0001214659-11-000952.txt : 20110322 0001214659-11-000952.hdr.sgml : 20110322 20110322140113 ACCESSION NUMBER: 0001214659-11-000952 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20101231 FILED AS OF DATE: 20110322 DATE AS OF CHANGE: 20110322 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Ridgewood Energy W Fund LLC CENTRAL INDEX KEY: 0001409947 STANDARD INDUSTRIAL CLASSIFICATION: OIL AND GAS FIELD EXPLORATION SERVICES [1382] IRS NUMBER: 000000000 STATE OF INCORPORATION: DE FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-53177 FILM NUMBER: 11703586 BUSINESS ADDRESS: STREET 1: 947 Linwood Avenue CITY: Ridgewood STATE: NJ ZIP: 07450 BUSINESS PHONE: (201) 447-9000 MAIL ADDRESS: STREET 1: 947 Linwood Avenue CITY: Ridgewood STATE: NJ ZIP: 07450 10-K 1 b31511110k.htm FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010 b31511110k.htm
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, 2010
or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-53177
 
RIDGEWOOD ENERGY W FUND, LLC
(Exact name of registrant as specified in its charter)
 
Delaware
26-0225130
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)

14 Philips Parkway, Montvale, NJ  07645
(Address of principal executive offices) (Zip code)
 
(800) 942-5550
(Registrant’s telephone number, including area code)

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

Shares of LLC Membership Interest

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o   No x
 
There is no market for the shares of LLC Membership Interest in the Fund.  As of March 22, 2011 there are 332.2918 shares of LLC Membership Interest outstanding.
 
 
 
 

RIDGEWOOD ENERGY W FUND, LLC
2010 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
     
PAGE
       
PART I
      
  2
  11
  11
  11
  12
  12
PART II
      
  12
  12
  12
  17
  17
  17
  18
  18
PART III
      
  18
  20
  20
  20
  21
PART IV
      
  21
       
    SIGNATURES 22
 
 
FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy W Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections, statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995 that are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods.  Examples of events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations.  Examples of forward-looking statements made herein include statements regarding future projects, investments and insurance.  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.

WHERE YOU CAN GET MORE INFORMATION

The Fund files annual, quarterly and current reports and certain other information with the Securities and Exchange Commission (“SEC”). Persons may read and copy any materials the Fund files with the SEC at the SEC’s public reference room at 100 F Street, NE, Washington D.C. 20549, on official business days during the hours of 10 a.m. to 3 p.m. Eastern Time.  Information may be obtained from the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
 
 
 
 
 
 
 
PART I

ITEM 1.  BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on May 17, 2007 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on June 15, 2007, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  On January 31, 2011, pursuant to the LLC Agreement, Ridgewood Energy Corporation, as manager of the Fund, converted all then outstanding Investor GP Shares to Limited Liability Shares.  There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on December 17, 2007.  The Fund raised $66.0 million and after payment of $10.8 million in offering fees, commissions and investment fees, the Fund had $55.2 million for investments and operating expenses.

Manager

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

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

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 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.

As compensation for its services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund.  The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year.  Management fees for the years ended December 31, 2010 and 2009 were $1.4 million and $1.5 million, respectively.  Additionally, the Manager is entitled to receive a 15% interest in cash distributions made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2010 and 2009 were $0.9 million and $0.1 million, respectively.

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 stage shallow water or deepwater 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 invests 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.  Although the Fund’s focus is primarily on exploratory oil and natural gas projects, it also investigates and, if appropriate, invests in non-exploratory projects, such as producing projects and projects that have proven undeveloped reserves, some of which may need capital to construct, install or acquire the necessary infrastructure assets, such as rigs, pipelines or other equipment needed to gather, process and transport oil or natural gas.  Some of these non-exploratory projects may also contain probable or possible reserves, which could be a factor in the purchase price paid by the Fund to acquire such projects.  The Fund rigorously screens and evaluates non-exploratory projects using the same investment screening and selection process used for exploratory stage projects, although, depending on the nature and type of a non-exploratory project, additional or different evaluative tools and processes may be needed by the Fund when evaluating such projects.

 
Investment Strategy

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

Investment Process
Although Ridgewood Energy’s model of investing fund capital with operators affords it access to industry-leading technical and engineering resources, Ridgewood Energy performs its own due diligence on, and independently evaluates, all of the projects in which the Fund invests and all investment decisions are based on the collective analysis of the Ridgewood Energy management team.  The Ridgewood Energy management team conducts an initial screening process to identify new project investment opportunities utilizing their training, experience and industry relationships.  Ridgewood Energy is selective as to which projects it pursues.  Key criteria that form part of the detailed evaluation include the identity of the operator and other partners, the technical quality of the project, access to existing infrastructure, drilling schedule and rig availability and project economics and terms.

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

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

 
Project Information

Existing projects, and future projects, if any, are located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama, in state waters or 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 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. The 5-year lease term is for blocks in water depths generally less than 400 meters, 8 years for depths between 400 meters and 800 meters and 10 years for depths in excess of 800 meters. 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 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 16.67% or 18.75% royalty to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) (formerly the Mineral Management Services) for shallow-water projects, dependent upon the lease date, and a 12.5% royalty to the BOE for deepwater projects. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 83.33% of the total revenue for shallow-water projects and 87.5% of the total revenue for deepwater projects, and, such net revenue amount is further reduced by any other royalty burdens that apply to a lease block.  However, as described below, the BOE has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects.  Other than BOE royalties, the Fund does not have material royalty burdens.  In addition to the foregoing, the Fund’s working interests in leases located in state waters of the Gulf of Mexico, offshore Louisiana, pay a 25% royalty to the State of Louisiana.

Deep Gas Royalty Relief
On January 26, 2004, the BOE promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the "Royalty Relief Rule"). Under the Royalty Relief Rule, lessees are eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief is available for wells drilled and perforated deeper than 18,000 feet subsea. The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the Continental Shelf nor does it apply if the price of natural gas exceeds $10.57 (estimated) Million British Thermal Units (“mmbtu”) adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters.

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

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

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, 2010.  Productive wells are producing wells and wells capable of production.  Gross wells are the total number of wells in which the Fund has an interest.  Net wells are the sum of the Fund’s fractional working interests owned in the gross wells.  All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

   
Total Productive Wells
  
   
Gross
    
Net
  
Oil and natural gas
     5       0.52  
 
Acreage Data
The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 2010.  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
  
  21,522       2,441       6,806       226  

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

         
Total Spent
          
   
Working
    
through
    
Total Fund
    
Lease Block
  
Interest
    
December 31, 2010
    
Budget
  
Status
         
(in thousands)
    
Non-producing Properties
              
Beta Project
     3.0%     $ 1,691     $ 4,869  
Drilling commenced March 2010, suspended during the moratorium, and currently expected to resume in second half 2011.
Raven Project well #2
     6.25%     $ 99     $ 1,360  
Drilling commenced December 2010; discovery March 2011.
Producing Properties
                    
Raven Project well #1
     6.25%     $ 1,617     $ 1,617  
Well completed and production commenced September 2010.
Liberty Project
     12.0%     $ 13,442     $ 13,442  
Well completed and production commenced July 2010.
Cobalt Project
     5.0%     $ 2,366     $ 2,396  
Production commenced June 2009.  Minor recompletion in April 2010 at a cost of $9 thousand.  Additional recompletion activities planned at an estimated cost of $30 thousand.
Main Pass 283/279 well #1
     9.0%     $ 2,722     $ 2,722  
Production commenced in 2008.
West Cameron 57
     20.0%     $ 7,572     $ 7,572  
Production commenced in 2008.  Working interest conveyed to operator effective February 1, 2011.  See discussion below.
Dry Holes
                          
2010
                          
Dakota Project
     6.5%     $ 3,002       N/A  
Drilling commenced December 2009;
dry hole determination May 2010.
2009
                          
Bison Project
     4.0%     $ 485       N/A  
Drilling commenced December 2008;
dry hole determination January 2009.
Sold Property
                        
Ajax Project
     12.5%     $ 3,693       N/A  
Property sold in June 2010. See further discussion below.
 
Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in West Cameron 57 to Marlin Coastal, L.L.C. (“Marlin”), the operator of the well, in exchange for Marlin’s assumption of all future obligations and liabilities of the well.  During the year ended December 31, 2009, the Fund recorded an impairment of $6.8 million relating to West Cameron 57 as the Fund’s independent petroleum engineers did not assign any reserves to this well.  During the year ended December 31, 2010, and through the date of the conveyance agreement, the well continued to produce small amounts of oil and gas.

In June 2010, the Fund sold its interest in the Ajax Project to KNOC USA Corporation and Samsung Oil & Gas USA Corp., for net proceeds of $1.8 million in cash and estimated overriding royalty interest amounts, which resulted in a gain of $1.0 million.  At the time of the sale, the carrying value for the Ajax Project was $0.8 million.  During the year ended December 31, 2009, the Fund recorded an impairment charge of $2.9 million relating to the Ajax Project, after evaluating its options for completion of the well given its estimate of market conditions.  The carrying value for the Ajax Project prior to the impairment charge was $3.7 million.  At the time of the impairment, the fair value of the well was determined based on level 3 inputs, which include projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.

In April 2010, the Deepwater Horizon, which was drilling a BP-operated project in the deepwater of the Gulf of Mexico, sank after an apparent blowout and fire.  As of the date of this filing, the well has been permanently capped and environmental remediation efforts are ongoing. Neither the Fund nor any operators of the Fund’s projects owns an interest in the affected field.  As a result of the explosion and resultant oil spill, the U.S. government placed a six-month moratorium on deepwater drilling operations in the Gulf of Mexico, which was lifted effective October 12, 2010.  The U.S. government has also implemented additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico.  The extent to which these recent events may impact the Fund’s future results is uncertain.  The Fund cannot predict how federal and state authorities will further respond to the incident or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result.  Such changes, if any, may impact the way the Fund conducts business and may increase the Fund’s cost of doing business.

 
Marketing/Customers

During 2010, the Fund had engaged a third-party marketer to sell the Fund’s proportionate share of oil and natural gas to the public market.  The Fund did not contract to sell oil and natural gas to customers and therefore, had no customers or any one or few major customers upon which it depends.  Effective December 2010, the Fund sells its oil and gas through an agent, Energy Upgrade, Inc.  

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

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

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

The Fund’s properties are located in the Gulf of Mexico; therefore its operations and cash flows may be significantly impacted by hurricanes and other inclement weather.  Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any damage or shut-ins, or production stoppages, due to hurricane activity in 2010.

Operator

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's producing properties are operated by LLOG Exploration Offshore, Inc., Marlin Coastal, L.L.C., Newfield Exploration Company, Phoenix Exploration Company LP and W&T Offshore, Inc.

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

 
Insurance

The Manager has obtained what it believes to be adequate insurance for the funds that it manages.  The Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to the projects.  Further, for the policy period August 2009 through July 2010, the Manager did not obtain coverage for named windstorm.  As a result of the losses underwriters incurred from claims arising from Hurricane Ike, a named windstorm in September 2008, the Manager determined that the premiums sought by underwriters for, and the deductibles applicable to, coverage for named windstorm made obtaining such coverage for such policy period prohibitively expensive. For the policy period August 2010 through July 2011, the Fund, through its operator, obtained windstorm coverage for the Liberty Project.  In addition, the Manager's past practice has been to obtain insurance as a package that is intended to cover most, if not all, of the funds under its management.  The Manager re-evaluates the insurance coverage on an annual basis.  While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the incident, that insurance coverage may not be sufficient to cover all losses.  In addition, depending on the extent, nature and payment of any claims to the Fund's affiliates, yearly insurance limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.

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

Competition

Strong competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. Although the Fund does not compete for lease acquisitions from the BOE, it does compete with other companies for the acquisition of percentage ownership interests in oil and natural gas working interests in the secondary market.

In many instances, the Fund competes for projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position that they could outbid the Fund for a project. However, because these companies are larger and have significant resources, they tend to focus more on projects that are larger, have greater reserve potential, and cost significantly more to explore and develop.  The focus of these companies on larger projects does not necessarily mean that they will not investigate and/or acquire projects for which the Fund typically competes.  The Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, (ii)  Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint, and (iii) Ridgewood Energy is typically not viewed as a competitor by the syndicating operator, as Ridgewood Energy does not participate in lease block sales but principally invests in drill-ready syndicated projects.
 
Employees

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

The principal executive office of each of 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 11700 Old Katy Road, Houston, TX 77079.  In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.
 
Regulation

Oil and natural gas exploration, development and production activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled and the plugging and abandoning of projects are also subject to regulations.

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

Outer Continental Shelf Lands Act

Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOE, an agency of the United States Department of Interior. The BOE administers federal offshore leases pursuant to regulations promulgated under the OCSLA. Lessees must obtain BOE approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency.  The Fund is not involved in the process of obtaining any such approvals or permits. Offshore operations are subject to numerous regulatory requirements, including stringent engineering and construction specifications related to offshore production facilities and pipelines and safety-related regulations concerning the design and operating procedures of these facilities and pipelines. BOE regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

The BOE has also imposed regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Under certain circumstances, the BOE may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect the Fund’s operations and interests.

The BOE conducts auctions for lease blocks of submerged areas offshore. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the duration of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a limited degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.
 
Sales and Transportation of Oil and Natural Gas

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

 
Environmental Matters and Regulation

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

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

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

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

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

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

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

The above represents a brief outline of the significant environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated thereunder.  The Fund does not believe that the costs of compliance with applicable environmental laws, including federal, state and local laws, will have a material adverse impact on its financial condition and/or operations.

 
ITEM 1A.  RISK FACTORS

Not required.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.  PROPERTIES

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

Drilling Activity
The following table sets forth the Fund’s drilling activity for the years ended December 31, 2010 and 2009.  Gross wells are the total number of wells in which the Fund has an interest.  Net wells are the sum of the Fund’s fractional working interests owned in the gross wells.  All of the wells are located in the offshore waters of the Gulf of Mexico.  During the years ended December 31, 2010 and 2009, the Fund had no drilling activity for developmental wells.  See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about wells in-progress at December 31, 2010.

   
2010
    
2009
  
   
Gross
    
Net
    
Gross
    
Net
  
Exploratory wells:
                        
Productive
     2       0.18       1       0.05  
Nonproductive
     1       0.07       1       0.04  
In-progress
     2       0.09       4       0.37  
Exploratory well total
     5       0.34       6       0.46  

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

The Fund’s reserve estimates at December 31, 2010 and 2009 were prepared by Ryder Scott Company, L.P., (“Ryder Scott”) an independent petroleum engineering firm.  The information regarding the qualifications of the petroleum engineer is included within the report from Ryder Scott, which is included as Exhibit 99 of this Annual Report, and is incorporated herein by reference.

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

 
Proved Undeveloped Reserves. At December 31, 2010, the Fund had approximately 4 thousand barrels and 561 thousand mcf of proved undeveloped oil and natural gas reserves, respectively. These proved undeveloped reserves are related to the Raven Project.  The Fund will evaluate the development alternatives for the Raven Project’s proved undeveloped reserves upon the depletion of its current productive well, which is currently expected in late-2013.  At December 31, 2009, the Fund had approximately 51 thousand barrels and 804 thousand mcf of proved undeveloped oil and natural gas reserves, respectively, related to the Liberty Project, which commenced production in July 2010.

Production and Prices
The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, 2010 and 2009 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 – Oil and Gas Revenue” and “Results of Operations – Operating Expenses” is incorporated herein by reference. 

Delivery Commitments
As of December 31, 2010, the Fund had no obligations or delivery commitments under any existing contracts.

ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4.  (REMOVED AND RESERVED)

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is currently no established public trading market for the Shares. As of the date of this filing, there were 811 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement.  At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders.  There is, however, no requirement to distribute available cash and as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 2010 and 2009, the Fund paid distributions totaling $7.3 million and $1.0 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 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 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 shallow water or deepwater oil and natural gas projects.  However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.

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

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

 
Critical Accounting Estimates
The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).  In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented.  The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows.  See Note 2 of Notes to Financial Statements – “Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of the Fund’s significant accounting policies.

Accounting for Exploration, Development and Acquisition Costs
Exploration and production activities 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. Annual lease rentals, exploration expenses and dry-hole costs are expensed as incurred. Costs of drilling and equipping productive wells and related production facilities are capitalized.

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

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

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

Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired.  When a project reaches drilling depth and is determined to be either proved or dry, a liability is recognized for the present value of asset retirement obligations once reasonably estimable.  The Fund capitalizes the associated asset retirement costs as part of the carrying amount of its proved properties.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.
 
Impairment of Long-Lived Assets
The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the end of each period.  If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property.  Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.  The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred.  Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term.  If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, 2010 and 2009, 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,
  
   
2010
    
2009
  
   
(in thousands)
  
             
Revenue
            
Oil and gas revenue
   $ 11,695     $ 1,948  
Expenses
                
Depletion and amortization
     3,522       3,061  
Dry-hole costs
     2,973       175  
Impairment of oil and gas properties
     -       9,704  
Management fees to affiliate
     1,406       1,470  
Operating expenses
     1,102       274  
General and administrative expenses
     490       571  
Total expenses
     9,493       15,255  
Gain on sale of oil and gas properties
     1,029       -  
Income (loss) from operations
     3,231       (13,307 )
Other income
                
Interest income
     29       101  
Net income (loss)
   $ 3,260     $ (13,206 )

Overview.  The Fund’s revenue, depletion and amortization, and lease operating expense were affected by the timing of the onset of production of the Fund’s wells.  During the year ended December 31, 2010, the Fund had five wells that produced for a total of 1,193 days, compared to three wells that produced for a total of 726 days during the year ended December 31, 2009.  The increase in total production days resulted from the onset of production for the Liberty and Raven projects, which commenced in July 2010 and September 2010, respectively.  During the year ended December 31, 2010, the Fund’s wells’ production rate averaged 1,197 mcfe/producing day, compared to 535 mcfe/producing day during the year ended December 31, 2009.  The increase was primarily related to the Liberty and Raven projects coupled with improved production for the Cobalt Project, which underwent a minor re-completion in April 2010.  Effective February 1, 2011, the Fund entered into an agreement to convey its working interest in West Cameron 57 to the operator of the well.  See Note 9 of Notes to Financial Statements – “Subsequent Events” in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for additional information.

Oil and Gas Revenue.   Oil and gas revenue for the year ended December 31, 2010 was $11.7 million, a $9.7 million increase from the year ended December 31, 2009.  The increase is attributable to an increase in sales volumes totaling $5.2 million coupled with the impact of increased average prices totaling $4.6 million.

Oil sales volumes were 100 thousand barrels and 13 thousand barrels for the years ended December 31, 2010 and 2009, respectively.  The Fund’s oil prices averaged $79 per barrel compared to $59 per barrel during the years ended December 31, 2010 and 2009, respectively.

 
Gas sales volumes were 652 thousand mcf and 256 thousand mcf for the years ended December 31, 2010 and 2009, respectively.  The Fund’s gas prices averaged $4.12 per mcf compared to $3.70 per mcf during the years ended December 31, 2010 and 2009, respectively.

The increases in oil and gas volumes were the result of the timing of the onset of production for the Fund’s producing wells and increased production rates for the Cobalt Project, as discussed in “Overview” above.

Depletion and Amortization.  Depletion and amortization for the year ended December 31, 2010 was $3.5 million, an increase of $0.5 million from the year ended December 31, 2009.  The increase resulted from an increase in production volumes totaling $8.2 million, partially offset by a decrease in average depletion rates totaling $7.7 million.  The decrease in the depletion rates was primarily due to the composite of productive wells coupled with an increase to reserve estimates for Main Pass 283/279 well #1.

Dry-hole Costs.   Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well.  At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.  Dry-hole costs, inclusive of such credits, are detailed in the following table:
 
   
Year ended December 31,
  
Lease Block
  
2010
    
2009
  
   
(in thousands)
  
             
Dakota Project
   $ 3,002     $ -  
Bison Project
     8       191  
Other wells
     (37 )     (16 )
    $ 2,973     $ 175  
 
Impairment of Oil and Gas Properties.  During the year ended December 31, 2009, the Fund recorded impairments of oil and gas properties totaling $9.7 million.  The Fund recorded an impairment charge of $6.8 million related to West Cameron 57 based upon the independent petroleum engineer’s assessment that such well was fully depleted.  Additionally, the Fund recorded an impairment charge of $2.9 million related to the Ajax Project, upon evaluation of its completion options given the market conditions at that time.  There were no impairments recorded during the year ended December 31, 2010.

Management Fees to Affiliate.   Management fees for the years ended December 31, 2010 and 2009 were $1.4 million and $1.5 million, respectively.   An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.

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

   
Year ended December 31,
  
   
2010
    
2009
  
   
(in thousands)
  
             
Lease operating expense
   $ 975     $ 232  
Geological costs
     103       31  
Accretion expense
     24       15  
Workover credits
     -       (4 )
    $ 1,102     $ 274  

Lease operating expense was related to the Fund’s producing properties during each year as outlined above in “Overview”.  During the year ended December 31, 2010, the average production cost was $0.68 per mcfe compared to $0.60 per mcfe for the year ended December 31, 2009.  Geological costs represent costs incurred to obtain seismic data, surveys and lease rentals for the Fund’s projects.  Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.  Workover expenses represent costs to restore or stimulate production of existing reserves of a proved property. 

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

 
   
Year ended December 31,
  
   
2010
    
2009
  
   
(in thousands)
  
             
Insurance expense
   $ 290     $ 367  
Accounting fees
     185       166  
Trust fees and other
     15       38  
    $ 490     $ 571  

Insurance expense represents premiums related to producing well and control of well insurance, which varies dependent upon the number of wells producing or drilling and directors’ and officers’ liability insurance.  Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

Gain on Sale of Oil and Gas Properties.  During the year ended December 31, 2010, the Fund recorded a gain on sale of oil and gas properties of $1.0 million, related to the Ajax Project, which had been impaired during the year ended December 31, 2009.  There were no such amounts recorded during the year ended December 31, 2009.  See Item 1. “Business” of this Annual Report under the heading “Properties” for further discussion of the sale of the Ajax Project.

Interest Income.        Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities.  Interest income for the year ended December 31, 2010 was $29 thousand, a $0.1 million decrease from the year ended December 31, 2009.  The decrease was the result of a reduction in average outstanding balances earning interest, due to ongoing capital expenditures for oil and gas properties, coupled with lower interest rates earned.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the year ended December 31, 2010 were $6.7 million, primarily related to revenue received of $9.5 million, partially offset by management fees of $1.4 million, operating expenses paid of $0.7 million and general and administrative expenses paid of $0.7 million.

Cash flows used in operating activities for the year ended December 31, 2009 were $42 thousand, primarily related to management fees of $1.5 million, general and administrative expenses paid of $0.3 million and operating expenses of $0.3 million, partially offset by revenue received of $1.9 million and interest income received of $0.1 million.

Investing Cash Flows
Cash flows provided by investing activities for the year ended December 31, 2010 were $1.2 million, primarily related to proceeds from the maturity of U.S. Treasury securities of $17.0 million coupled with the proceeds from the sale of the Ajax property of $1.8 million, partially offset by investments in U.S. Treasury securities of $12.0 million and capital expenditures for oil and gas properties of $5.6 million.

Cash flows used in investing activities for the year ended December 31, 2009 were $12.3 million, primarily related to investments in U.S. Treasury securities of $25.0 million and capital expenditures for oil and gas properties of $15.4 million, inclusive of advances to operators, partially offset by proceeds from the maturity of U.S. Treasury securities of $28.1 million.

Financing Cash Flows
Cash flows used in financing activities for the year ended December 31, 2010 were $7.3 million related to manager and shareholder distributions.

Cash flows used in financing activities for the year ended December 31, 2009 were $1.0 million related to manager and shareholder distributions.

 
Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investment properties.  The estimated capital expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis.  As of December 31, 2010, the Fund had committed to spend an additional $4.5 million related to its investment properties, of which $2.7 million is expected to be spent during the next twelve months.

When the Manager makes a decision to participate in an exploratory project, it assumes that the well will be successful and allocates enough capital to budget for the completion of that well and the additional development wells and infrastructure anticipated.  If an exploratory well is deemed a dry hole or if it is determined by the Manager to be un-economical, the capital allocated to the completion of that well and to the development of additional wells is then reallocated to a new project or used to make additional investments.

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

Liquidity Needs

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

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

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

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at December 31, 2010 and 2009 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators.  On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities.  The Fund does not negotiate such contracts.  No contractual obligations exist at December 31, 2010 and 2009 other than those discussed in “Estimated Capital Expenditures” above.
 
Recent Accounting Pronouncements
 
See Note 3 of Notes to Financial Statements – “Recent Accounting Standards” in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of recent accounting pronouncements.

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.
 
ITEM 8.        FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
 
All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits, Financial Statement Schedules” and filed as part of this report.
 
ITEM 9.        CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
None.

 
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, 2010.  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, 2010.  In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework. Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2010, 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, 2010 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

The Fund has engaged Ridgewood Energy as the Manager.  The Manager has very broad authority, including the authority to appoint the executive officers of the Fund.  Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 2010 are as follows:
 
 
         
Officer of
         
Ridgewood Energy
   
Name, Age and Position with Registrant
  
Corporation Since
           
 
Robert E. Swanson, 63
    
   
Chief Executive Officer
  
1982
           
 
Kenneth W. Lang, 56
    
   
President and Chief Operating Officer
  
2009
           
 
Kathleen P. McSherry, 45
    
   
Executive Vice President and
    
     
Chief Financial Officer
  
2001
           
 
Robert L. Gold, 52
    
   
Executive Vice President
  
1987
           
 
Daniel V. Gulino, 50
    
   
Senior Vice President and General Counsel
  
2003

The officers in the above table have also been officers of the Fund since May 17, 2007, the date of inception of the Fund, with the exception of Mr. Lang who has been an officer of Ridgewood Energy and the Fund since June 2009.  The officers are employed by and paid exclusively by the Manager.  Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

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

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

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

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

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

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

 
Code of Ethics
The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on our 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, 2010, all filing requirements applicable to its officers, directors and 10% beneficial owners were met.

ITEM 11.     EXECUTIVE COMPENSATION

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

 
ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 332.2918 shares outstanding at March 22, 2011. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.
 
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
 
The LLC Agreement provides that the Manager render management, administrative and advisory services.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for the years ended December 31, 2010 and 2009 were $1.4 million and $1.5 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2010 and 2009 were $0.9 million and $0.1 million, respectively.

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

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

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
 
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 for the years ended December 31, 2010 and 2009.
 
   
Year ended December 31,
  
   
2010
    
2009
  
   
(in thousands)
  
Audit fees (1)
   $ 130     $ 130  
Audit-related fees (2)
     -       3  
    $ 130     $ 133  
 
(1)
Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.
(2)
Fees for consultations regarding the Fund’s disclosure controls and procedures in accordance with Section 906 of the Sarbanes-Oxley Act of 2002.

PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) (1)     Financial Statements

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

(a) (2)     Financial Statement Schedules

None.

(a) (3)    
        
         
EXHIBIT
        
NUMBER
  
TITLE OF EXHIBIT
  
METHOD OF FILING
         
3.1
  
Certificate of Formation of Ridgewood Energy W Fund, LLC dated May 17, 2007
  
Incorporated by reference to the Fund's Form 10 filed on April 18, 2008
         
3.2
  
Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy W Fund, LLC dated June 15, 2007
Incorporated by reference to the Fund's Form 10 filed on April 18, 2008
         
14
  
Code of Ethics
  
Filed herewith
         
31.1
  
Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
Filed herewith
         
31.2
  
Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
Filed herewith
         
32
  
Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund
Filed herewith
         
99
  
Report of Ryder Scott Company, L.P.
  
Filed herewith
 
 

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 22, 2011
By:
/s/ ROBERT E. SWANSON   
    Robert E. Swanson  
    Chief Executive Officer  
   
(Principal Executive Officer)
  
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
Capacity
Date
   
 
March 22, 2011
/s/ ROBERT E. SWANSON
Chief Executive Officer
  (Principal Executive Officer)
Robert E. Swanson
  
     
     
/s/ KATHLEEN P. MCSHERRY
 Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
March 22, 2011
Kathleen P. McSherry
  
     
RIDGEWOOD ENERGY CORPORATION
    
     
BY:  /s/ ROBERT E. SWANSON
 Chief Executive Officer of Manager
March 22, 2011
Robert E. Swanson
    
     
 
 
 
 
 
 
 
 

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, 2010 and 2009, and the related statements of operations, changes in members’ capital, and cash flows for the years ended December 31, 2010 and 2009.  These financial statements are the responsibility of the Fund's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Fund's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures, in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy W Fund, LLC as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years ended December 31, 2010 and 2009, in conformity with accounting principles generally accepted in the United States of America.


/s/ Deloitte & Touche LLP

Parsippany, New Jersey
March 22, 2011
 
 
 
 
 
 
RIDGEWOOD ENERGY W FUND, LLC
  
BALANCE SHEETS
  
(in thousands, except share data)
  
             
   
December 31,
  
   
2010
    
2009
  
ASSETS
            
Current assets:
            
Cash and cash equivalents
   $ 4,237     $ 3,671  
Short-term investments in marketable securities
     5,000       9,999  
Production receivable
     2,434       202  
Other current assets
     145       19  
Total current assets
     11,816       13,891  
Salvage fund
     1,083       1,062  
Oil and gas properties:
                
Advances to operators for working interests and expenditures
     -       2,520  
Unproved properties
     1,791       4,794  
Proved properties
     20,725       17,491  
Less: accumulated depletion and amortization
     (6,089 )     (5,430 )
Total oil and gas properties, net
     16,427       19,375  
Total assets
   $ 29,326     $ 34,328  
                 
LIABILITIES AND MEMBERS' CAPITAL
                
Current liabilities:
                
Due to operators
   $ 481     $ 1,306  
Accrued expenses
     126       370  
Total current liabilities
     607       1,676  
Asset retirement obligations
     905       775  
Total liabilities
     1,512       2,451  
Commitments and contingencies (Note 8)
                
                 
Members' capital:
                
Manager:
                
Distributions
     (1,015 )     (162 )
Retained earnings (accumulated deficit)
     688       (582 )
Manager's total
     (327 )     (744 )
                 
Shareholders:
                
Capital contributions (625 shares authorized;
                
332.2918 shares issued and outstanding)
     65,965       65,965  
Syndication costs
     (7,823 )     (7,823 )
Distributions
     (7,391 )     (921 )
Accumulated deficit
     (22,610 )     (24,600 )
Shareholders' total
     28,141       32,621  
Total members' capital
     27,814       31,877  
Total liabilities and members' capital
   $ 29,326     $ 34,328  
                 
                 
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,
  
   
2010
    
2009
  
             
Revenue
            
Oil and gas revenue
   $ 11,695     $ 1,948  
Expenses
                
Depletion and amortization
     3,522       3,061  
Dry-hole costs
     2,973       175  
Impairment of oil and gas properties
     -       9,704  
Management fees to affiliate (Note 6)
     1,406       1,470  
Operating expenses
     1,102       274  
General and administrative expenses
     490       571  
Total expenses
     9,493       15,255  
Gain on sale of oil and gas properties
     1,029       -  
Income (loss) from operations
     3,231       (13,307 )
Other income
                
Interest income
     29       101  
Net income (loss)
   $ 3,260     $ (13,206 )
                 
                 
Manager Interest
                
Net income (loss)
   $ 1,270     $ (172 )
                 
Shareholder Interest
                
Net income (loss)
   $ 1,990     $ (13,034 )
Net income (loss) per share
   $ 5,989     $ (39,225 )
                 
                 
The accompanying notes are an integral part of these financial statements.
  
 
RIDGEWOOD ENERGY W FUND, LLC
  
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
  
(in thousands, except share data)
  
                         
                         
   
# of Shares
    
Manager
    
Shareholders
    
Total
  
                         
Balances, December 31, 2008
     332.2918     $ (429 )   $ 46,468     $ 46,039  
Distributions
     -       (143 )     (813 )     (956 )
Net loss
     -       (172 )     (13,034 )     (13,206 )
Balances, December 31, 2009
     332.2918       (744 )     32,621       31,877  
Distributions
     -       (853 )     (6,470 )     (7,323 )
Net income
     -       1,270       1,990       3,260  
Balances, December 31, 2010
     332.2918     $ (327 )   $ 28,141     $ 27,814  
                                 
                               
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,
  
   
2010
    
2009
  
             
Cash flows from operating activities
            
Net income (loss)
   $ 3,260       (13,206 )
Adjustments to reconcile net income (loss) to net cash
                
  provided by (used in) operating activities:
                
Depletion and amortization
     3,522       3,061  
Dry-hole costs
     2,973       175  
Impairment of oil and gas properties
     -       9,704  
Accretion expense
     24       15  
Gain on sale of oil and gas properties
     (1,029 )     -  
Interest earned on marketable securities
     (7 )     (70 )
Changes in assets and liabilities:
                
Increase in production receivable
     (2,232 )     (43 )
(Increase) decrease in other current assets
     (12 )     83  
Increase in due to operators
     351       27  
(Decrease) increase in accrued expenses
     (197 )     212  
Net cash provided by (used in) operating activities
     6,653       (42 )
                 
Cash flows from investing activities
                
Payments to operators for working interests and expenditures
     -       (2,520 )
Capital expenditures for oil and gas properties
     (5,562 )     (12,900 )
Proceeds from sale of oil and gas properties
     1,813       -  
Proceeds from the maturity of marketable securities
     17,007       28,096  
Investments in marketable securities
     (12,001 )     (24,994 )
Interest reinvested in salvage fund
     (21 )     (20 )
Net cash provided by (used in) investing activities
     1,236       (12,338 )
                 
Cash flows from financing activities
                
Distributions
     (7,323 )     (956 )
Net cash used in financing activities
     (7,323 )     (956 )
Net increase (decrease) in cash and cash equivalents
     566       (13,336 )
Cash and cash equivalents, beginning of year
     3,671       17,007  
Cash and cash equivalents, end of year
   $ 4,237     $ 3,671  
                 
Supplemental schedule of non-cash investing activities
                
Advances used for capital expenditures in oil and gas properties
                
  reclassified to dry-hole costs and proved properties
   $ 2,520     $ 169  
                 
                 
The accompanying notes are an integral part of these financial statements.
  
 
 
RIDGEWOOD ENERGY W FUND, LLC
NOTES TO FINANCIAL STATEMENTS

1.   Organization and Purpose

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.  The Fund was organized 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 Manager has direct and exclusive control over the management of the Fund’s operations.  With respect to project investments, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions in which the investments are made.  The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations.  Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information.  In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations.  The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 6 and 8.

2.   Summary of Significant Accounting Policies

Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period.  On an ongoing basis, the Manager reviews its estimates, including those related to property balances, determination of proved reserves, impairments and asset retirement obligations.  Actual results may differ from those estimates.
      
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents.  At times, deposits may be in excess of federally insured limits.  Federally insured limits of the Fund’s deposits are $250 thousand per insured financial institution.  At December 31, 2010, the Fund’s bank balances exceeded federally insured limits by $2.4 million, of which $1.9 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Investments in Marketable Securities
At times, the Fund may invest in U.S. Treasury bills and notes.  These investments are considered short-term when their maturities are one year or less, and long-term when their maturities are greater than one year.  The Fund currently has short-term investments that are classified as held-to-maturity.  Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value.  At December 31, 2010, the Fund had short-term, held-to-maturity investments of $5.0 million, which mature in May 2011.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.

Salvage Fund
The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations.  At December 31, 2010, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity totaling $1.0 million, which mature in February 2012. Interest earned on the account will become part of the salvage fund.  There are no restrictions on withdrawals from the salvage fund.

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.
 
 
The successful efforts method of accounting for oil and gas producing activities is followed.  Acquisition costs are capitalized when incurred.  Other oil and gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves.  If proved commercial reserves have not been found, exploratory drilling costs are expensed as dry-hole costs.  Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of oil and gas, are capitalized.  Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred.
 
Upon the sale or retirement of a proved property, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized.
 
Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.
 
At December 31, 2010 and 2009, amounts recorded in due to operators totaling $0.1 million and $1.2 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 a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest.  The Fund may be required to advance its share of estimated cash expenditures for the succeeding month’s operation.  The Fund accounts for such payments as advances to operators for working interests and expenditures.  As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired.  When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  The following table presents changes in asset retirement obligations for the years ended December 31, 2010 and 2009.
   
2010
    
2009
  
   
(in thousands)
  
             
Balance - Beginning of year
   $ 775     $ 550  
Liabilities incurred
     106       43  
Accretion expense
     24       15  
Revisions to previous estimates
     -       167  
Balance - End of year
   $ 905     $ 775  

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

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

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

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

The Fund did not record any impairments during the year ended December 31, 2010.  During the year ended December 31, 2009, the Fund recorded impairments of oil and gas properties totaling $9.7 million.  The Fund recorded an impairment charge of $6.8 million related to West Cameron 57 based upon the independent petroleum engineer’s assessment that such well was fully depleted.  Additionally, the Fund recorded an impairment charge of $2.9 million relating to the Ajax Project, after evaluation of its completion options given the market conditions at that time.  The carrying value for the Ajax Project of $3.7 million was written down to its fair value of $0.8 million, which was determined based on level 3 inputs, which include projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.  During 2010, the Fund sold its interest in the Ajax Project. See Note 4 for additional discussion on the sale of the Ajax Project.

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

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

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

3.   Recent Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements.  This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective beginning January 1, 2010.  The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, which will be effective for the Fund December 31, 2011. The adoption of the guidance is not expected to have a material impact on the Fund’s financial statements.

4.   Oil and Gas Properties
 
Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves.  Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves.  At December 31, 2010, the Fund had no projects with capitalized exploratory well costs in excess of one year.  The following table reflects the net changes in unproved properties for the years ended December 31, 2010 and 2009.
 
 
   
2010
    
2009
  
   
(in thousands)
  
             
Balance - Beginning of year
   $ 4,794     $ 1,971  
Additions to capitalized exploratory well costs
                
  pending the determination of proved reserves
     1,970       4,942  
Reclassifications to proved properties based on
                
  the determination of proved reserves
     (4,848 )     (2,119 )
Capitalized exploratory well costs charged to
                
  expense
     (125 )     -  
Balance - End of year
   $ 1,791     $ 4,794  

During June 2010, the Fund sold its interest in the Ajax Project to KNOC USA Corporation and Samsung Oil & Gas USA Corp., for net proceeds of $1.8 million in cash and estimated overriding royalty interest amounts, which resulted in a gain of $1.0 million.  At the time of the sale, the carrying value for the Ajax Project was $0.8 million as a result of a prior year impairment. See Note 2 for further discussion of impairment charges.

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field.  At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.  Dry-hole costs, inclusive of such credits, are detailed in the following table.
 
   
Year ended December 31,
  
Lease Block
  
2010
    
2009
  
   
(in thousands)
  
             
Dakota Project
   $ 3,002     $ -  
Bison Project
     8       191  
Other wells
     (37 )     (16 )
    $ 2,973     $ 175  
 
 
5.   Distributions
 
Distributions to shareholders are allocated in proportion to the number of shares held. Certain shares have early investment incentive and advance distribution rights, as defined in the LLC Agreement, which range from approximately $8 thousand to $16 thousand per share. The Fund began making distributions to eligible early investors in 2008 and to all investors in October 2010.

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.

6.   Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for the years ended December 31, 2010 and 2009 were $1.4 million and $1.5 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2010 and 2009 were $0.9 million and $0.1 million, respectively.

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

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

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.

7.   Fair Value Measurements

At December 31, 2010 and 2009, cash and cash equivalents, short-term investments in marketable securities, production receivable, salvage fund and accrued expenses approximate fair value.

8.   Commitments and Contingencies

Capital Commitments
The Fund has entered into multiple agreements for the drilling and development of its investment properties.  The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis.  As of December 31, 2010, the Fund had committed to spend an additional $4.5 million related to its investment properties, of which $2.7 million is expected to be spent during the next twelve months.

Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems.  The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry.  However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims.  At December 31, 2010 and 2009, there were no known environmental contingencies that required the Fund to record a liability.

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

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

9.   Subsequent Events

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

Ridgewood Energy W Fund, LLC
Supplementary Financial Information
Information about Oil and Gas Producing Activities – Unaudited

 
In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are currently 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,
  
   
2010
    
2009
  
   
(in thousands)
  
Advances to operators for working interests and expenditures
   $ -     $ 2,520  
Unproved properties
     1,791       4,794  
Proved properties
     20,725       17,491  
   Total oil and gas properties
     22,516       24,805  
Accumulated depletion and amortization
     (6,089 )     (5,430 )
Oil and gas properties, net
   $ 16,427     $ 19,375  
                 
                 
                 
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
  
                 
   
Year ended December 31,
  
      2010       2009  
   
(in thousands)
  
Exploration costs
   $ 1,413     $ 7,727  
Development costs
     3,066       5,347  
    $ 4,479     $ 13,074  
 
 
 
 

 
 
Table III - Reserve Quantity Information
                        
                         
Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer, Ryder Scott Company, L.P. at December 31, 2010 and 2009. 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, 2010
    
December 31, 2009
  
   
United States
  
   
Oil (BBLS)
    
Gas (MCF)
    
Oil (BBLS)
    
Gas (MCF)
  
                         
Proved developed and undeveloped reserves:
                        
Beginning of year
     64,974       1,617,882       79,680       1,472,237  
Extensions and discoveries
     8,116       1,154,013       11,592       748,981  
Revisions of previous estimates (a)
     321,850       1,515,168       (12,918 )     (299,004 )
Production
     (100,388 )     (828,693 )     (13,380 )     (304,332 )
End of year
     294,552       3,458,370       64,974       1,617,882  
                                 
Proved developed reserves:
                                
Beginning of year
     13,487       813,940       28,193       668,717  
End of year
     290,543       2,897,245       13,487       813,940  
                                 
Proved undeveloped reserves:
                                
Beginning of year
     51,487       803,942       51,487       803,520  
End of year
     4,009       561,125       51,487       803,942  
                                 
(a) Revisions of estimates are attributable to well performance.
                  
 
 
 
 
 
 
 
Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
  
             
Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. At December 31, 2010 and 2009, 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,
  
   
2010
    
2009
  
   
(in thousands)
  
Future cash inflows
   $ 40,137     $ 10,501  
Future production costs
     (4,210 )     (1,333 )
Future development costs
     (2,051 )     (1,698 )
Future ad valorem taxes
     (26 )     -  
Future net cash flows
     33,850       7,470  
10% annual discount for estimated timing of cash flows
     (4,394 )     (1,745 )
Standardized measure of discounted future net cash flows
   $ 29,456     $ 5,725  
                 
                 
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,
  
      2010       2009  
   
(in thousands)
  
Net change in sales and transfer prices and in production costs
 related to future production
   $ 9,311     $ (2,336 )
Sales and transfers of oil and gas produced during the period
     (10,720 )     (1,716 )
Net change due to extensions, discoveries, and improved recovery
     3,048       2,576  
Changes in estimated future development costs
     684       2,439  
Net change due to revisions in quantities estimates
     17,125       (2,088 )
Accretion of discount
     573       627  
Other
     3,710       (50 )
Aggregate change in the standardized measure of discounted
 future net cash flows for the year
   $ 23,731     $ (548 )
 
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.

 
 
F-14
 
 EX-14 2 ex14.htm CODE OF ETHICS ex14.htm
Exhibit 14
 
September 2009
Code of Ethics for Ridgewood Energy Corporation


As a registered investment adviser, Ridgewood Energy Corporation (“Ridgewood Energy”)  is required to adopt a Code of Ethics pursuant to Rule 204A-1 (the “Rule”)of the Investment Advisers Act of 1940 (“Advisers Act”).  This Code of Ethics, together with The Ridgewood Companies Code of Ethics (attached as Exhibit A), will serve as Ridgewood Energy’s Code of Ethics (“Code”) for purposes of the Rule.

I.
Statement of General Policy

 Ridgewood Energy and its employees owe a fiduciary duty to their clients.  A fiduciary is a person or entity that acts in certain matters on behalf of another person or entity.  Fiduciaries are held to a higher standard of care when managing the affairs of others and must act with integrity, skill, care and diligence.  A fiduciary must disclose conflicts of interest with its clients or, in some cases, avoid such conflicts entirely. A fiduciary’s duties also require it to treat clients fairly and not to favor one client over another.  Accordingly, at all times Ridgewood Energy and its employees must avoid activities, interests and relationships that run contrary (or appear to run contrary) to the best interests of their clients.  The Code sets forth specific standards for Ridgewood Energy and its employees when fulfilling Ridgewood Energy’s fiduciary responsibilities.
 
All employees are also required to read, understand and comply at all times with the Code, including The Ridgewood Companies Code of Ethics (Exhibit A), which contains standards of business conduct that Ridgewood Energy and its affiliates require of their employees such as: (i) the expectation that all employees perform their duties in an honest and ethical manner; (ii) the requirement that employees ensure that all disclosures in reports and documents are complete, fair, accurate, timely and understandable; and (iii) the requirement that no employee retaliate against any other employee who provides information in good faith to any of the affiliated Ridgewood Companies, law enforcement officials or regulatory agencies concerning a possible violation of law or regulation (see the Ridgewood Companies Internal Reporting Procedures).
 
While the Code cannot anticipate every situation in which personal interests may be in conflict with the interests of Ridgewood Energy’s clients, all employees are expected to be responsive to the spirit and intent of the Code as well as its specific provisions.  The Chief Compliance Officer (“CCO”) and the Legal Department are responsible for enforcement of the Code. All persons subject to the Code are required to report any violations of the Code of which they become aware to the CCO.  When any doubt exists regarding any Code provision or whether a conflict of interest might exist with regard to an Advisory Client (see definition below), you should discuss the transaction beforehand with the CCO.
 
Each employee of Ridgewood Energy will be required to sign the Code of Ethics Acknowledgement Form acknowledging that he/she has received, read and understands the contents of the Code.
 
 
 
 
 
Code of Ethics for Ridgewood Energy Corporation
 Page 2
 September 2009
 
II.           Definitions:  As used in the Code, the following terms have the meaning provided below:
 
 
A.
Adviser. Ridgewood Energy.
 
 
B.
Advisory Client. Any private equity fund exempt from the securities registration requirements under Section 4(2) of the Securities Act of 1933 (“1933 Act”) and Rule 506 of Regulation D thereunder, or any public fund that is registered pursuant to a Form S-3 shelf registration statement pursuant to the 1933 Act, that is managed directly or indirectly by the Adviser (such as the Ridgewood Energy I Fund, LLC, among others).
 
 
C.
Access Person.  Any director, officer or employee of the Adviser, or of any company which is an affiliate of the Adviser, who, in connection with his or her regular functions or duties, makes, participates in, or obtains information regarding the purchase or sale of a security for an Advisory Client, or whose functions relate to the making of any recommendations and investment decisions with respect to such purchases or sales and shall include any person who is a member of the Adviser’s Investment Committee (referred to herein as “Investment Committee Member”), as defined below.
 
A person does not become an Access Person due to the following:
 
 
A.
Assisting in the preparation of public reports or receiving public reports (except reports regarding current recommendations of “Oil and Gas Projects” for Ridgewood Energy); or
 
 
B.
Obtaining knowledge of current recommendations of “Oil and Gas Projects” for Ridgewood Energy on an infrequent or inadvertent basis.
 
 
D.
Beneficial Ownership.  “Beneficial Ownership” shall be interpreted in the same manner as it would be under Rule 16a-1(a)(2) under the Securities Exchange Act of 1934 (the “1934 Act”) in determining whether a person has beneficial ownership of a security for purposes of Section 16 of the 1934 Act and the rules and regulations thereunder.  Accordingly, the term “Beneficial Ownership” shall be understood to mean “any person who, directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise, has or shares a direct or indirect pecuniary interest in the equity securities.”  Beneficial Ownership includes securities owned by a member of your immediate family sharing the same household.
 
 
E.
Chief Compliance Officer (“CCO”).  The person designated by the Adviser as CCO or a properly designated delegate.  The current CCO is Maria E. Haggerty.
 
 
F.
Covered Securities.  All securities as defined in Section 202(a)(18) of the Adviser’s Act, except that it shall not include direct obligations of the government of the United States, high quality, short-term debt instruments (including but not limited to bankers’ acceptances, bank certificates of deposit, commercial paper and repurchase agreements) and shares of U.S. registered open-end investment companies (i.e., mutual funds).
 
 
G.
Investment Committee Member.  Each person who is a member of the Ridgewood Energy Investment Committee and, in connection with his or her regular functions or duties, makes or participates in making recommendations and investment decisions regarding the purchase or sale of securities affecting an Advisory Client.
 
 
 
 
 
Code of Ethics for Ridgewood Energy Corporation
 Page 3
 September 2009
 
 
H.
New Issue Equity Security.  Any initial public offering of any equity security (as defined in section 3(a) (11) of the Securities Exchange Act of 1934), made pursuant to a registration statement or offering circular.
 
 
I.
Non-Advisory Director or Officer.  The directors or officers of Ridgewood Energy who in connection with his or her regular functions or duties do not make, participate in, or obtain information regarding the purchase or sale of a security for an Advisory Client.
 
 
J.
Private Placement.  An offering that is exempt from registration under the 1933 Act, as amended, pursuant to Section 4(2) or Section 4(6) or pursuant to Rule 504, Rule 505 or Rule 506 under the 1933 Act.
 
 
K.
Purchase or Sale of a Security.  A transaction to purchase or sell a security, including among other things, an option to purchase or sell a security.
 
 
L.
Supervised Persons. Each (i) Access Person and Non-Advisory Director or Officer; (ii) other employees of the Adviser; and (iii) any other person who provides advice on behalf of the Adviser and is subject to the Adviser’s supervision and control.  With regard to item (iii), depending upon the circumstances, the following may be “Supervised Persons” of the Adviser: temporary workers, consultants, independent contractors, certain employees of affiliates, or particular persons designated by the CCO.
 
All other terms used in the Code that are not defined herein have the same meanings ascribed to them in either the Advisers Act, the 1933 Act or the Securities Exchange Act of 1934.
 
III.           Standards of Conduct
 
 
A.
All Supervised Persons have a fiduciary duty to:
 
 
1.
Always place the interests of the Advisory Clients first and not take inappropriate advantage of their positions;
 
 
2.
Ensure that all personal securities transactions and other activities are conducted consistent with the Code and in such a manner as to avoid any actual or potential conflict of interest or any abuse of a Supervised Person’s position of trust and responsibility (see Section D below for more on Conflicts of Interests);
 
 
3.
Not engage in any act, practice, or course of business which results in the distribution to unauthorized persons of material nonpublic information of public companies learned in the course of business which is confidential, pursuant to the requirements established by the “Insider Trading Policy”.  Although Access Persons are most likely to come in contact with material nonpublic information, the prohibition on insider trading and potential sanctions applies to all Supervised Persons.
 
 
 
 
 
Code of Ethics for Ridgewood Energy Corporation
 Page 4
 September 2009
 
 
4.
Ensure that independence is maintained in the investment decision-making process.
 
 
B.
Supervised Persons must comply with all applicable federal securities laws, which includes the Advisers Act, 1933 Act, the Securities Exchange Act of 1934, the Sarbanes-Oxley Act of 2002, Title V of the Gramm-Leach-Bliley Act, any rules adopted by the SEC under any of these statutes, the Bank Secrecy Act to the extent it applies to funds and investment advisers, and any rules adopted thereunder by the SEC or the Department of the Treasury (collectively, “Federal Securities Laws”).
 
 
C.
In connection with the purchase or sale, directly or indirectly, of securities held or to be acquired by an Advisory Client, Supervised Persons are not permitted to:
 
 
1.
Employ any device, scheme or artifice to defraud an Advisory Client;
 
 
2.
Mislead an Advisory Client, including by making any untrue statement of a material fact or by making a statement that omits material facts;
 
 
3.
Engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon an Advisory Client;
 
 
4.
Engage in any manipulative practice with respect to an Advisory Client; or
 
 
5.
Engage in any manipulative practice with respect to securities including price manipulation.
 
 
D.
Conflicts of Interest among Advisory Clients may arise where an Adviser or its Supervised Persons have reason to favor the interests of one Advisory Client over another Advisory Client (e.g., funds with a larger number of investors versus funds with fewer investors; funds in which employees of an Adviser have made material personal investments versus those without).   Inappropriate favoritism of one Advisory Client over another Advisory Client would constitute a breach of fiduciary duty.
 
 
E.
The standards set forth in Sections A-D above, govern all conduct whether or not the conduct is also covered by more specific provisions of the Code.  Supervised Persons are encouraged to raise any questions concerning the Code with the CCO.  The CCO is ultimately responsible for administering, monitoring and reviewing such procedures to ensure that they are accomplishing their stated goal.
 
IV.
Restrictions on Personal Securities Transactions -- Access Persons
 
 
A.
Access Persons shall not purchase or sell, directly or indirectly, any Covered Security in which she or he has, any direct or indirect Beneficial Ownership and which at the time of such purchase or sale:


 
1.
Is a publicly traded exploration and production oil and gas company that has substantial activities in the Gulf of Mexico or a publicly traded drilling or pipeline company that has substantial activities in the Gulf of Mexico.  If you are not sure whether a particular security falls within this category, please consult with the CCO before entering an order for the Purchase or Sale of a Security.
 
 
 
 
 
Code of Ethics for Ridgewood Energy Corporation
 Page 5
 September 2009

 
 
2.
Is a New Issue Equity Security.
 
 
B.
Access Persons are required to obtain prior written approval before making an outside investment in a Private Placement or any other investment that cannot be made through a Financial Industry Regulatory Authority, Inc. (“FINRA”) Member Firm (including Ridgewood Funds) from the Adviser’s CEO or Executive Vice President (Robert L. Gold) and the CCO.  The Ridgewood Energy “Outside Investments Approval Form” is attached hereto as Exhibit D.

 
V.
Exempt Transactions: The prohibitions in Section III of the Code shall not apply to the following transactions by Access Persons:
 
 
A.
Purchases or Sales of Securities effected in any account over which an Access Person has no direct or indirect influence or control; and
 
 
B.
The exercise of rights to purchase securities granted by an issuer on a pro rata basis to the Access Person as a member of a class of holders of the issuer’s securities, to the extent such rights were acquired from such issuer.
 
VI.          Prohibited Business Conduct

 
A.
Supervised Persons of the Adviser may not participate in any of the following activities without obtaining prior written approval from both the Head of such Supervised Person’s Department and the CCO or in the case of Access Persons from the Adviser’s CEO Executive Vice President (Robert L. Gold) and the CCO:
 
 
1.
Outside Employment, Business Affiliations or Directorships: Accept any outside employment, directorship or other business affiliation with organizations outside of the Adviser. The Adviser discourages Supervised Persons from engaging in outside business activities that may interfere with their duties with the Adviser. 
 
 
2.
Gifts and Entertainment: A conflict of interest occurs when the personal interests of employees interfere or could potentially interfere with their responsibilities to their clients.  Generally, Supervised Persons should not accept gifts, favors, entertainment, special accommodations, or other things of material value that could influence their decision-making or make them feel beholden to a person or firm.  Similarly, Supervised Persons should not offer gifts, favors, entertainment or other things of value that could be viewed as overly generous or aimed at influencing the decision-making from any person or entity that does or seeks to do business with or on behalf of the Adviser.
 
Note. This general principal applies in addition to the more specific guidelines set forth below.
 
 
 
 
 
Code of Ethics for Ridgewood Energy Corporation
 Page 6
 September 2009
 
 
a.
Gifts.  No Supervised Person may receive any gift, service, or other thing of more than de minimis value from any person or entity that does business with or on behalf of the Adviser.  No Supervised Person may give or offer any gift of more than de minimis value to any person or entity that does business with or on behalf of the Adviser without pre-approval by the CCO.
 
 
i.    De Minimis.  For purposes of the Code, de minimus is one-hundred dollars ($100) per person.
 
 
b.
Cash.   No Supervised Person may give or accept cash gifts or cash equivalents to or from a person or entity that does business with an Advisory Client.
 
 
c.
Entertainment.  No Supervised Person may give or accept extravagant or excessive entertainment to or from any person or entity that does or seeks to do business with or on behalf of an Advisory Client.  Supervised Persons may provide or accept a business entertainment event, such as dinner or a sporting event, so long as it is of reasonable value and the Supervised Person providing the entertainment is present as such event.
 
 
B.
No Supervised Person shall, either directly or indirectly:
 
 
1.
Engage in any business transaction or arrangement for personal profit based on material non-public information gained by way of employment with the Adviser;
 
 
2.
Communicate material non-public information about security transactions of an Advisory Client whether current or prospective, to anyone unless necessary as part of the regular and ordinary course of the Advisory Clients’ business.
 
 
3.
Buy or sell any security or any other property from or to an Advisory Client without the prior approval of the CEO of the Adviser and the CCO.
 
VII.         Holdings and Transaction Reporting Requirements for Access Persons
 
Access Persons must submit to the CCO a report of all holdings in all Covered Securities within 10 days of becoming an Access Person (“Initial Securities Holdings Report”) and thereafter on an annual basis (“Annual Holdings Report”).  Both these reports must be current within the preceding 45 days.  Access Persons are also required to submit ongoing quarterly transaction reports within 10 days of each quarter-end (“Quarterly Securities Transaction Reports”).  Please refer to Exhibit F, Schedules A-C, attached hereto for further requirements regarding the initial, quarterly and annual reports.
 
In lieu of filing such reports with the CCO, Access Persons may arrange for the CCO or CCO designee to receive duplicate account statements and confirmations for accounts held at broker-dealers, banks or other financial institutions.
 
 
 
 
 
Code of Ethics for Ridgewood Energy Corporation
 Page 7
 September 2009
 
VIII.         Reinforcement, Reporting and Sanctions
 
The Code is designed to detect and prevent fraud against Advisory Clients and to avoid even the appearance of impropriety.
 
To provide assurance that policies are effective, the CCO or CCO designee is required to monitor Access Persons’ personal securities transactions for violations against the restrictions outlined in Section III A above, as well as any suspicious trading or patterns of trading that may violate the Federal Securities Laws.   Other internal auditing and compliance review procedures may be adopted from time to time.  Appropriate records will be kept, in the form, and for the time periods, required by applicable law, including records of compliance monitoring, reporting by Access Persons, approvals of various transactions, and disciplinary actions.
 
Upon learning of a violation of the Code, the Adviser may impose sanctions as it deems appropriate under the circumstance, including, but not limited to, letters of reprimand, suspension or termination of employment and notification to regulatory authorities in the case of Code violations which also constitute fraudulent conduct. The CCO and General Counsel will make recommendations regarding sanctions for violations and refer such recommendations to the CEO of the Adviser for review.  All material violations of the Code and any sanctions imposed with respect thereto shall be reported to the CCO and the General Counsel.
 
IX.          Administration & Amendments to the Code
 
 
A.
Annual Certification of Compliance:  Unless an updated Code has been delivered to Supervised Persons, all Supervised Persons are required in writing to certify annually that they have (a) received a copy of the Code; (b) read and understand all provisions of the Code; and (c) agreed to comply with the Code. 
 
 
B.
Amendments: The Code may be amended by the CCO from time to time. Material amendments shall be distributed to all relevant persons and records shall be kept of their acknowledgement of receipt of such an Amended Code.
 
 
C.
Training and Education: The CCO is responsible for training and educating Supervised Persons regarding the Code.  Such training will occur periodically.
 
 
D.
Records of the Code: Records will be kept in accordance with Rules 204-2(a) (12) and (13) of the Advisers Act.  Accordingly, such records will be maintained at the Adviser’ home office located in New Jersey or at such other of its offices as appropriate.
 
 
E.
Additional Information: For additional information about the Code or any ethics-related questions, please contact the CCO or the General Counsel.
 
 
 
 
 
 
EXHIBIT A
 
THE RIDGEWOOD COMPANIES

Code of Ethics


1.           Application and Purpose

This Code of Ethics (this “Code”) shall apply to all employees and officers of Ridgewood Renewable Power, LLC, Ridgewood Energy Corporation, Ridgewood Capital Management, LLC (the “Ridgewood Companies”), including employees and officers of The Ridgewood Companies affiliates and subsidiaries (“Employees”), including, but not limited to, the power trusts:  Ridgewood Electric Power Trust I, Ridgewood Electric Power Trust II, Ridgewood Electric Power Trust III, Ridgewood Electric Power Trust IV, Ridgewood Electric Power Trust V, and The Ridgewood Power Growth Fund (collectively the “Power Trusts”).  Every Employee must be familiar with and understand the provisions of this Code.  The purpose of this Code is to promote:

 
·
Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
 
 
·
Full, fair, accurate, timely and understandable disclosure in reports and documents that the Power Trusts file with, or submits to, the United States Securities and Exchange Commission and, as to the Power Trusts and Ridgewood Companies, in other public communications;
 
 
·
Compliance with applicable governmental laws, rules and regulations;
 
 
·
The prompt internal reporting of violations of this Code; and
 
 
·
Accountability for adherence to this Code.

 
2.
Honest and Ethical Conduct

All Employees shall perform their duties in an honest and ethical manner.  This includes:

 
·
Avoiding situations in which their personal, family or financial interests conflict with those of the Ridgewood companies;
 
 
·
Refraining from engaging in any activities that compete with the Ridgewood Companies, or which may compromise its interests;
 
 
·
Refraining from taking any business or investment opportunity discovered in the course of employment with or service to the Ridgewood Companies that the Employee knows, or should have or has reason to know, would benefit the Ridgewood Companies, or any of them; and
 
 
·
Complying with all applicable governmental laws, rules and regulations.
 
 
 
 
 
The Ridgewood Companies encourage Employees to avoid even the appearance of a conflict of interest and to raise ethical questions, dilemmas, concerns or suggestions with appropriate individuals within the Ridgewood Companies, including supervisors, managers, senior management, or human resources.  The Ridgewood Companies have since their inception encouraged such issues to be raised and, based upon prior experience, many, if not most, of these issues can be addressed informally, after appropriate discussion and analysis.

If any Employee would feel uncomfortable in any way raising ethical issues as set forth above, or if they raise such issues and they are not resolved appropriately, then s/he should consult with the Manager of HR or the General Counsel (the “Ethics Officer(s)”).  The Ethics Officer(s) will also follow the procedures described in Section 4 below.  Any Employee who becomes involved in a situation that gives rise to an actual conflict of interest must promptly inform the Ethics Officer(s) of such conflict.

 
3.
Full, Fair, Accurate, Timely and Understandable Disclosure

The Ridgewood Companies are committed to ensuring that all disclosures in reports and documents that the Power Trusts file with, or submits to the SEC, as well as other public communications made by the Ridgewood Companies in general are full, fair, accurate, timely and understandable.  The Ridgewood Companies’ CEO and CFO (“Senior Officers”) are ultimately responsible for taking all necessary steps to ensure that this occurs.  All Company Employees shall take appropriate steps within their area of responsibility to ensure the same.
 
 
4.
Internal Reporting of Code Violations

Any Employee who in good faith believes or suspects that any portion of this Code has been violated (including any violation of Section 3 of this Code) and does not feel comfortable addressing the issue with individuals identified in Section 2 should immediately report such violation to the Ethics Officer(s).  Any such report will be promptly evaluated and/or investigated.  While the Ridgewood Companies strongly prefer that any individual who wishes to make such a complaint to identify him/herself (to assist in the understanding of the concerns expressed), any person may make such a complaint anonymously.  Any person reporting such a violation should be prepared to provide as much detail as possible about the suspected violation, including the individuals involved, the nature of the violation, documentation of the violation, or any other information which may be helpful in the Ridgewood Companies’ evaluation and, if necessary, investigation of the complaint.  Prompt disclosure to the appropriate parties is vital to ensure a thorough and timely evaluation and appropriate resolution.  A violation of this Code is a serious matter and could have legal implications.  Allegations of such behavior are not taken lightly and should not be made to embarrass someone or put him or her in a false light.  Therefore, reports of suspected violations should always be made in good faith.

 
5.
No Retaliation

The Ridgewood Companies will not tolerate any retaliation against any person who provides information in good faith to the Ridgewood Companies or law enforcement official concerning a possible violation of any law, regulation or this Code.  Any Employee who violates this rule may be subject to civil, criminal and administrative penalties, as well as disciplinary action, up to and including termination of employment.
 
2
 
 
 
 
6.
Consequences for Non-Compliance with this Code

Corrective Actions.  Any violation of applicable law or any deviation from the standards embodied in this Code will result in appropriate corrective and/or disciplinary action, up to and including termination of employment.

Required Government Reporting.  Whenever conduct occurs that requires a report to the government, the Ethics Officer(s) shall be responsible for complying with such reporting requirements.

 
7.
Publication of this Code; Amendments and Waivers

 
·
This Code will be posted and maintained on the Company’s website and posting will be disclosed in each Power Trust’s Annual Report on Form 10-K.
 
 
·
Any amendment to or waiver of this Code with respect to a Senior Officer of a Power Trust:
 
 
o
Shall be disclosed within five (5) days of such action in a filing on Form 8-K with the Securities and Exchange Commission.
 
 
o
Shall be reported in the Power Trust’s next periodic report with the SEC if not previously reported on a Form 8-K.
 
 
o
Shall be reported in the Power Trust’s next periodic report with the SEC if not previously reported on a Form 8-K.
 
 
·
Records of any disclosures relating to waivers of this Code shall be retained for no less than five years.



Adopted by March 1, 2004
 
 
 
3
 EX-31.1 3 ex31_1.htm ex31_1.htm
Exhibit 31.1
 
 
CERTIFICATION
 
I, Robert E. Swanson, certify that:
 
 
1.
I have reviewed this Annual Report on Form 10-K of Ridgewood Energy W Fund, LLC;
 
 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
 
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have:
 
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
 
5.
 
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Dated:
March 22, 2011
   
/s/
ROBERT E. SWANSON
Name:
Robert E. Swanson
   
Title:
Chief Executive Officer
 
(Principal Executive Officer)
 





 
 EX-31.2 4 ex31_2.htm ex31_2.htm
Exhibit 31.2
 
 
CERTIFICATION
 
I, Kathleen P. McSherry, certify that:
 
  1.
I have reviewed this Annual Report on Form 10-K of Ridgewood Energy W Fund, LLC;
 
 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
 
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have:
 
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
 
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
 
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
 
Dated:
March 22, 2011
   
/s/
KATHLEEN P. MCSHERRY
Name:
Kathleen P. McSherry
   
Title:
Executive Vice President and Chief Financial Officer
 
(Principal Financial and Accounting Officer)
 

 
 EX-32 5 ex32.htm ex32.htm
Exhibit 32
 
 
CERTIFICATIONS PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with this Annual Report on Form 10-K of the Ridgewood Energy W Fund, LLC (the “Fund”) for the fiscal year ended December 31, 2010, as filed with the Securities and Exchange Commission on the date hereof, (the “Report”), each of the undersigned officers of the Fund hereby certifies, pursuant to 18 U.S.C. (section) 1350, as adopted pursuant to (section) 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:
 
 
(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
 
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Fund.
 
         
Dated:
March 22, 2011
By:
/s/
ROBERT E. SWANSON
     
Name:
Robert E. Swanson
     
Title:
Chief Executive Officer
       
(Principal Executive Officer)
         
         
Dated:
March 22, 2011
By:
/s/
KATHLEEN P. MCSHERRY
     
Name:
Kathleen P. McSherry
     
Title:
Executive Vice President and Chief Financial Officer
       
(Principal Financial and Accounting Officer)
         
         
 
A signed original of this written statement or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to Ridgewood Energy W Fund, LLC and will be retained by Ridgewood Energy W Fund, LLC and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this report or as a separate disclosure document.
 
 
 
 
 
 
 





 
 EX-99 6 ex99.htm REPORT OF RYDER SCOTT COMPANY, L.P. ex99.htm
Exhibit 99









RIDGEWOOD ENERGY W FUND, LLC








Estimated Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests





SEC Parameters





As of

December 31, 2010




\s\ Stephen E. Gardner
  
\s\ John E. Hamlin
Stephen E. Gardner, P.E.
  
John E. Hamlin, P.E.
Texas PE License No. 100578
  
Texas PE License No. 65319
Senior Petroleum Engineer
  
Managing Senior Vice President

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
[SEAL]
[SEAL]

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
 
 
TBPE REGISTERED ENGINEERING FIRM F-1580
FAX (713) 651-0849
  1100 LOUISIANA    SUITE 3800                 HOUSTON, TEXAS 77002-5235
TELEPHONE (713) 651-9191

 
January 4, 2011

Ridgewood Energy Corporation
14 Philips Parkway
Montvale, NJ  07645-1811

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Ridgewood Energy W Fund, LLC (the Fund), which is administered by Ridgewood Energy Corporation (Ridgewood) as of December 31, 2010.  The subject properties are located in the state and federal waters offshore Louisiana.  The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).  Our third party study, completed on December 30, 2010 and presented herein, was prepared for public disclosure by Ridgewood in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon and gas reserves of the Fund as of December 31, 2010.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2010 are related to hydrocarbon prices.  The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations.  Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.  The results of this study are summarized below.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
Ridgewood Energy W Fund, LLC
As of December 31, 2010

   
Proved
  
   
Developed
          
Total
  
   
Producing
    
Non-Producing
    
Undeveloped
    
Proved
  
Net Remaining Reserves
                        
  Oil/Condensate – Barrels
     254,123       36,420       4,008       294,551  
  Gas – MMCF
     1,811       1,086       561       3,458  
                                 
Income Data
                                
  Future Gross Revenue
   $ 28,838,144     $ 8,566,449     $ 2,732,060     $ 40,136,653  
  Deductions
     3,259,948       1,961,283       1,065,664       6,286,895  
  Future Net Income (FNI)
   $ 25,578,196     $ 6,605,166     $ 1,666,396     $ 33,849,758  
                                 
  Discounted FNI @ 10%
   $ 24,005,551     $ 4,505,824     $ 944,409     $ 29,455,784  
 
600,  1015   4TH  STREET, S.W.CALGARY, ALBERTA T2R 1J4        TEL (403) 262-2799    FAX (403) 262-2790
621  17TH STREET, SUITE 1550DENVER, COLORADO 80293-1501 TEL (303) 623-9147    FAX (303) 623-4258
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 2
 

Liquid hydrocarbons are expressed in standard 42 gallon barrels.  All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C.  The program was used solely at the request of Ridgewood.  Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized.  Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding.  The rounding differences are not material.

The future gross revenue is after the deduction of production taxes.  The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage.  Certain gas, oil and condensate processing and handling fees, including compression fees where applicable, are included as “other” costs.  The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.  Liquid hydrocarbon reserves account for approximately 57 percent and gas reserves account for the remaining 43 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.  Future net income was discounted at five other discount rates which were also compounded monthly.  These results are shown in summary form as follows.
 
    Discounted Future Net Income
    As of December 31, 2010
Discount Rate
    
Total
  
Percent
    
Proved
  
         
  8
    
$30,235,851
  
12
    
$28,718,057
  
15
    
$27,684,266
  
20
    
$23,133,174
  
30
    
$23,552,532
  


The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.  The proved developed non-producing reserves included herein consist of the behind pipe category.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 3
 

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.  The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  At Ridgewood’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.  If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.  For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”  Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks.  Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Ridgewood’s operations may be subject to various levels of governmental controls and regulations.  These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time.  Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which the Fund owns an interest; however, we have not made any field examination of the properties.  No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 4
 
 
Estimates of Reserves

The estimation of reserves involves two distinct determinations.  The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a).  The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures.  These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.  These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves.  Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
 
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator.  When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves.  If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator.  Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported.  For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.”  The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”  The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.”  All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available.  Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

All of the proved reserves for the properties included herein were estimated by the volumetric method.  This method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.  However, available performance data were used to ensure the volumetric parameters in our estimates were appropriate. The analysis utilized pertinent well and seismic data furnished to Ryder Scott by Ridgewood or which we have obtained from public data sources that were available through October 2010.  The data utilized from the analogues, as well as the well data and seismic data incorporated into our analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.  Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined.  While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 5
 

Ridgewood has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation.  In preparing our forecast of future proved production and income, we have relied upon data furnished by Ridgewood with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements.  Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Ridgewood.  We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein.  The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.”  In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data.  If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated.  An estimated rate of decline was then applied to depletion of the reserves.  If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing.  For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Ridgewood.  Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production.  Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes that include, but are not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 6
 

Ridgewood furnished us with the above mentioned average prices in effect on December 31, 2010.  These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold.  These benchmark prices are prior to the adjustments for differentials as described herein.  The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, plant product revenue, and/or distance from market, referred to herein as “differentials.”  The differentials used in the preparation of this report were furnished to us by Ridgewood.  The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Ridgewood to determine these differentials. The differentials furnished by Ridgewood were reviewed by us for their reasonableness using information furnished by Ridgewood for this purpose.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.


Geographic Area
Product
Price
Reference
Average
Benchmark Prices
Average
Realized Prices
United States
Oil/
Condensate
WTI Cushing
$79.43/Bbl
$77.47/Bbl
Gas
Henry Hub
$4.38/MMBTU
$5.05/MCF


The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Ridgewood and include only those costs directly applicable to the leases or wells.  The operating costs include a portion of general and administrative costs allocated directly to the leases and wells.  For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs.  The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Certain gas, oil and condensate processing and handling fees, including compression fees where applicable, are included as “other” costs.  The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Ridgewood.  No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 7
 

Development costs were furnished to us by Ridgewood and are based on authorizations for expenditure for the proposed work or actual costs for similar projects.  The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs.  The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant.  The estimates of the net abandonment costs furnished by Ridgewood were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Ridgewood’s plans to develop these reserves as of December 31, 2010.  The implementation of Ridgewood’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Ridgewood’s management.  As the result of our inquires during the course of preparing this report, Ridgewood has informed us that the development activities included herein have been subjected to and received the internal approvals required by Ridgewood’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Ridgewood.  Additionally, Ridgewood has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Ridgewood were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years.  Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada.  We have over eighty engineers and geoscientists on our permanent staff.  By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue.  We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients.  This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations.  Many of our staff have authored or co-authored technical papers on the subject of reserves related topics.  We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Ridgewood and the Fund.  Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott.  The professional qualifications of the undersigned, the technical person primarily responsible for reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
Ridgewood Energy W Fund, LLC
Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests
SEC Parameters
As of December 31, 2010
January 4, 2011
Page 8
 

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings on Form 10-K made with the SEC by Ridgewood.

We have provided Ridgewood with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Ridgewood and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices.  Please contact us if we can be of further service.
 
 
 
Very truly yours,
  
     
 
RYDER SCOTT COMPANY, L.P.
  
 
TBPE Firm Registration No. F-1580
  
     
     
 
\s\ Stephen E. Gardner
  
     
 
Stephen E. Gardner, P.E.
  
 
Texas PE License No. 100578
  
 
Senior Petroleum Engineer
[SEAL]
     
     
 
\s\ John E. Hamlin
  
     
 
John E. Hamlin, P.E.
  
 
Texas PE License No. 65319
  
 
Managing Senior Vice President
[SEAL]
 
SEG/sm
 

RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
 
Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P.  Mr. John E. Hamlin was the primary technical person responsible for overseeing the estimate of the reserves, future production, and income presented herein.

Mr. Hamlin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1979, is a Managing Senior Vice President and also serves as an Engineering Group Supervisor responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide.  Before joining Ryder Scott, Mr. Hamlin served in a number of engineering positions with Phillips Petroleum Corporation.  For more information regarding Mr. Hamlin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com.

Mr. Hamlin earned a Bachelor of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975 and is a licensed Professional Engineer in the State of Texas.  He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Hamlin fulfills.  As part of his 2010 continuing education hours, Mr. Hamlin attended an internally presented 19.5 hours of formalized training and 3.5 hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, and ethics training.

Based on his educational background, professional training and more than 34 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Hamlin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
 
PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)


PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA).  The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K.  The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”.  The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010.  Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made.  The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data.  The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved.  Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.  Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC.  The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods.  Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery.  Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids.  Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations.  Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.  Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits.  These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
PETROLEUM RESERVES DEFINITIONS
Page 2
 
 
Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.


RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

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

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


PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

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

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

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

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

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
PETROLEUM RESERVES DEFINITIONS
Page 3
 
 
PROVED RESERVES (SEC DEFINITIONS) CONTINUED

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

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

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

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

 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
 
RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and
 
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
 

Reserves status categories define the development and producing status of wells and reservoirs.  Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).


DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

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

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

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

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
 
 
 
RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2
 
 
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In
Shut-in Reserves are expected to be recovered from:
 
(1)
completion intervals which are open at the time of the estimate, but which have not  started producing;
 
(2)
wells which were shut-in for market conditions or pipeline connections; or
 
(3)
wells not capable of production for mechanical reasons.

Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.


UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

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

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

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

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

 
 
RYDER SCOTT COMPANY   PETROLEUM CONSULTANTS
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