding)  65,965   65,965 
Syndication costs  (7,823)  (7,823)
Distributions  (48,463)  (48,463)
Retained earnings  4,903   6,298 
Shareholders' total  14,582   15,977 
Total members' capital  14,562   15,847 
Total liabilities and members' capital $27,848  $24,637 
  December 31, 
  2014  2013 
Assets      
Current assets:      
Cash and cash equivalents $3,462  $8,521 
Salvage fund  90   90 
Production receivable  320   813 
Asset held for sale  -   317 
Other current assets  36   109 
Total current assets  3,908   9,850 
Salvage fund  1,716   1,708 
Other assets  418   558 
Oil and gas properties:        
Proved properties  21,629   20,132 
Equipment and facilities - in progress  7,330   2,763 
Less:  accumulated depletion, depreciation and amortization  (15,003)  (13,997)
Total oil and gas properties, net  13,956   8,898 
Total assets $19,998  $21,014 
         
Liabilities and Members' Capital        
Current liabilities:        
Due to operators $1,387  $1,368 
Accrued expenses  35   40 
Asset retirement obligations  90   90 
Liability held for sale  -   171 
Total current liabilities  1,512   1,669 
Asset retirement obligations  1,450   1,413 
Total liabilities  2,962   3,082 
         
Commitments and contingencies (Note 5)        
         
Members' capital:        
Manager:        
Distributions  (7,787)  (6,834)
Retained earnings  7,713   6,858 
Manager's total  (74)  24 
         
Shareholders:        
Capital contributions (625 shares authorized;        
332.2918 issued and outstanding)  65,965   65,965 
Syndication costs  (7,823)  (7,823)
Distributions  (47,457)  (40,365)
Retained earnings  6,425   131 
Shareholders' total  17,110   17,908 
Total members' capital  17,036   17,932 
Total liabilities and members' capital $19,998  $21,014 

The accompanying notes are an integral part of these financial statements.
 
 
RIDGEWOOD ENERGY W FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)


  Year ended December 31, 
  2014  2013 
Revenue      
Oil and gas revenue $7,842  $10,277 
         
Expenses        
Depletion, depreciation and amortization  1,006   1,790 
Impairment of oil and gas properties  -   505 
Management fees to affiliate (Note 3)  960   1,031 
Operating expenses  1,138   1,428 
General and administrative expenses  203   271 
Total expenses  3,307   5,025 
Gain on sale of oil and gas properties  2,599   - 
Income from operations  7,134   5,252 
Interest income  15   17 
Net income $7,149  $5,269 
         
Manager Interest        
Net income $855  $1,100 
         
Shareholder Interest        
Net income $6,294  $4,169 
Net income per share $18,940  $12,547 
The accompanying notes are an integral part of these financial statements.
   Year ended December 31, 
  2016  2015 
Revenue      
Oil and gas revenue $2,725  $2,903 
Expenses        
Depletion and amortization  1,629   625 
Impairment of oil and gas properties  -   142 
Management fees to affiliate (Note 2)  960   960 
Operating expenses  905   1,043 
General and administrative expenses  150   146 
Total expenses  3,644   2,916 
Loss from operations  (919)  (13)
Interest (expense) income, net  (366)  7 
Net loss $(1,285) $(6)
         
Manager Interest        
Net income $110  $121 
         
Shareholder Interest        
Net loss $(1,395) $(127)
Net loss per share $(4,199) $(382)


RIDGEWOOD ENERGY W FUND, LLC
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(in thousands, except share data)
  # of Shares  Manager  Shareholders  Total 
Balances, December 31, 2012  332.2918  $(49) $19,560  $19,511 
Distributions  -   (1,027)  (5,821)  (6,848)
Net income  -   1,100   4,169   5,269 
Balances, December 31, 2013  332.2918   24   17,908   17,932 
Distributions  -   (953)  (7,092)  (8,045)
Net income  -   855   6,294   7,149 
Balances, December 31, 2014  332.2918  $(74) $17,110  $17,036 
The accompanying notes are an integral part of these financial statements.
 
 
RIDGEWOOD ENERGY W FUND, LLC
STATEMENTS OF CASH FLOWSCHANGES IN MEMBERS' CAPITAL
(in thousands)thousands, except share data)


   # of Shares  Manager  Shareholders  Total 
Balances, December 31, 2014  332.2918  $(74) $17,110  $17,036 
Distributions  -   (177)  (1,006)  (1,183)
Net income (loss)  -   121   (127)  (6)
Balances, December 31, 2015  332.2918   (130)  15,977   15,847 
Net income (loss)  -   110   (1,395)  (1,285)
Balances, December 31, 2016  332.2918  $(20) $14,582  $14,562 
  Year ended December 31, 
  2014  2013 
       
Cash flows from operating activities      
Net income $7,149  $5,269 
Adjustments to reconcile net income to net cash        
   provided by operating activities:        
Depletion, depreciation and amortization  1,006   1,790 
Impairment of oil and gas properties  -   505 
Gain on sale of oil and gas properties  (2,599)  - 
Accretion expense  37   14 
Changes in assets and liabilities:        
Decrease in production receivable  493   827 
Decrease in other current assets  12   78 
Decrease in due to operators  (22)  (37)
Decrease in accrued expenses  (5)  - 
Net cash provided by operating activities  6,071   8,446 
         
Cash flows from investing activities        
Proceeds from sale of oil and gas properties  2,745   - 
Capital expenditures for oil and gas properties  (5,822)  (1,624)
Investments in salvage fund  (8)  (673)
Net cash used in investing activities  (3,085)  (2,297)
         
Cash flows from financing activities        
Distributions  (8,045)  (6,848)
Net cash used in financing activities  (8,045)  (6,848)
         
Net decrease in cash and cash equivalents  (5,059)  (699)
Cash and cash equivalents, beginning of year  8,521   9,220 
Cash and cash equivalents, end of year $3,462  $8,521 

The accompanying notes are an integral part of these financial statements.
 
 
RIDGEWOOD ENERGY W FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)

  Year ended December 31, 
  2016  2015 
       
Cash flows from operating activities      
Net loss $(1,285) $(6)
Adjustments to reconcile net loss to net cash        
   provided by operating activities:        
Depletion and amortization  1,629   625 
Impairment of oil and gas properties  -   142 
Accretion expense  144   90 
Amortization of debt discounts and deferred financing costs  70   - 
Changes in assets and liabilities:        
(Increase) decrease in production receivable  (725)  318 
(Increase) decrease in other current assets  (77)  36 
Increase (decrease) in due to operators  61   (170)
Increase in accrued expenses  317   129 
Net cash provided by operating activities  134   1,164 
         
Cash flows from investing activities        
Capital expenditures for oil and gas properties  (3,285)  (6,458)
Increase in salvage fund  (1)  (444)
Net cash used in investing activities  (3,286)  (6,902)
         
Cash flows from financing activities        
Long-term borrowings  3,755   5,650 
Distributions  -   (1,183)
Net cash provided by financing activities  3,755   4,467 
         
Net increase (decrease) in cash and cash equivalents  603   (1,271)
Cash and cash equivalents, beginning of year  2,191   3,462 
Cash and cash equivalents, end of year $2,794  $2,191 

The accompanying notes are an integral part of these financial statements.
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.transactions.  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.information and the management of the Fund’s investments in projects.  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 2, 3 4 and 5.4.

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,depletion and amortization, determination of proved reserves, impairmentsimpairment of long-lived assets 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 consistsconsist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments.  Level 3 valuationsinputs are derived fromunobservable inputs that are significant and unobservable;include situations where there is little, if any, market activity for the instrument; hence, these valuationsinputs 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 equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2016, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution.  AtAs of December 31, 2014,2016, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

Salvage Fund
The Fund deposits in a separate interest-bearing account, or salvage fund, moneycash 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, 2014 and 2013, the Fund had investments in federal agency mortgage-backed securities within its salvage fund that are classified as available-for-sale of $0.1 million and $0.3 million, respectively, which mature in January 2042.  Available-for-sale securities are carried in the financial statements at fair value.  At December 31, 2014 and 2013, 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 acquiring the debt (see Note 4.3. “Credit Agreement – Beta Project Financing”) 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, 2014 and 2013, $0.4 million and $0.6 million, respectively, ofdebt.  Unamortized debt discounts and deferred financing costs were unamortized.  Amortization expense was $0.1 million during eachare presented as a reduction of “Long-term borrowings” on the years ended December 31, 2014balance sheets (see Note 1. “Organization and 2013. Summary of Significant Accounting Policies - Recent Accounting Pronouncements”).

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” (see Note 3. “Credit Agreement – Beta Project Financing”).

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,Acquisition, exploration and 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.  CostsThe costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”  Exploratory costsexploratory wells are capitalized pending determination of whether proved reserves have been found.  If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs.  At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.

Interest costs related to the Credit Agreement (see Note 4.3. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity, transportation expense and workover efforts are expensed as incurred.

Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.

AtAs of December 31, 20142016 and 2013,2015, amounts recorded in due to operators totaling $1.1$0.6 million and $0.2 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 an oil and gas property 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 the estimated cash expenditures for the succeeding month’s operation. The Fund accountsexpenditures to the operator for such payments as advances to operators for working interestsits oil and expenditures.gas properties. As drillingthe 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. WhenUpon the determination that a project reaches drilling depth andproperty is determined to be either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation isin the period incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations forduring the years ended December 31, 20142016 and 2013.2015.

  2014  2013 
  (in thousands) 
Balance, beginning of year $1,503  $964 
Liabilities settled/conveyed  -   (171)
Accretion expense  37   14 
Revisions in estimated cash flows  -   696 
Balance, end of year $1,540  $1,503 
At December 31, 2013, the Fund’s balance sheet reflects the reclassification of the Raven Project’s asset retirement obligation from “Asset retirement obligation” to “Liability held for sale”.  On January 17, 2014, the Fund entered into an agreement to sell its interest in the Raven Project to a third party.
  2016  2015 
  (in thousands) 
Balance, beginning of year $2,815  $1,540 
Liabilities incurred  3   606 
Accretion expense  144   90 
Revision of estimates  (412)  579 
Balance, end of year $2,550  $2,815 

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.reasonably assured. The Fund uses the sales method of accounting for gas production imbalances.  The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties.  These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production.  The Fund’s recorded liability, if any, would be reflected in other liabilities.  No receivables are recorded for those wells where the Fund has taken less than its share of production.

Impairment of Long-Lived Assets
The Fund reviews the carrying value of its oil and gas properties wheneverannually and when 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 estimated future net undiscounted cash flows to the net bookcarrying value at the time of the review.  If the net bookcarrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the propertyasset is written down to fair value, which is determined using estimated future 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.asset.  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

Significant and consistent fluctuations in oil and natural gas prices decline significantly, even if only for a short periodsince fourth quarter 2014 have impacted the fair value of time, it is possible that write-downs ofthe Fund’s oil and gas properties could occur.

The Fund did not record an impairmentproperties. There were no impairments of oil and gas properties during the year ended December 31, 2014.2016. During the year ended December 31, 2013,2015, the Fund recorded an impairment of oil and gas properties of $0.5$0.1 million related to the Cobalt Project, which was attributable to both declines in future oil and gas prices and an increase in estimated asset retirement costs.revisions to reserve estimates as provided by the Fund’s independent petroleum engineers.  The fair value of the Cobalt Projectimpaired property at the date of impairment was $0.4$0.1 million.  Such amount was determined based on Level 3 inputs, which included projected income from reserves utilizing forward price curves, netIf oil and natural gas prices decline, even if only for a short period of anticipated costs, discounted.time, it is possible that additional impairments of oil and gas properties will occur.

Depletion Depreciation and Amortization
Depletion depreciation 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.facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs.  In certain circumstances, equipmentcosts and facilities costs are depreciated over the estimated useful life of the asset.to construct offshore platform and associated asset retirement 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.  The Fund files U.S. Federal and State tax returns and the 20102013 through 20132015 tax returns remain open for examination by tax authorities.

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.   During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $1.8 million.  There were no such distributions during the year ended December 31, 2013.

Recent Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs on the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset.  Amortization of debt issuance costs will continue to be reported as interest expense.  In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset.  These pronouncements became effective for fiscal years, and interim periods within those years, beginning after December 15, 2015.  The Fund has considered recentadopted the accounting guidance in first quarter 2016, resulting in a one-time reclassification of $0.3 million of unamortized debt discounts and deferred financing costs from “Other assets” to “Long-term borrowings” on the balance sheet as of December 31, 2015. The adoption of these pronouncements did not impact the Fund’s results of operations or cash flows.
In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and believes that these recent pronouncementslicensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Based on the Fund’s initial assessment of the accounting guidance, the Fund currently does not expect it will not have a material effectimpact on its results of operations or cash flows in the Fund’s financial statements.period after adoption. Under the accounting guidance, revenue is recognized as control transfers to the customer, as such the Fund expects the application of the accounting guidance to its existing contracts to be generally consistent with its current revenue recognition model. The Fund will continue the evaluation of the provisions of this accounting guidance, as well as new or emerging interpretations, as it relates to new contracts the Fund receives and in particular as it relates to disclosure requirements through the date of adoption, which is currently expected to be January 1, 2018.

2. Oil and Gas Properties

On January 17, 2014, the Fund, along with its affiliates, Ridgewood Energy Gulf of Mexico Oil and Gas Fund, L.P., Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy P Fund, LLC, and Ridgewood Energy Y Fund, LLC,  (when used with the Fund the “Ridgewood Funds”) entered into a purchase and sale agreement to sell the Ridgewood Funds’ interests in the Raven Project, located in the state waters of Louisiana, to Castex Energy Partners, L.P. for cash consideration totaling $21.7 million.  The closing of the sale transaction occurred on January 30, 2014.

The Fund had a 6.25% working interest in the Raven Project and received $2.7 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.1 million, thereby resulting in a gain to the Fund of $2.6 million, which was recognized during the year ended December 31, 2014.  There was no such amount recorded during the year ended December 31, 2013.

At December 31, 2013, the Fund’s balance sheet reflected the Raven Project’s cost and accumulated depletion classified as “Asset held for sale”, which totaled $0.3 million, and the Raven Project’s asset retirement obligation classified as “Liability held for sale”, which totaled $0.2 million.   Such asset was monetized and obligation was relieved upon the closing of the Raven Project’s sale.

3. Related Parties

Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund.  For such services, the Manager is paidentitled to 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.  In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments. Management fees forduring each of the years ended December 31, 20142016 and 20132015 were $1.0 million.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions from operations paid toThe Fund did not pay distributions during the Manager for each of the yearsyear ended December 31, 2014 and 2013 were $1.0 million.  In addition, the Manager is entitled to receive a 1% interest in cash distributions from dispositions.2016. Distributions from the sale of the Raven project paid to the Manager during the year ended December 31, 20142015 were $18 thousand.  There were$0.2 million.

None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.

In May 2015, Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager (the “Ridgewood Beta Funds”) to facilitate the transportation and sale of oil and gas produced from the Beta Project. On June 1, 2016, the Ridgewood Beta Funds entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from Ridgewood Beta Funds all of their interests in oil and gas produced at the Beta Project and sell such volumes to unrelated third party purchasers.

Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no such distributions duringbenefit or compensation for the year ended December 31, 2013.services provided under the master agreement or under any other agreement it enters into with regard to the oil and gas purchased from the Ridgewood Beta Funds. Ridgewood Beta Funds have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations.  These revenues and operating expenses allocable to the Fund are based on the Fund’s working interest ownership in the Beta Project.

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

None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
 
 
4.3. Credit Agreement – Beta Project Financing

In November 2012, the Fund entered into a credit agreement (the(as amended on September 30, 2016, 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,Certain other funds managed by 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.Funds. The Manager serves as the manager for each of the Ridgewood Participating Fund.Funds.  As of December 31, 2016, in accordance with the terms of the Credit Agreement, there will be no additional borrowings available to the Ridgewood Participating Funds.

TheAs of December 31, 2016 and 2015, the Fund anticipates it will borrow approximatelyhad borrowings of $9.4 million overand $5.7 million, respectively, under the development period of the Beta Project, which will bearCredit Agreement. The Loan bears interest at 8% compounded annually and accrue only on Loan proceeds as they are drawn.annually.  Principal and interest will not be payable until such time that initial production has commenced forare repaid at the Beta Project, which is currently expected in 2016. At that time, if certain revenue production levels are met, principal and interest will be repaid atlesser of (i) a monthly rate of 1.25% of the Fund’s total principal outstanding at the date the Beta Project commences productionas of July 31, 2016 for the first seven months of production,beginning October 2016, and increases to 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, and (ii) debt service amount as defined in the Credit Agreement, in no event later than December 31, 2020.  The Loan may be prepaid by the Fund without premium or penalty.

The unamortized debt discounts and deferred financing costs of $0.1 million as of December 31, 2016 and $0.3 million as of December 31, 2015 are presented as a reduction of “Long-term borrowings” on the balance sheets (see Note 1. “Organization and Summary of Significant Accounting Policies - Recent Accounting Pronouncements”).  Amortization expense of $0.1 million during each of the years ended December 31, 2016 and 2015 were capitalized and included on the balance sheet within “Oil and gas properties”. As a result of the Beta Project’s commencement of production in third quarter 2016, amortization expense during the year ended December 31, 2016 of $0.1 million was expensed and is included on the statement of operations within “Interest (expense) income, net”.

As of December 31, 20142016 and 2013,2015, interest costs of $0.4 million and $0.2 million, respectively, were capitalized and included on the Fund had no borrowings underbalance sheet within “Oil and gas properties”.  Such amounts were accrued on the Credit Agreement.balance sheet within “Accrued expenses” as of December 31, 2016 and 2015.  As a result of the Beta Project’s commencement of production in third quarter 2016, interest costs during the year ended December 31, 2016 of $0.3 million were expensed and are included on the statement of operations within “Interest (expense) income, net”.  Such amounts are accrued on the balance sheet within “Accrued expenses”.  Interest payments on the Loan of $0.1 million as of December 31, 2016 related to capitalized interest costs. Such amounts are included within cash flows from investing activities on the statements of cash flows.

As additional consideration to the Lenders, each Ridgewood Participatingthe Fund has agreed to convey an overriding royalty interest (“ORRI”) in theirits working interestsinterest in the Beta Project. Each Ridgewood ParticipatingProject to the Lenders.  The 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 percentageSuch ORRI to be grantedwill not accrue or become payable to the Lenders equals 12.24% ofuntil after 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.  Upon entering into the Credit Agreement, the Fund recorded the additional consideration as debt discounts and deferred financing costs at a fair value of $0.7 million, whichLoan is 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. 

repaid in full.  The Credit Agreement contains customary covenants, forwith which the Fund believes it was in compliance atas of December 31, 20142016 and 2013.2015.

5.4.   Commitments and Contingencies

Capital Commitments
The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas 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.

As of December 31, 2014,2016, the Fund’s estimated capital commitments related to its oil and gas properties were $16.1$7.9 million (which include asset retirement obligations for the Fund’s projects of $4.0 million and projected interest costs of $2.4 million for the Beta Project)$4.1 million), of which $5.0$3.3 million is expected to be spent during the year ending December 31, 2015. These expected capital commitments exceed available working capital and salvage fund by $12.0 million at December 31, 2014.  In November 2012,2017, which is primarily related to complete the Fund entered into a credit agreement that provides for an aggregate loan commitmentfinal phase of up to $9.4 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. PrincipalFuture results of operations and interest amountscash flows are contracted to be repaid upondependent on the onset ofcontinued successful development and the related production of oil and gas revenues from the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2020. See Note 4. “Credit Agreement – Beta Project Financing” for additional information.
Project.  Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations and borrowings to be sufficient to cover its commitments, borrowing repayments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s capital commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term capital commitments if needed.

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.  AtAs of December 31, 20142016 and 2013,2015, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund to record a liability.Fund’s financial statements.

During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore.  If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations.  It is not possible at this time to predict whether such legislation or regulation, if proposed, 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.

BOEM Notice to Lessees on Supplemental Bonding
On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees,  (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance.  The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured.  The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

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.  ClaimsDepending on the extent, nature and payment of claims made by the Fund or other funds managed by the Manager, can reduce or eliminateyearly insurance forcoverage may be exhausted and become insufficient to cover a claim by the Fund.Fund in a given year.
 
 
Ridgewood Energy W Fund, LLC
Supplementary Financial Information
Information about Oil and Gas Producing Activities – Unaudited

In accordance with the Financial Accounting Standards BoardFASB 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 the United States offshore waters of Louisiana in the Gulf of Mexico.


Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
  December 31, 
  2016  2015 
  (in thousands) 
Proved properties $39,513  $36,018 
   Total oil and gas properties  39,513   36,018 
Accumulated depletion and amortization  (17,453)  (15,824)
Oil and gas properties, net $22,060  $20,194 
 
  December 31, 
  2014  2013 
  (in thousands) 
Proved properties $21,629  $20,132 
Equipment and facilities - in progress  7,330   2,763 
   Total oil and gas properties  28,959   22,895 
Accumulated depletion, depreciation and amortization  (15,003)  (13,997)
Oil and gas properties, net $13,956  $8,898 

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

 Year ended December 31,  Year ended December 31, 
 2014  2013  2016  2015 
 (in thousands)  (in thousands) 
Exploration costs $(3) $(164) $28  $6 
Development costs  5,947   3,012   3,423   6,878 
 $5,944  $2,848  $3,451  $6,884 
 
 
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, 20142016 and 2013.2015.  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, 2014  December 31, 2013  December 31, 2016  December 31, 2015 
 United States  United States 
 Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Oil (BBLS)  NGL (BBLS)  Gas (MCF) 
                                    
Proved developed and undeveloped reserves:                  Proved developed and undeveloped reserves:  
Beginning of year  502,900   101,876   2,777,794   576,675   -   3,237,305   502,461   23,781   930,575   497,417   61,105   1,235,213 
Sales of minerals in place (a)
  (10,053)  (38,442)  (1,468,385)  -   -   - 
Revisions of previous estimates (b)
  78,015   8,434   111,277   (1,926)  125,034   95,680 
Revisions of previous estimates (a)
  (120,853)  30,809   25,531   56,723   (29,845)  (186,493)
Production  (73,445)  (10,763)  (185,473)  (71,849)  (23,158)  (555,191)  (59,218)  (6,221)  (101,076)  (51,679)  (7,479)  (118,145)
End of year  497,417   61,105   1,235,213   502,900   101,876   2,777,794   322,390   48,369   855,030   502,461   23,781   930,575 
                                                
Proved developed reserves:                                                
Beginning of year  83,538   69,333   1,222,476   158,590   -   1,815,830   86,127   23,781   618,324   78,942   61,105   921,356 
End of year  78,942   61,105   921,356   83,538   69,333   1,222,476   295,020   48,369   839,430   86,127   23,781   618,324 
                                                
Proved undeveloped reserves:                                                
Beginning of year  419,362   32,543   1,555,318   418,085   -   1,421,475   416,334   -   312,251   418,475   -   313,857 
End of year (c)
  418,475   -   313,857   419,362   32,543   1,555,318 
End of year  27,370   -   15,600   416,334   -   312,251 
 
(a)On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 6 thousand barrels and 33 thousand barrels, respectively and proved developed and undeveloped gas reserves of approximately 0.2 million mcf and 1.2 million mcf, respectively.

(b)Revisions of previous estimates were attributable to well performance.

(c)At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.
 
 
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 respectto 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, 
  2016  2015 
  (in thousands) 
Future cash inflows $13,871  $25,459 
Future production costs  (5,124)  (5,363)
Future development costs  (4,802)  (10,909)
Future net cash flows  3,945   9,187 
10% annual discount for estimated timing of cash flows  977   (1,920)
Standardized measure of discounted future net cash flows $4,922  $7,267 
  December 31, 
  2014  2013 
  (in thousands) 
Future cash inflows $51,303  $64,355 
Future production costs  (6,599)  (6,315)
Future development costs  (13,635)  (21,420)
Future ad valorem taxes  -   (150)
Future net cash flows (a)  31,069   36,470 
10% annual discount for estimated timing of cash flows  (8,464)  (13,272)
Standardized measure of discounted future net cash flows (a) $22,605  $23,198 
(a)On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $4.3 million and $3.1 million, respectively.



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, 
  2016  2015 
  (in thousands) 
Net change in sales and transfer prices and in production costs
 related to future production
 $(6,171) $(16,374)
Sales and transfers of oil and gas produced during the period  (2,001)  (1,977)
Changes in estimated future development costs  6,107   2,726 
Net change due to revisions in quantities estimates  (1,824)  (98)
Accretion of discount  727   2,260 
Other  817   (1,875)
Aggregate change in the standardized measure of discounted
 future net cash flows for the year
 $(2,345) $(15,338)

  Year ended December 31, 
  2014  2013 
  (in thousands) 
Net change in sales and transfer prices and in production costs
 related to future production
 $(4,006) $(3,687)
Sales and transfers of oil and gas produced during the period  (6,762)  (8,970)
Net change due to purchases and sales of minerals in place (a)
  (3,132)  - 
Changes in estimated future development costs  5,922   (136)
Net change due to revisions in quantities estimates  4,464   4,796 
Accretion of discount  2,320   2,842 
Other  601   (71)
Aggregate change in the standardized measure of discounted
 future net cash flows for the year
 $(593) $(5,226)
(a)On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $3.1 million.

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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