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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q


ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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.  000-52576

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


Delaware
(State or other jurisdiction of
incorporation or organization)
20-4077773
(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  ý 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 ý      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
 
ý
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).       Yes  o  No  ý
 
As of October 27, 2011 the Fund had 839.5395 shares of LLC Membership Interest outstanding.



 
 

 
 
  PAGE
PART I - FINANCIAL INFORMATION
 
1
    1
    2
    3
    4
11
16
16
     
PART II - OTHER INFORMATION
 
18
18
18
18
18
18
18
     
  19
 
 
 
 

 

PART I – FINANCIAL INFORMATION


RIDGEWOOD ENERGY S FUND, LLC
(in thousands, except share data)

   
September 30, 2011
   
December 31, 2010
 
ASSETS
           
Current assets:
           
Cash and cash equivalents
  $ 2,157     $ 3,961  
Short-term investments in marketable securities
    3,000       2,998  
Salvage fund
    566       -  
Production receivable
    140       854  
Receivable from sale of oil and gas properties
    -       2,250  
Other current assets
    218       95  
Total current assets
    6,081       10,158  
Salvage fund
    1,074       2,364  
Oil and gas properties:
               
Advances to operators for working interests and expenditures
    -       402  
Unproved properties
    1,412       1,410  
Proved properties
    48,507       46,828  
Less:  accumulated depletion and amortization
    (28,563 )     (25,532 )
Total oil and gas properties, net
    21,356       23,108  
Total assets
  $ 28,511     $ 35,630  
                 
LIABILITIES AND MEMBERS' CAPITAL
               
Current liabilities:
               
Due to operators
  $ 1,449     $ 1,151  
Asset retirement obligations
    129       911  
Accrued expenses
    66       89  
Total current liabilities
    1,644       2,151  
Asset retirement obligations
    1,284       1,285  
Total liabilities
    2,928       3,436  
Commitments and contingencies (Note 6)
               
Members' capital:
               
Manager:
               
Distributions
    (5,148 )     (4,626 )
Retained earnings
    3,113       2,847  
Manager's total
    (2,035 )     (1,779 )
Shareholders:
               
Capital contributions (1,000 shares authorized;
               
839.5395 issued and outstanding)
    124,401       124,401  
Syndication costs
    (14,236 )     (14,236 )
Distributions
    (31,270 )     (26,216 )
Accumulated deficit
    (51,277 )     (49,976 )
Shareholders' total
    27,618       33,973  
Total members' capital
    25,583       32,194  
Total liabilities and members' capital
  $ 28,511     $ 35,630  
 
The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
RIDGEWOOD ENERGY S 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
  $ 623     $ 2,722     $ 4,080     $ 7,634  
Expenses
                               
Depletion and amortization
    303       3,118       3,031       7,981  
Dry-hole costs
    -       (12 )     -       2,264  
Management fees to affiliate (Note 4)
    449       510       1,394       1,610  
Operating expenses
    154       226       492       795  
General and administrative expenses
    31       74       212       358  
Total expenses
    937       3,916       5,129       13,008  
Loss from operations
    (314 )     (1,194 )     (1,049 )     (5,374 )
Other income
    105       89       14       356  
Net loss
    (209 )     (1,105 )     (1,035 )     (5,018 )
Other comprehensive loss
                               
Unrealized loss on marketable securities
    -       (53 )     -       (197 )
Total comprehensive loss
  $ (209 )   $ (1,158 )   $ (1,035 )   $ (5,215 )
                                 
Manager Interest
                               
Net income
  $ 10     $ 262     $ 266     $ 652  
                                 
Shareholder Interest
                               
Net loss
  $ (219 )   $ (1,367 )   $ (1,301 )   $ (5,670 )
Net loss per share
  $ (261 )   $ (1,629 )   $ (1,550 )   $ (6,754 )
 
The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
 RIDGEWOOD ENERGY S FUND, LLC
(in thousands)

   
Nine months ended September 30,
 
 
 
2011
   
2010
 
             
Cash flows from operating activities
           
Net loss
  $ (1,035 )   $ (5,018 )
Adjustments to reconcile net loss to net cash
               
   provided by operating activities:
               
Depletion and amortization
    3,031       7,981  
Dry-hole costs
    -       2,264  
Realized gain on marketable securities
    -       (32 )
Amortization of premium on investment
    -       90  
Derivative instrument loss (income)
    14       (80 )
Derivative instrument settlements
    128       106  
Changes in assets and liabilities:
               
Decrease (increase) in production receivable
    714       (469 )
Increase in other current assets
    (269 )     (168 )
Increase in due to operator
    73       5  
(Decrease) increase in accrued expenses
    (23 )     3  
Settlements of asset retirement obligations
    (783 )     -  
Net cash provided by operating activities
    1,850       4,682  
                 
Cash flows from investing activities
               
Capital expenditures for oil and gas properties
    (1,052 )     (7,566 )
Proceeds from sale of oil and gas properties
    2,250       -  
Proceeds from held-to-maturity securities
    3,000       -  
Investments in marketable securities
    (3,000 )     -  
Proceeds from available-for-sale securities
    -       2,547  
Proceeds from (investments in) salvage fund, net
    724       (25 )
Net cash provided by (used in) investing activities
    1,922       (5,044 )
                 
Cash flows from financing activities
               
Distributions
    (5,576 )     (3,721 )
Net cash used in financing activities
    (5,576 )     (3,721 )
                 
Net decrease in cash and cash equivalents
    (1,804 )     (4,083 )
Cash and cash equivalents, beginning of period
    3,961       4,948  
Cash and cash equivalents, end of period
  $ 2,157     $ 865  
                 
                 
Supplemental schedule of non-cash investing activities
               
Advances used for capital expenditures in oil and gas properties
reclassified to proved properties
  $ 402     $ -  
 
The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
RIDGEWOOD ENERGY S FUND, LLC

 
1.  Organization and Summary of Significant Accounting Policies
 
Organization
The Ridgewood Energy S Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on December 19, 2005 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of February 1, 2006 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 $1.3 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 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 September 30, 2011, the Fund had short-term, held-to-maturity investments of $3.0 million, which mature in April 2012.

During 2010, the Fund had investments in U.S. Treasury securities, which matured in December 2010, that were classified as available-for-sale.  Available-for-sale securities are carried in the financial statements at fair value.  In June 2010, the Fund sold a portion of these investments, which were purchased in March 2008.  Gross proceeds from the sale totaled $2.6 million, which included interest income of $4 thousand and a realized gain on investment of $32 thousand.  

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized.
 
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 $1.1 million, which mature in December 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 $1.2 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.  The following table presents changes in asset retirement obligations for the nine months ended September 30, 2011 and the year ended December 31, 2010.

   
September 30, 2011
   
December 31, 2010
 
   
(in thousands)
 
Balance, beginning of period
  $ 2,196     $ 2,160  
Liabilities settled
    (783 )     -  
Accretion expense
    -       36  
Balance, end of period
  $ 1,413     $ 2,196  
 
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 $22 thousand and $2.2 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
    1,637     $ 105.00     $ 19  
October 1, 2011 - April 30, 2012
 
Put Options
    781     $ 112.00     $ 13  
October 1, 2011 - April 30, 2012
 
Put Options
    781     $ 100.00     $ 7  
                             
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
    63,994     $ 4.25     $ 31  
October 1, 2011 - October 31, 2011
 
Put Options
    63,994     $ 4.35     $ 38  
 
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
  $ (35 )   $ 20     $ (77 )   $ 59  
Unrealized gains on derivative instruments
    131       1       63       21  
    $ 96     $ 21     $ (14 )   $ 80  
 
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 no unproved properties with capitalized exploratory well costs in excess of one year.

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 $3.5 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.  The Fund recorded credits to dry-hole costs of $12 thousand for the three months ended September 30, 2010.  Dry-hole costs of $2.3 million, inclusive of credits, for the nine months ended September 30, 2010, related primarily to the Targa Project.  The Fund had no dry-hole costs for the three and nine months ended September 30, 2011.
 
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 the three months ended September 30, 2011 and 2010 were $0.4 million and $0.5 million, respectively.  Management fees for the nine months ended September 30, 2011 and 2010 were $1.4 million and $1.6 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 nine months ended September 30, 2011 and 2010, were $0.5 million and $0.6 million, respectively.  Distributions paid to the Manager for the three months ended September 30, 2010 were $0.3 million.  The Fund did not pay distributions during the three months ended September 30, 2011.
 
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, salvage fund, production receivable, receivable from sale of oil and gas properties 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 $6.8 million related to its investment properties, of which $3.6 million is expected to be spent during the next twelve months. Included in these amounts are estimated costs of $0.8 million related to the West Cameron 75 pipeline repair.  West Cameron 75 has been shut-in since March 30, 2011 as a result of damages sustained to its production pipeline, which is owned by a third-party company.  During the third quarter, the Fund agreed to participate in the repair costs of the pipeline in order to facilitate resumption of production.

As of September 30, 2011, the Fund’s commitments of $6.8 million exceed its available working capital by $2.4 million. Based upon its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations.  Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.  In the event of a temporary production stoppage, causing the Fund’s wells to not produce cash flow from operations, the Fund may borrow from the Manager until such time that production is resumed.  At such time the Manager determines that the Fund is no longer capable of continuing to fund its operations, the Manager would elect to dissolve the Fund.

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.

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.
 
 
 
 
 
 
 

Cautionary Statement Regarding Forward-Looking Statements

Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy S 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 19, 2005 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.
 
Lease Block
 
Working
Interest
   
Total Spent through
September 30, 2011
   
Total
Fund
Budget
 
Status
         
(in thousands)
   
Non-producing Properties
                   
Beta Project
  2.5%     $ 1,412     $ 4,342  
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.
Producing Properties
                       
Main Pass 275
  30.0%     $ 5,768     $ 5,798  
Production commenced in 2007.  Minor recompletion is planned for 2013 at an estimated cost of $30 thousand.
South Marsh Island 111
  22.5%     $ 7,343     $ 7,366  
Production commenced in 2009.  Recompletion efforts to access behind the pipe reserves commenced in April 2011 and completed in May 2011 at a cost of $0.9 million.  Well shut-in since August 2011, for approximately two months, for pipeline maintenance.   Minor recompletion is also planned for 2012 at an estimated cost of $23 thousand.
West Cameron 75
  20.0%     $ 25,274     $ 29,074  
Production commenced in 2007.  Well has been shut-in since March 30, 2011 as a result of damages sustained by the pipeline during a dredging operation performed by the US Army Corps of Engineers. The Fund has agreed to participate in the costs to repair and deepen the third-party pipeline and estimates the costs to be $0.8 million.  The repair efforts are expected to be completed during the fourth quarter 2011.  An additional recompletion is planned for 2013 at an estimated cost of $3.0 million.
West Delta 68
  22.5%     $ 5,349     $ 5,372  
Production commenced in 2008. Recompletion planned for 2014 at an estimated cost of $23 thousand.
Fully Depleted
                       
West Delta 67
  22.5%     $ 3,555       N/A  
Production commenced in 2008.   Determined to be fully depleted during second quarter 2011.
 
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
  $ 623     $ 2,722     $ 4,080     $ 7,634  
Expenses
                               
Depletion and amortization
    303       3,118       3,031       7,981  
Dry-hole costs
    -       (12 )     -       2,264  
Management fees to affiliate
    449       510       1,394       1,610  
Operating expenses
    154       226       492       795  
General and administrative expenses
    31       74       212       358  
Total expenses
    937       3,916       5,129       13,008  
Loss from operations
    (314 )     (1,194 )     (1,049 )     (5,374 )
Other income
    105       89       14       356  
Net loss
    (209 )     (1,105 )     (1,035 )     (5,018 )
Other comprehensive loss
                               
Unrealized loss on marketable securities
    -       (53 )     -       (197 )
Total comprehensive loss
  $ (209 )   $ (1,158 )   $ (1,035 )   $ (5,215 )
 
 
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
    3       5       5       5  
Total number of production days
    231       341       714       1,012  
Average mcfe per production day
    405       1,774       1,037       1,601  
 
The decreases in production days and average production rate were principally attributable to the West Cameron 75 well, which has been shut-in since March 30, 2011, coupled with one of the Fund’s wells reaching the end of its economic life during second quarter 2011.  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 $0.6 million, a $2.1 million decrease from the three months ended September 30, 2010.  The decrease is attributable to decreased sales volume totaling $2.2 million partially offset by the impact of the change in average prices totaling $0.1 million.

Oil and gas revenue for the nine months ended September 30, 2011 was $4.1 million, a $3.6 million decrease from the nine months ended September 30, 2010.  The decrease is attributable to decreased sales volume totaling $3.9 million partially offset by the impact of the change in average prices totaling $0.3 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
    2       5       10       13  
Average oil price per barrel
  $ 104     $ 75     $ 102     $ 76  
Gas sales in thousands of mcfs
    69       528       605       1,404  
Average gas price per mcf
  $ 4.33     $ 4.15     $ 3.88     $ 4.20  
 
The decreases in oil and gas volumes were primarily the result of West Cameron 75, which has been shut-in since March 30, 2011, coupled with one of the Fund’s wells reaching the end of its economic life during second quarter 2011. 
 
 
Depletion and Amortization.  Depletion and amortization for the three and nine months ended September 30, 2011 was $0.3 million and $3.0 million, respectively, a decrease of $2.8 million and $5.0 million from the three and nine months ended September 30, 2010, respectively.  The decrease in the three month period resulted from a decrease in production volumes totaling $2.6 million coupled with a decrease in average depletion rates totaling $0.2 million.  The decrease in the nine month period resulted from a decrease in production volumes totaling $4.2 million coupled with a decrease in average depletion rates totaling $0.7 million.  The decreases in average depletion rates for the three and nine month periods were primarily the result of the impact of the shut-in West Cameron 75 well, which has higher cost reserves.

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.   The Fund recorded credits to dry-hole costs of $12 thousand for the three months ended September 30, 2010.  Dry-hole costs of $2.3 million, inclusive of credits, for the nine months ended September 30, 2010, related primarily to the Targa Project.  The Fund had no dry-hole costs for the three and nine months ended September 30, 2011.

Management Fees to Affiliate.  Management fees for the three months ended September 30, 2011 and 2010 were $0.4 million and $0.5 million, respectively.  Management fees for the nine months ended September 30, 2011 and 2010 were $1.4 million and $1.6 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
  $ 154     $ 243     $ 492     $ 778  
Other
    -       (17 )     -       17  
    $ 154     $ 226     $ 492     $ 795  
 
Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  The average production cost was $1.65 per mcfe and $0.66 per mcfe during the three and nine months ended September 30, 2011, respectively, compared to $0.41 per mcfe and $0.49 per mcfe during the three and nine months ended September 30, 2010, respectively.

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
  $ 26     $ 29     $ 118     $ 212  
Accounting fees
    5       40       90       131  
Trust fees and other
    -       5       4       15  
    $ 31     $ 74     $ 212     $ 358  
 
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     $ 68     $ 28     $ 244  
Realized (losses) gains on derivative instruments
    (35 )     20       (77 )     59  
Unrealized gains on derivative instruments
    131       1       63       21  
Realized gain on sale of marketable securities
    -       -       -       32  
    $ 105     $ 89     $ 14     $ 356  
 
Unrealized Loss on Marketable Securities.  During 2007, the Fund purchased available-for-sale U.S. Treasury securities, which matured in December 2010.  Unrealized gains and losses related to the securities' changes in fair value were recorded in other comprehensive income until realized.  For the three and nine months ended September 30, 2010, the Fund recorded unrealized losses of $0.1 million and $0.2 million, respectively.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the nine months ended September 30, 2011 were $1.9 million, primarily related to revenue received of $4.8 million coupled with derivative instrument settlements of $0.1 million, partially offset by management fees of $1.4 million, the settlement of asset retirement obligations of $0.8 million, operating expenses paid of $0.4 million, general and administrative expenses paid of $0.3 million and the purchase of derivative instruments of $0.2 million.

Cash flows provided by operating activities for the nine months ended September 30, 2010 were $4.7 million, primarily related to revenue received of $7.2 million and interest income received of $0.3 million, partially offset by management fees of $1.6 million, operating expenses of $0.8 million and general and administrative expenses of $0.4 million.

Investing Cash Flows
Cash flows provided by investing activities for the nine months ended September 30, 2011 were $1.9 million, primarily related to proceeds from U.S. Treasury securities of $3.0 million, proceeds received from the sale of the Aspen Project of $2.3 million and proceeds from the salvage fund of $0.7 million, partially offset by purchases of U.S. Treasury securities of $3.0 million and capital expenditures for oil and gas properties of $1.1 million.

Cash flows used in investing activities for the nine months ended September 30, 2010 were $5.0 million, primarily related to capital expenditures for oil and gas properties of $7.6 million, partially offset by proceeds from the sale of U.S. Treasury securities of $2.5 million.

Financing Cash Flows
Cash flows used in financing activities for the nine months ended September 30, 2011 were $5.6 million, related to manager and shareholder distributions.
 
Cash flows used in financing activities for the nine months ended September 30, 2010 were $3.7 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 $6.8 million related to its investment properties, of which $3.6 million is expected to be spent during the next twelve months.  Included in these amounts are estimated costs of $0.8 million related to the West Cameron 75 pipeline repair.  During the third quarter, the Fund agreed to participate in the repair costs of the pipeline in order to facilitate resumption of production.
 
 
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.  As of September 30, 2011, the Fund had commitments of $6.8 million that exceed its current available working capital by $2.4 million.   Based upon its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations.  Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.  In the event of a temporary production stoppage, causing the Fund’s wells to not produce cash flow from operations, the Fund may borrow from the Manager until such time that production is resumed.  At such time the Manager determines that the Fund is no longer capable of continuing to fund its operations, the Manager would elect to dissolve the Fund.

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.


Not required.


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


None.


Not required.


None.


None.



None.


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 S FUND, LLC
 
Dated:
October 27, 2011
By:
/s/
   
ROBERT E. SWANSON
     
Name:
   
Robert E. Swanson
     
Title:
   
Chief Executive Officer
           
(Principal Executive Officer)
             
             
Dated:
October 27, 2011
By:
/s/
   
KATHLEEN P. MCSHERRY
     
Name:
   
Kathleen P. McSherry
     
Title:
   
Executive Vice President and Chief Financial Officer
           
(Principal Financial Officer)
             
             
 
 
 
 
 
 19