10-Q 1 d11111110q.htm FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011 d11111110q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2011
 
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. 000-51924

RIDGEWOOD ENERGY O FUND, LLC
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  
76-0774429
(I.R.S. Employer
Identification No.)
  

14 Philips Parkway, Montvale, NJ  07645
 (Address of principal executive offices) (Zip code)

(800) 942-5550
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes xNo o     
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes x      No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes oNo x
 
As of November 3, 2011 the Fund had 870.6486 shares of LLC Membership Interest outstanding.
 
 
 
 
 
 

 
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PART I - FINANCIAL INFORMATION
  
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PART II - OTHER INFORMATION
  
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PART I – FINANCIAL INFORMATION


UNAUDITED CONDENSED BALANCE SHEETS
(in thousands, except share data)

             
   
September 30, 2011
    
December 31, 2010
  
ASSETS
            
Current assets:
            
Cash and cash equivalents
   $ 7,049     $ 5,642  
Short-term investments in marketable securities
     10,403       12,993  
Production receivable
     880       1,282  
Receivable from sale of oil and gas properties
     -       2,330  
Other current assets
     443       112  
Total current assets
     18,775       22,359  
Salvage fund
     1,211       1,191  
Oil and gas properties:
                
Advances to operators for working interests and expenditures
     3       -  
Unproved properties
     6,108       5,632  
Proved properties
     17,207       17,194  
Less:  accumulated depletion and amortization
     (12,903 )     (10,021 )
Total oil and gas properties, net
     10,415       12,805  
Total assets
   $ 30,401     $ 36,355  
LIABILITIES AND MEMBERS' CAPITAL
                
Current liabilities:
                
Due to operators
   $ 609     $ 1,127  
Accrued expenses
     26       44  
Total current liabilities
     635       1,171  
Asset retirement obligations
     549       549  
Total liabilities
     1,184       1,720  
Commitments and contingencies (Note 6)
                
Members' capital:
                
Manager:
                
Distributions
     (3,763 )     (2,799 )
Retained earnings
     1,954       1,091  
Manager's total
     (1,809 )     (1,708 )
Shareholders:
                
Capital contributions (935 shares authorized;
                
   870.6486 issued and outstanding)
     128,990       128,990  
Syndication costs
     (14,742 )     (14,742 )
Distributions
     (23,500 )     (15,861 )
Accumulated deficit
     (59,722 )     (62,044 )
Shareholders' total
     31,026       36,343  
Total members' capital
     29,217       34,635  
Total liabilities and members' capital
   $ 30,401     $ 36,355  
 
The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
 RIDGEWOOD ENERGY O FUND, LLC
(in thousands, except per share data)
 
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
Revenue
                        
Oil and gas revenue
   $ 2,212     $ 3,063     $ 7,883     $ 6,394  
                                 
Expenses
                                
Depletion and amortization
     930       949       2,882       2,095  
Dry-hole costs
     4       46       (143 )     2,303  
Management fees to affiliate (Note 4)
     375       417       1,133       1,280  
Operating expenses
     193       191       672       390  
General and administrative expenses
     61       158       221       491  
Total expenses
     1,563       1,761       4,765       6,559  
Income (loss) from operations
     649       1,302       3,118       (165 )
Other income
     141       40       67       145  
Net income (loss)
   $ 790     $ 1,342     $ 3,185     $ (20 )
                                 
Manager Interest
                                
Net income
   $ 249     $ 341     $ 863     $ 621  
                                 
Shareholder Interest
                                
Net income (loss)
   $ 541     $ 1,001     $ 2,322     $ (641 )
Net income (loss) per share
   $ 621     $ 1,150     $ 2,667     $ (736 )
 
The accompanying notes are an integral part of these unaudited condensed financial statements.

 
RIDGEWOOD ENERGY O FUND, LLC
(in thousands)

   
Nine months ended September 30,
  
 
  
2011
    
2010
  
             
Cash flows from operating activities
            
Net income (loss)
   $ 3,185     $ (20 )
Adjustments to reconcile net income (loss) to net cash
                
   provided by operating activities:
                
Depletion and amortization
     2,882       2,095  
Dry-hole costs
     (143 )     2,303  
Derivative instrument income
     (34 )     (108 )
Derivative instrument settlements
     64       142  
Changes in assets and liabilities:
                
Decrease (increase) in production receivable
     402       (7 )
Increase in other current assets
     (374 )     (116 )
(Decrease) increase in due to operators
     (62 )     44  
(Decrease) increase in accrued expenses
     (18 )     17  
Net cash provided by operating activities
     5,902       4,350  
                 
Cash flows from investing activities
                
Payments to operators for working interests and expenditures
     (3 )     -  
Capital expenditures for oil and gas properties
     (798 )     (8,329 )
Proceeds from sale of oil and gas properties
     2,330       -  
Proceeds from the maturity of investments
     13,000       24,013  
Investments in marketable securities
     (10,401 )     (17,001 )
Interest reinvested in salvage fund
     (20 )     (20 )
Net cash provided by (used in) investing activities
     4,108       (1,337 )
                 
Cash flows from financing activities
                
Distributions
     (8,603 )     (3,755 )
Net cash used in financing activities
     (8,603 )     (3,755 )
Net increase (decrease) in cash and cash equivalents
     1,407       (742 )
Cash and cash equivalents, beginning of period
     5,642       16,846  
Cash and cash equivalents, end of period
   $ 7,049     $ 16,104  

The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
RIDGEWOOD ENERGY O FUND, LLC

1.  Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy O Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on December 21, 2004 and operates pursuant to a limited liability company agreement (the "LLC Agreement") dated as of February 16, 2005 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 4 and 6.
 
Basis of Presentation
These unaudited interim condensed financial statements have been prepared by the Fund’s management in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Fund’s financial position, results of operations and cash flows for the periods presented.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted in these unaudited interim condensed financial statements.  The results of operations, financial position, and cash flows for the periods presented herein are not necessarily indicative of future financial results.  These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2010 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”).  The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period.  On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.
 
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents.  At times, deposits may be in excess of federally insured limits, which, for interest bearing deposits, are $250 thousand per insured financial institution.  Additionally, non-interest bearing deposits are fully insured through December 31, 2012, after which they will be included within the $250 thousand limit.  At September 30, 2011, the Fund’s bank balances exceeded federally insured limits by $5.6 million, all of which 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 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 September 30, 2011, the Fund had short-term, held-to-maturity investments of $4.4 million, which matured in October 2011, and $6.0 million, which will mature in December 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 September 30, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $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 September 30, 2011 and December 31, 2010, amounts recorded in due to operators totaling $0.4 million and $0.9 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.  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.
 
 
Derivative Instruments    
The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Derivative instruments are carried on the balance sheet at fair value and recorded as either an asset or liability.  Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met.  At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as other income on the statement of operations.  The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  See Note 2.  “Derivative Instruments,” for more information.

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.   

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.

Distributions
Distributions to shareholders are allocated in proportion to the number of shares held.  The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.
 
Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.
 
In January 2011, proceeds from the sale of the Aspen Project were distributed to the Manager and shareholders totaling $23 thousand and $2.3 million, respectively.
 
 
Recent Accounting Pronouncements
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.
 
2.   Derivative Instruments
 
The Fund periodically enters into derivative contracts relating to its oil or gas production. During the first quarter 2011, the Fund entered into two eight-month derivative contracts for put options relating to the pricing of gas for a portion of its anticipated production.  During the second quarter 2011, the Fund entered into three twelve-month derivative contracts for put options relating to the pricing of oil for a portion of its anticipated production.  The use of such derivative instruments limits the downside risk of adverse price movements.  Currently, the Fund has elected not to use hedge accounting for its derivatives and consequently, the derivatives are marked-to-market each quarter with fair value gains and losses recognized as other income on the statement of operations.  The estimated fair value of these contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  See Note 5. “Fair Value Measurements.”  The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.
 
Derivative instruments are carried at their fair value on the balance sheet within “Other current assets”.  The derivative contracts relating to gas pricing are settled based upon reported prices on NYMEX.  The derivative contracts relating to oil pricing are settled based upon averaged reported prices on ICE.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis in the statement of operations under the caption “Other income.”  Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.
 
At September 30, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil and gas that are not designated for hedge accounting as detailed in the following tables.
 
Production Period
  
Type of
Contract
  
Volume in
barrels
    
ICE Contract
Price per
barrel
    
Estimated
 Fair Value
 Asset
  
                   
(in thousands)
  
October 1, 2011 - April 30, 2012
  
Put Options
     9,656     $ 105.00     $ 110  
October 1, 2011 - April 30, 2012
  
Put Options
     4,607     $ 112.00     $ 74  
October 1, 2011 - April 30, 2012
  
Put Options
     4,607     $ 100.00     $ 40  
 
 
Production Period
  
Type of
Contract
  
Volume in
mmbtus
    
NYMEX
Contract
Price per
mmbtu
    
Estimated
 Fair Value
 Asset
  
                   
(in thousands)
  
October 1, 2011 - October 31, 2011
  
Put Options
     30,812     $ 4.25     $ 15  
October 1, 2011 - October 31, 2011
  
Put Options
     30,812     $ 4.35     $ 18  
 
 
For the three and nine months ended September 30, 2011 and 2010, the Fund’s derivative instrument income consisted of the following:

   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
  
Realized (losses) gains on derivative instruments
   $ (60 )   $ 27     $ (113 )   $ 79  
Unrealized gains on derivative instruments
     192       1       147       29  
    $ 132     $ 28     $ 34     $ 108  


3.   Oil and Gas Properties

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves.  Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves.  At September 30, 2011, the Fund had one unproved property, the Alpha Project, with capitalized exploratory well costs in excess of one year.  The Fund is currently undergoing completion efforts for the Alpha Project and production is expected to commence in first quarter 2012.

In December 2010, after determining not to proceed with the completion of the Aspen Project, the Fund entered into an agreement to sell its working interest in the Aspen Project to Stone Energy Corporation, for net proceeds of $2.3 million in cash, which resulted in a loss of $3.6 million.  The proceeds from the sale of the Aspen Project were collected in January 2011.

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.

   
Three months ended September 30,
    
Nine months ended September 30,
  
Lease Block
  
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
  
Targa Project
   $ (1 )   $ -     $ -     $ 2,276  
Other wells
     5       46       (143 )     27  
    $ 4     $ 46     $ (143 )   $ 2,303  

4.   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 each of the three months ended September 30, 2011 and 2010 were $0.4 million.   Management fees for the nine months ended September 30, 2011 and 2010 were $1.1 million and $1.3 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund.  Distributions paid to the Manager for each of the three months ended September 30, 2011 and 2010 were $0.2 million.  Distributions paid to the Manager for the nine months ended September 30, 2011 and 2010 were $1.0 million and $0.6 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.

5.   Fair Value Measurements
 
At September 30, 2011 and December 31, 2010, cash and cash equivalents, short-term investments in marketable securities, production receivable, receivable from sale of oil and gas properties, salvage fund and accrued expenses approximate fair value.  At September 30, 2011, derivative instruments are recorded at fair value based on Level 2 inputs, as the instruments are over-the-counter derivatives with a third party.
 
6.   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 September 30, 2011, the Fund had committed to spend an additional $14.0 million related to its investment properties, of which $8.8 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 September 30, 2011 and December 31, 2010, there were no known environmental contingencies that required the Fund to record a liability.

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

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

Lease Expirations
On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011.  Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

7.   Subsequent Events

The Fund has assessed the impact of subsequent events through the date of issuance of its financial statements, and has concluded that there were no such events that require adjustment to, or disclosure in, the notes to the financial statements.
 
 
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

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

Critical Accounting Policies and Estimates

The following discussion and analysis of the Fund’s financial condition and operating results is based on its financial statements.  The preparation of this Quarterly Report requires the Fund to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of the Fund’s financial statements, and the reported amount of revenue and expense during the reporting period. Actual results may differ from those estimates and assumptions.  See “Notes to Unaudited Condensed Financial Statements” in Part I of this Quarterly Report for a presentation of the Fund’s significant accounting policies.  No changes have been made to the Fund’s critical accounting policies and estimates disclosed in its 2010 Annual Report on Form 10-K.

Overview of the Fund’s Business

The Fund is a Delaware limited liability company formed on December 21, 2004 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.  Ridgewood Energy Corporation (“Ridgewood Energy” or the “Manager”) a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management of the Fund’s operations.  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 Fund’s limited liability company agreement (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. For these services, the Manager receives an annual management fee equal to 2.5% of capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, payable monthly.  The Fund does not currently, nor is there any plan to, operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as appropriate. The Manager also participates in distributions.

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

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


         
Total Spent
    
Total
    
   
Working
    
through
    
Fund
    
Lease Block
  
Interest
    
September 30, 2011
    
Budget
  
Status
         
(in thousands)
    
Non-producing Properties
                    
Alpha Project
 2.25%   $ 2,938     $ 4,280  
Completion efforts are ongoing. Production expected to commence in first quarter 2012.
Beta Project
 5.0%   $ 2,823     $ 8,684  
Drilling commenced in March 2010 and was suspended due to the moratorium. Permit to resume drilling was obtained in August 2011. Drilling expected to resume in fourth quarter 2011.
Diller Project
 0.75%   $ 160     $ 2,990  
Acquired interest in May 2010. Drilling date expected in fourth quarter 2011, pending permit approval. See further discussion below.
Marmalard Project
 0.75%   $ 187     $ 4,112  
Acquired interest in May 2010. Drilling date to be determined. See further discussion below.
Producing Properties
                        
South Pelto 9
 16.67%   $ 5,026     $ 5,026  
Production commenced in 2007. Well shut-in from March 2011 through September 2011 for repairs to downstream pipeline, which were completed at no cost to the Fund.
Eugene Island 346/347 well #1
 5.0%   $ 3,494     $ 3,519  
Production commenced in 2008. Recompletion efforts to access behind the pipe reserves are planned for fourth quarter 2011 at an estimated cost of $25 thousand.
Cobalt Project
 4.0%   $ 1,893     $ 1,945  
Production commenced in 2009. Maintenance work completed in July 2011 at a cost of $4 thousand, which increased well's production rates. Ongoing recompletion efforts planned at an estimated cost of $0.1 million.
Liberty Project
 5.0%   $ 5,598     $ 5,598  
Production commenced July 2010.
 
On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011.  Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

Results of Operations

The following table summarizes the Fund’s results of operations for the three and nine months ended September 30, 2011 and 2010, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1. “Financial Statements” in Part I of this Quarterly Report.


   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
  
Revenue
                        
Oil and gas revenue
   $ 2,212     $ 3,063     $ 7,883     $ 6,394  
                                 
Expenses
                                
Depletion and amortization
     930       949       2,882       2,095  
Dry-hole costs
     4       46       (143 )     2,303  
Management fees to affiliate
     375       417       1,133       1,280  
Operating expenses
     193       191       672       390  
General and administrative expenses
     61       158       221       491  
Total expenses
     1,563       1,761       4,765       6,559  
Income (loss) from operations
     649       1,302       3,118       (165 )
Other income
     141       40       67       145  
Net income (loss)
   $ 790     $ 1,342     $ 3,185     $ (20 )


Overview.  The following table provides information related to the Fund’s oil and gas production during the three and nine months ended September 30, 2011 and 2010.
 
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
Number of wells producing
     4       5       4       5  
Total number of production days
     354       438       915       1,103  
Average mcfe per production day
     583       996       789       884  
 
The decreases in production days and average production rate were principally attributable to the number of productive wells coupled with maintenance activities for the Cobalt Project and South Pelto 9.  See additional discussion in “Business Update” section above.

Oil and Gas Revenue.  Oil and gas revenue for the three months ended September 30, 2011 was $2.2 million, a $0.9 million decrease from the three months ended September 30, 2010.   The decrease is attributable to decreased sales volume totaling $1.3 million, partially offset by the impact of the change in average prices totaling $0.5 million.

Oil and gas revenue for the nine months ended September 30, 2011 was $7.9 million, a $1.5 million increase from the nine months ended September 30, 2010.   The increase is attributable to the impact of the change in average prices totaling $1.7 million, partially offset by a net decrease in sales volume totaling $0.2 million.

The following table provides information related to the Fund’s oil and gas revenue during the three and nine months ended September 30, 2011 and 2010.
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
Oil sales in thousands of barrels
     16       22       57       34  
Average oil price per barrel
   $ 104     $ 74     $ 104     $ 75  
Gas sales in thousands of mcfs
     83       230       289       611  
Average gas price per mcf
   $ 4.29     $ 4.55     $ 4.16     $ 4.62  
 
The decreases in gas sales volumes during the three and nine months ended September 30, 2011 were primarily related to declines in production for the South Pelto 9 well and the Eugene Island 346/347 wells. The decrease in oil sales volumes during the three months ended September 30, 2011 was primarily related to declines in production for the South Pelto 9 well and the Cobalt Project.  The increase in oil sales volumes during the nine months ended September 30, 2011 was primarily related to the timing of the onset of production for the Liberty Project.  See further discussion in “Overview” above.
 
 
Depletion and Amortization.  Depletion and amortization for the three months ended September 30, 2011 was $0.9 million, a decrease of $19 thousand from the three months ended September 30, 2010.  Depletion and amortization for the nine months ended September 30, 2011 was $2.9 million, an increase of $0.8 million from nine months ended September 30, 2010.  The decrease in the three month period resulted from a decrease in production volumes totaling $0.5 million, principally offset by an increase in average depletion rates totaling $0.5 million.  The increase in the nine month period resulted from an increase in average depletion rates totaling $1.3 million, partially offset by a decrease in production volumes totaling $0.5 million.  The changes in average depletion rates were principally the result of higher cost reserve additions.
 
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.
 
   
Three months ended September 30,
    
Nine months ended September 30,
  
Lease Block
  
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
  
Targa Project
   $ (1 )   $ -     $ -     $ 2,276  
Other wells
     5       46       (143 )     27  
    $ 4     $ 46     $ (143 )   $ 2,303  
 
Management Fees to Affiliate.   Management fees for each of the three months ended September 30, 2011 and 2010 were $0.4 million.   Management fees for the nine months ended September 30, 2011 and 2010 were $1.1 million and $1.3 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.
 
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
  
Lease operating expense
   $ 190     $ 181     $ 637     $ 322  
Geological costs and other
     3       10       35       68  
    $ 193     $ 191     $ 672     $ 390  
 
Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  The average production cost was $0.92 per mcfe during the three months ended September 30, 2011 compared to $0.44 per mcfe during the three months ended September 30, 2010.  The average production cost was $0.88 per mcfe during the nine months ended September 30, 2011 compared to $0.34 per mcfe during the nine months ended September 30, 2010.  Geological costs represent costs incurred to obtain seismic data, surveys and lease rentals for the Fund’s projects.

General and Administrative Expenses.  General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the following table.
 
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
Insurance expense
   $ 31     $ 108     $ 104     $ 342  
Accounting fees
     24       41       97       119  
Trust fees and other
     6       9       20       30  
    $ 61     $ 158     $ 221     $ 491  
 
Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling and directors’ and officers’ liability insurance.  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.
 
 
Other Income.  Other income for the three and nine months ended September 30, 2011 and 2010 is detailed in the following table.

   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2011
    
2010
    
2011
    
2010
  
   
(in thousands)
  
Interest income
   $ 9     $ 12     $ 33     $ 37  
Realized (losses) gains on derivative instruments
     (60 )     27       (113 )     79  
Unrealized gains on derivative instruments
     192       1       147       29  
    $ 141     $ 40     $ 67     $ 145  

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the nine months ended September 30, 2011 were $5.9 million, primarily related to revenue received of $8.3 million, partially offset by management fees of $1.1 million, operating expenses of $0.7 million, the purchase of derivative instruments of $0.3 million and general and administrative expenses paid of $0.3 million.

Cash flows provided by operating activities for the nine months ended September 30, 2010 were $4.4 million, primarily related to revenue received of $6.4 million, partially offset by management fees of $1.3 million, general and administrative expenses of $0.5 million and operating expenses paid of $0.3 million.

Investing Cash Flows
Cash flows provided by investing activities for the nine months ended September 30, 2011 were $4.1 million, primarily related to proceeds from the maturity of U.S. Treasury securities totaling $13.0 million and proceeds from the sale of the Aspen Project of $2.3 million, partially offset by investments in U.S. Treasury securities of $10.4 million and capital expenditures for oil and gas properties totaling $0.8 million, inclusive of advances.

Cash flows used in investing activities for the nine months ended September 30, 2010 were $1.3 million, primarily related to investments in U.S. Treasury securities totaling $17.0 million and capital expenditures for oil and gas properties totaling $8.3 million, partially offset by proceeds from the maturity of U.S. Treasury securities totaling $24.0 million.

Financing Cash Flows
Cash flows used in financing activities for the nine months ended September 30, 2011 were $8.6 million, related to manager and shareholder distributions.

Cash flows used in financing activities for the nine months ended September 30, 2010 were $3.8 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 September 30, 2011, the Fund had committed to spend an additional $14.0 million related to its investment properties, of which $8.8 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.

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 September 30, 2011 and December 31, 2010 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators.  On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities.  The Fund does not negotiate such contracts.  No contractual obligations exist at September 30, 2011 and December 31, 2010 other than those discussed in “Estimated Capital Expenditures” above.
 
Recent Accounting Pronouncements
 
See Note 1 of Notes to Unaudited Condensed Financial Statements – “Organization and Summary of Significant Accounting Policies” contained in this Quarterly Report for a discussion of recent accounting pronouncements.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4.  CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Fund’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Fund’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of September 30, 2011.
 
There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.
 
 
PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

ITEM 1A. RISK FACTORS

Not required.

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

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. (REMOVED AND RESERVED)

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS
 
EXHIBIT
NUMBER
TITLE OF EXHIBIT
    
METHOD OF FILING
         
31.1
Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
    
Filed herewith
         
31.2
Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
    
Filed herewith
         
32
Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund.
    
Filed herewith
         
101.INS
XBRL Instance Document
    
*
         
101.SCH
XBRL Taxonomy Extension Schema
    
*
         
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
    
*
         
101.LAB
XBRL Taxonomy Extension Label Linkbase
    
*
         
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
    
*
 
* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Act of 1934 and otherwise are not subject to liability.
 
 

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

           
RIDGEWOOD ENERGY O FUND, LLC
 
Dated:
November 3, 2011
By:
/s/
    
ROBERT E. SWANSON
     
Name:
    
Robert E. Swanson
     
Title:
    
Chief Executive Officer
           
(Principal Executive Officer)
             
             
Dated:
November 3, 2011
By:
/s/
    
KATHLEEN P. MCSHERRY
     
Name:
    
Kathleen P. McSherry
     
Title:
    
Executive Vice President and Chief Financial Officer
           
(Principal Financial Officer)
             
             
 
 
 
 
 
 
17