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

FORM 10-Q

ýx
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2011March 31, 2012
 
or
 
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 EXCHANGE ACT OF 1934
 For the transition period from _______________________to___________________________________________ to __________________

Commission File No.Number: 000-53895

RIDGEWOOD ENERGY A-1 FUND, LLC
(Exact name of registrant as specified in its charter)


 Delaware
Delaware01-0921132
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization) 
01-0921132
(I.R.S. Employer
Identification No.)
 

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

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


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

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

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

Large accelerated fileroAccelerated filero
Non-accelerated filer
oSmaller reporting companyx
(Do not check if a smaller reporting company) oSmaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Act.)  Yes oNo x

As of July 26, 2011April 30, 2012 the Fund had 207.7026 shares of LLC Membership Interest outstanding.



 
 


Table of Contents



PAGE
PART I - FINANCIAL INFORMATIONPAGE
1
 1
 
2
 
3
 4
10
15
15
   
PART II - OTHER INFORMATION 
1516
1516
1516
1516
1516
1516
1617
   
 1718
 
 
 

 
 
 
 

 
PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

RIDGEWOOD ENERGY A-1 FUND, LLC
UNAUDITED CONDENSED BALANCE SHEETS
(in thousands, except share data)

 June 30,  December 31,  March 31, 2012  December 31, 2011 
 2011  2010 
ASSETS      
Assets      
Current assets:            
Cash and cash equivalents $5,828  $10,249  $5,823  $6,817 
Production receivable  1,136   1,576   1,488   1,840 
Other current assets  419   68   19   66 
Total current assets  7,383   11,893   7,330   8,723 
Salvage fund  1,047   1,024   1,284   1,276 
        
Oil and gas properties:                
Advances to operators for working interests and expenditures  149   181 
Unproved properties  5,917   5,790   2,501   8,078 
Proved properties  17,521   12,591   24,897   18,144 
Less: accumulated depletion and amortization  (4,353)  (1,471)  (9,299)  (7,915)
Total oil and gas properties, net  19,234   17,091   18,099   18,307 
Total assets $27,664  $30,008  $26,713  $28,306 
                
LIABILITIES AND MEMBERS' CAPITAL        
Liabilities and Members' Capital        
Current liabilities:                
Due to operators $706  $1,350  $2,074  $2,155 
Accrued expenses  80   354   31   29 
Total current liabilities  786   1,704   2,105   2,184 
        
Asset retirement obligations  664   497   1,101   1,101 
Total liabilities  1,450   2,201   3,206   3,285 
                
Commitments and contingencies (Note 9)        
Commitments and contingencies (Note 6)        
Members' capital:                
Manager:                
Distributions  (582)  (101)  (1,801)  (1,323)
Retained earnings (accumulated deficit)  550   (102)
Retained earnings  2,068   1,611 
Manager's total  (32)  (203)  267   288 
                
Shareholders:                
Capital contributions (250 shares authorized;                
207.7026 issued and outstanding)  41,143   41,143   41,143   41,143 
Syndication costs  (4,804)  (4,804)  (4,804)  (4,804)
Distributions  (3,298)  (574)  (10,207)  (7,498)
Accumulated deficit  (6,807)  (7,755)  (2,911)  (4,127)
Shareholders' total  26,234   28,010   23,221   24,714 
Accumulated other comprehensive gain  12   - 
Accumulated other comprehensive income  19   19 
Total members' capital  26,214   27,807   23,507   25,021 
Total liabilities and members' capital $27,664   30,008  $26,713  $28,306 
 
The accompanying notes are an integral part of these unaudited condensed financial statements.

 
1

 
RIDGEWOOD ENERGY A-1 FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS AND
COMPREHENSIVE INCOME (LOSS)
(in thousands, except per share data)

  Three months ended June 30,  Six months ended June 30, 
  2011  2010  2011  2010 
Revenue         
Oil and gas revenue $2,582  $-  $5,386  $- 
                 
Expenses                
Depletion and amortization  1,428   -   2,882   - 
Dry-hole costs  (8)  3,233   61   3,233 
Impairment of oil and gas properties  -   245   -   245 
Management fees to affiliate (Note 7)  233   257   466   514 
Operating expenses  121   44   250   261 
General and administrative expenses  116   57   113   107 
Total expenses  1,890   3,836   3,772   4,360 
Income (loss) from operations  692   (3,836)  1,614   (4,360)
Other (loss) income  (21)  14   (14)  22 
Net income (loss)  671   (3,822)  1,600   (4,338)
Other comprehensive income (loss)                
Unrealized gain on marketable securities  8   14   12   2 
Total comprehensive income (loss) $679  $(3,808) $1,612  $(4,336)
                 
Manager Interest                
Net income (loss) $300  $(81) $652  $(128)
                 
Shareholder Interest                
Net income (loss) $371  $(3,741) $948  $(4,210)
Net income (loss) per share $1,787  $(18,011) $4,563  $(20,269)

The accompanying notes are an integral part of these unaudited condensed financial statements.
2

Table of Contents
RIDGEWOOD ENERGY A-1 FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
  Six months ended June 30, 
  2011  2010 
       
Cash flows from operating activities      
Net income (loss) $1,600  $(4,338)
Adjustments to reconcile net income (loss) to net cash        
   provided by (used in) operating activities:        
Depletion and amortization  2,882   - 
Derivative instrument loss  26   - 
Dry-hole costs  61   3,233 
Impairment of oil and gas properties  -   245 
Changes in assets and liabilities:        
Decrease in production receivable  440   - 
Increase in other current assets  (76)  (10)
Increase in due to operators  62   - 
Decrease in accrued expenses  (274)  (555)
Net cash provided by (used in) operating activities  4,721   (1,425)
         
Cash flows from investing activities        
Payments to operators for working interests and expenditures  (149)  (43)
Capital expenditures for oil and gas properties  (5,777)  (6,874)
Proceeds from the maturity of investments  -   8,004 
Investments in salvage fund  (11)  (6)
Net cash (used in) provided by investing activities  (5,937)  1,081 
         
Cash flows from financing activities        
Contributions from shareholders  -   25 
Syndication costs  -   (1)
Distributions  (3,205)  - 
Net cash (used in) provided by financing activities  (3,205)  24 
Net decrease in cash and cash equivalents  (4,421)  (320)
Cash and cash equivalents, beginning of period  10,249   5,890 
Cash and cash equivalents, end of period $5,828  $5,570 
         
Supplemental schedule of non-cash investing activities        
Advances used for capital expenditures in oil and gas
properties reclassified to proved and unproved properties
 $181  $2,713 
  Three months ended March 31, 
  2012  2011 
Revenue      
Oil and gas revenue $3,741  $2,804 
         
Expenses        
Depletion and amortization  1,384   1,454 
Dry-hole costs  63   69 
Management fees to affiliate (Note 4)  233   233 
Operating expenses  323   129 
General and administrative expenses  45   (3)
Total expenses  2,048   1,882 
Income from operations  1,693   922 
Other (loss) income  (20)  7 
Net income  1,673   929 
Other comprehensive income        
Unrealized gain on marketable securities  -   4 
Total comprehensive income $1,673  $933 
         
Manager Interest        
Net income $457  $352 
         
Shareholder Interest        
Net income $1,216  $577 
Net income per share $5,854  $2,776 
 
The accompanying notes are an integral part of these unaudited condensed financial statements.

2

RIDGEWOOD ENERGY A-1 FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)

  Three months ended March 31, 
  2012  2011 
       
Cash flows from operating activities      
Net income $1,673  $929 
Adjustments to reconcile net income to net cash        
   provided by operating activities:        
Depletion and amortization  1,384   1,454 
Dry-hole costs  63   69 
Derivative instrument loss  29   - 
Derivative instrument settlements  2   - 
Changes in assets and liabilities:        
Decrease in production receivable  352   14 
Decrease in other current assets  16   11 
(Decrease) increase in due to operators  (98)  52 
Increase (decrease) in accrued expenses  2   (300)
Net cash provided by operating activities  3,423   2,229 
         
Cash flows from investing activities        
Capital expenditures for oil and gas properties  (1,222)  (4,484)
Interest reinvested in salvage fund  (8)  (5)
Net cash used in investing activities  (1,230)  (4,489)
         
Cash flows from financing activities        
Distributions  (3,187)  (1,177)
Net cash used in financing activities  (3,187)  (1,177)
Net decrease in cash and cash equivalents  (994)  (3,437)
Cash and cash equivalents, beginning of period  6,817   10,249 
Cash and cash equivalents, end of period $5,823  $6,812 
         
Supplemental schedule of non-cash investing activities        
Advances used for capital expenditures in oil and gas
properties reclassified to proved properties
 $-  $141 
The accompanying notes are an integral part of these unaudited condensed financial statements.

 
3


RIDGEWOOD ENERGY A-1 FUND, LLC
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1.   Organization and Purpose
1.Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy A-1 Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement") dated as of March 2, 2009 by and among Ridgewood Energy Corporation (the "Manager") and the shareholders of the Fund.  The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. In July 2010, the Fund began earning revenue and, as a result, was determined by the Manager to no longer be an exploratory stage enterprise.

The Manager has direct and exclusive control over the management of the Fund'sFund’s operations.  With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations.  Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information.  In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations.  The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required.  See Notes 2, 74 and 9.

2.   Summary of Significant Accounting Policies6.

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, 20102011 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 June 30, 2011,March 31, 2012, the Fund’s bank balances exceeded federally insured limits by $5.1$3.5 million, all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

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 June 30,March 31, 2012 and December 31, 2011,the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $0.4 million, which mature in January 2012.  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.  Additionally, the Fund had investments in federal agency mortgage-backed securities of $0.3 million and $0.1 million,as detailed in the following table, which mature in June 2039 and April 2040, respectively, that are classified as available-for-sale.available for sale.  Available-for-sale securities are carried in the financial statements at fair value.  The following table is a summary of available-for-sale investments at June 30, 2011 and December 31, 2010:
 
 
4


     Gross    
  Amortized  Unrealized  Fair 
Available-for-Sale Cost  Gains  Value 
  (in thousands) 
Government National Mortgage Association securities (GNMA):       
GNMA June 2039         
   March 31, 2012 $219  $6  $225 
   December 31, 2011 $278  $8  $286 
GNMA April 2040            
   March 31, 2012 $6  $-  $6 
   December 31, 2011 $39  $1  $40 
GNMA July 2041            
   March 31, 2012 $176  $8  $184 
   December 31, 2011 $204  $10  $214 
Federal National Mortgage Association security (FNMA January 2042)         
   March 31, 2012 $747  $5  $752 
   December 31, 2011 $-  $-  $- 
    Gross   
  Amortized Unrealized Fair 
Available-for-Sale Cost Gains Value 
  (in thousands) 
Government National Mortgage Association securities:       
   June 30, 2011 $415 $12 $427 
   December 31, 2010 $490 $- $490 


The unrealized gains on the Fund's investment in federal agency mortgage-backed securities were caused by a reduction in market interest rates. The Fund purchased these securities at a discount relative to their face amount, and the contractual cash flows of those investments are guaranteed by an agency of the U.S. government.  Accordingly, it is expected that the securities would not be settled at a price less than the amortized cost basis of the Fund’s investments. Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  Interest earned on the account will become part of the salvage fund.  There are no restrictions on withdrawals from the salvage fund.

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'sFund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.

TheExploration, development and acquisition costs are accounted for using the successful efforts methodmethod. Costs of accounting foracquiring unproved and proved oil and natural gas producing activities is followed. Acquisitionleasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized.  Exploratory costs are capitalized 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 wellsproved reserves have discovered proved commercial reserves.been found. If proved commercial reserves haveare not been found, exploratory drilling costs are expensed as dry-hole costs. Costs to develop proved reserves, including the costs of all development wellsAnnual lease rentals and related facilities and equipment used in the production of oil and gas, are capitalized.  Expenditures for ongoing repairs and maintenance of producing propertiesexploration expenses 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 June 30, 2011March 31, 2012 and December 31, 2010,2011, amounts recorded in due to operators totaling $0.6$1.9 million, and $1.3 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.
5


Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.
5


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

Revenue Recognition and Imbalances
Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibilitycollectability 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 4.2.  “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.costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs, 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.

6


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
6

3.   Recent Accounting Standardsshares held.  Certain shares have early investment incentive rights, as defined in the LLC Agreement, of $16 thousand per share.  Additionally, shareholders without early investment incentive rights may participate in an advance cash flow distribution, as defined in the LLC Agreement, of $6 thousand per share.  The Fund commenced advance distributions and distributions to early investors in September 2010.  The Fund commenced distributions to all investors in May 2011.

In January 2010,The Manager determines whether available cash from operations, as defined in the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements.  This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective beginning January 1, 2010.  The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, whichLLC Agreement, will be effective fordistributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.

Recent Accounting Pronouncements
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements for the year ending December 31, 2011. The adoption of the guidance is not expected to have a material impact.statements.

4.   
2.Derivative Instruments
 
The Fund periodically enters into derivative contracts relating to its oil or gas 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 Intercontinental Exchange (“ICE”), volatility, and the time value of options.  See Note 8.5. “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”.assets.”  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 (loss) income.” Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.

At June 30, 2011,March 31, 2012, the Fund had outstanding derivative contracts with respect to its future production of oil that are not designated for hedge accounting as detailed in the following table.

Production Period  
Type of
Contract
  
Volume in
barrels
  
ICE Contract
Price per
 barrel
  
Estimated
 Fair Value
 Asset
 
            (in thousands) 
April 1, 2012 - April 30, 2012  Put Options   656  $105.00  $- 
April 1, 2012 - April 30, 2012  Put Options   305  $112.00  $- 
April 1, 2012 - April 30, 2012  Put Options   305  $100.00  $- 

Production Period 
Type of
Contract
 
Volume in
barrels
 
ICE Contract
Price per
barrel
 
Estimated
 Fair Value
 Asset
 
        (in thousands) 
July 1, 2011 - April 30, 2012 Put Options  7,777 $105.00 $34 
July 1, 2011 - April 30, 2012 Put Options  3,724 $112.00 $25 
July 1, 2011 - April 30, 2012 Put Options  3,724 $100.00 $12 
7


For the three and six months ended June 30, 2011,March 31, 2012, the Fund’s derivative instrument income consisted of realized losses of $19 thousand and unrealized losses of $7 thousand.  There was$21 thousand and $8 thousand, respectively.  For the three months ended March 31, 2011 the Fund had no derivative instrument income for the three and six months ended June 30, 2010.instruments.

5.  Oil and Gas Properties

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 June 30, 2011,March 31, 2012, the Fund had oneno unproved property, the Alpha Project,properties 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 fourth quarter 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.  During the three and six months ended June 30,March 31, 2012 and 2011, and 2010, dry-hole costs, inclusive of credits, were related to the Dakota Project.

7

6.   Distributions

Distributions to shareholders are allocated in proportion to the number of shares held.  Certain shares have early investment incentive rights, as defined in the LLC Agreement, of $16 thousand per share.  Additionally, shareholders without early investment incentive rights may participate in an advance cash flow distribution, as defined in the LLC Agreement, of $6 thousand per share.  The Fund commenced advance distributions and distributions to early investors in September 2010.  The Fund commenced distributions to all investors in May 2011.
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.
7.   
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 June 30,March 31, 2012 and 2011 and 2010 were $0.2 million and $0.3 million, respectively.  Management fees for each of the six months ended June 30, 2011 and 2010 were $0.5 million.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund. Distributions paid to the Manager for the three and six months ended June 30,March 31, 2012 and 2011 were $0.3$0.5 million and $0.5$0.2 million, respectively.  There were no distributions paid to the Manager for the three and six months ended June 30, 2010.

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.

8.   Fair Value Measurements
5.Fair Value Measurements

At June 30, 2011March 31, 2012 and December 31, 2010,2011, cash and cash equivalents, production receivable, salvage fund and accrued expenses approximate fair value.  The fair value of the Fund’s mortgage-backed securities was determined using Level 2 inputs as the securities trade in an over-the-counter market. At June 30, 2011,and derivative instruments arewere recorded at fair value based on Level 2 inputs, as thesuch instruments aretrade in over-the-counter derivatives with a third party.markets.

9.   
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 June 30, 2011,March 31, 2012, the Fund had committed to spend an additional $5.1$2.6 million related to its investment properties, of which $4.6$1.2 million is expected to be spent during the next twelve months.
8


Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At June 30, 2011March 31, 2012 and December 31, 2010,2011, there were no known environmental contingencies that required the Fund to record a liability.
8


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.

10.   
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.
 

 
9

 
ITEM 2.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy A-1 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 20102011 Annual Report on Form 10-K.

Overview of the Fund’s Business

The Fund is a Delaware limited liability company formed on February 3, 2009 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.  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"Agreement”).

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) is the Manager, and as such, has direct and exclusive control over the management of the Fund’s operations.  The Manager performs certain duties on the Fund’s behalf including the evaluation of 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 affecteffect on the Fund’s future profitability.
 
 
10

 
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  March 31, 2012  Budget  Status
      (in thousands)   
Non-producing Properties         
Beta Project  2.0%  $2,501  $4,002  Drilling commenced in March 2010 and was suspended due to the moratorium. Drilling resumed in December 2011. Discovery in February 2012. Evaluating options for completion.
Producing Properties              
Alpha Project  3.75%  $6,851  $7,827  Well completed and production commenced in April 2012.
Raven Project well #2  25.0%  $4,354  $4,354  Production commenced in July 2011. Minor maintenance work completed during first quarter 2012 at a cost of $45 thousand.
Carrera Project  2.0%  $3,086  $3,103  Production commenced June 2011. Separator upgrade planned for 2012 at an estimated cost of $17 thousand.
Raven Project well #1  25.0%  $6,528  $6,653  Production commenced in 2010. Recompletion efforts to access behind the pipe reserves are planned for 2014 at an estimated cost totaling $0.1 million.
Liberty Project  2.0%  $3,009  $3,009  Production commenced in 2010.
     Total Spent  Total  
  Working  through  Fund  
Lease Block Interest  June 30, 2011  Budget Status
     (in thousands)  
Non-producing Properties        
Alpha Project 3.75%  $4,656  $7,134 Completion efforts are ongoing.  Production expected to commence in fourth quarter 2011.
Beta Project 2.0%  $1,261  $3,614 Drilling commenced in March 2010 and was suspended due to the moratorium.  Awaiting issuance of drilling permit, which is currently expected in third quarter 2011.  Acquired interest in October 2010.
             
Producing Properties            
Liberty Project 2.0%  $3,010  $3,010 Production commenced July 2010.
Raven Project well #1 25.0%  $6,493  $6,618 Production commenced September 2010.  Well was shut-in for one month, resuming production in June 2011.  Recompletion efforts to access behind the pipe reserves are planned for 2014 at an estimated cost of $0.1 million.
Carrera Project 2.0%  $3,042  $3,042 Production commenced June 2011.
Raven Project well #2 25.0%  $4,325  $4,431 Production commenced July 2011.

Results of Operations

The following table summarizes the Fund’s results of operations for the three and six months ended June 30,March 31, 2012 and 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 ofin this Quarterly Report.
 
 
11

 
 Three months ended June 30,  Six months ended June 30,  Three months ended March 31, 
 2011  2010  2011  2010  2012  2011 
 (in thousands)  (in thousands) 
Revenue                  
Oil and gas revenue $2,582  $-  $5,386  $-  $3,741  $2,804 
                        
Expenses                        
Depletion and amortization  1,428   -   2,882   -   1,384   1,454 
Dry-hole costs  (8)  3,233   61   3,233   63   69 
Impairment of oil and gas properties  -   245   -   245 
Management fees to affiliate  233   257   466   514   233   233 
Operating expenses  121   44   250   261   323   129 
General and administrative expenses  116   57   113   107   45   (3)
Total expenses  1,890   3,836   3,772   4,360   2,048   1,882 
Income (loss) from operations  692   (3,836)  1,614   (4,360)
Income from operations  1,693   922 
Other (loss) income  (21)  14   (14)  22   (20)  7 
Net income (loss)  671   (3,822)  1,600   (4,338)
Other comprehensive income (loss)                
Net income  1,673   929 
Other comprehensive income        
Unrealized gain on marketable securities  8   14   12   2   -   4 
Total comprehensive income (loss) $679   (3,808) $1,612   (4,336)
Total comprehensive income $1,673  $933 
 
Overview.Overview.  The following table provides information related to the Fund’s oil and gas production and oil and gas revenue depletionduring the three months ended March 31, 2012 and amortization2011.
  Three months ended March 31, 
  2012  2011 
Number of wells producing  4   2 
Total number of production days  356   179 
Average mcfe per production day  2,226   2,606 
Oil sales (in thousands of barrels)  16   10 
Average oil price per barrel $110  $98 
Gas sales (in thousands of mcfs)  659   405 
Average gas price per mcf $2.63  $4.38 
The increases in production days and lease operating expenseoil and gas sales volumes were affected by the timing ofprincipally attributable to the onset of production of the Fund’s wells.  During the six months endedRaven Project well #2 in July 2011 and Carrera Project in June 30, 2011, the Fund had three wells that produced for a total of 356 days, at a2011.  The decrease in average production rate that averaged 2,366 mcfe/day.  The Liberty, Raven and Carrera projects commenced productionwas due to the composite of productive wells.  See additional discussion in July 2010, September 2010 and June 2011, respectively.  During the six months ended June 30, 2010, the Fund had no producing properties and was classified as an exploratory stage enterprise.“Business Update” section above.

Oil and Gas Revenue.Revenue.  Oil and gas revenue for the three months ended June 30, 2011March 31, 2012 was $2.6 million.  Oil and gas sales volumes were 10 thousand barrels and 289 thousand mcf, respectively.  The Fund’s oil and gas prices averaged $112 per barrel and $4.53 per mcf, respectively.  The Fund had no oil and gas revenue for$3.7 million, a $0.9 million increase from the three months ended June 30, 2010.

Oil and gas revenueMarch 31, 2011.  The increase is attributable to increased sales volume totaling $2.0 million, partially offset by the impact of the change in average prices totaling $1.0 million.  See “Overview” above for the six months ended June 30, 2011 was $5.4 million.  Oil and gas sales volumes were 19 thousand barrels and 711 thousand mcf, respectively.  The Fund’s oil and gas prices averaged $105 per barrel and $4.46 per mcf, respectively.  The Fund had no oil and gas revenue for the six months ended June 30, 2010.additional information.

Depletion and Amortization.Amortization.  Depletion and amortization for the three and six months ended June 30, 2011March 31, 2012 was $1.4 million, and $2.9a decrease of $0.1 million respectively, related to the Liberty, Raven and Carrera projects.  The Fund did not incur depletion and amortization forfrom the three and six months ended June 30, 2010.March 31, 2011.  The decrease resulted from a decrease in average depletion rates totaling $1.1 million, partially offset by an increase in production volumes totaling $1.0 million.  The decrease in average depletion rates was principally the result of revisions to reserve estimates.

Dry-hole Costs.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.  During the three and six months ended June 30,March 31, 2012 and 2011, and 2010, dry-hole costs, inclusive of credits, were related to the Dakota Project.
Impairment of Oil and Gas Properties.  During the three and six months ended June 30, 2010, the Fund recorded an impairment charge of $0.2 million, representing the carrying cost of the Pearl Project, resulting from the Fund’s election to no longer proceed with the drilling of this well.  The Fund did not record impairment charges during the three and six months ended June 30, 2011.

Management Fees to Affiliate.  Management fees for each of the three and six months ended June 30,March 31, 2012 and 2011 were $0.2 million and $0.5 million, respectively.   Management fees for the three and six months ended June 30, 2010 were $0.3 million and $0.5 million, respectively.million.  An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.
 
 
12


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

 Three months ended June 30, Six months ended June 30,  Three months ended March 31, 
 2011 2010 2011 2010  2012  2011 
 (in thousands) (in thousands) 
Lease operating expense $91 $- $217 $-  $289  $126 
Geological costs and other  35   3 
Workover costs  25  -  25  -   (1)  - 
Geological costs  5  40  8  257 
Other expense  -  4  -  4 
 $121 $44 $250 $261  $323  $129 
 
Lease operating expense was relatedrelates to the onset of production for the Liberty, Raven and Carrera projects.  ForFund’s producing properties during each of the three and six months ended June 30, 2011, theperiod as outlined above in “Overview”.  The average production cost was $0.26$0.36 per mcfe. Workover costsmcfe during the three and six months ended June 30, 2011 relatedMarch 31, 2012 compared to $0.27 per mcfe during the Raven Project.  three months ended March 31, 2011.  Geological costs represent costs incurred to obtain seismic data, surveys, and lease rentals forrentals. Workover costs represent costs to restore or stimulate well production. Workover costs include costs and credits attributable to the Fund’s projects.Raven Project

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

 Three months ended June 30, Six months ended June 30,  Three months ended March 31, 
 2011 2010 2011 2010  2012  2011 
 (in thousands) (in thousands)
Accounting fees $48 $46 $87 $82  $25  $39 
Insurance expense  66  2  21  5   20   (45)
Trust fees and other  2  9  5  20 
Other  -   3 
 $116 $57 $113 $107  $45  $(3)
 
Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  Insurance expense represents premiums related to producing well and control of well insurance, which varies dependentdepending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance.  During the three and six months ended June 30, 2011, the Fund received credits from its insurance provider related to its control of well policy.  Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

Other (Loss) Income.  Income.  Other (loss) income for the three and six months ended June 30,March 31, 2012 and 2011 and 2010 is detailed in the following table.
 
 Three months ended June 30, Six months ended June 30,  Three months ended March 31, 
 2011 2010 2011 2010  2012  2011 
 (in thousands)  (in thousands) 
Interest income $5 $14 $12 $22  $9  $7 
Realized losses on derivative instruments  (19) -  (19) -   (21)  - 
Unrealized losses on derivative instruments  (7) -  (7) -   (8)  - 
 $(21)$14 $(14)$22  $(20) $7 
 
Unrealized Gain on Marketable Securities.  In 2010, theThe Fund purchased two available-for-sale U.S. Government National Mortgage Associationhas investments in federal agency mortgage-backed securities totaling $1.2 million, which mature in June between 2039 and April 2040.2042, that are classified as available-for-sale.  Available-for-sale securities are carried in the financial statements at fair value. Unrealized gains and losses related to the securities’ changes in fair value are recorded in other comprehensive income until realized.  The Fund recognizedhad no unrealized gains of $8 thousand and $12 thousandor losses during the three and six months ended June 30, 2011, respectively.March 31, 2012.  The Fund recognized unrealized gains of $14 thousand and $2$4 thousand during the three and six months ended June 30, 2010, respectively.March 31, 2011.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities for the three months ended March 31, 2012 were $3.4 million, primarily related to revenue received of $4.1 million, partially offset by operating expenses paid of $0.4 million, and management fees of $0.2 million.
 
 
13

 
Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the sixthree months ended June 30,March 31, 2011 were $4.7$2.2 million, primarily related to revenue received of $5.8$2.8 million, partially offset by management fees of $0.5 million, general and administrative expenses paid of $0.4$0.2 million, operating expenses paidmanagement fees of $0.2 million, and the purchase of derivative instruments of $0.1 million

Cash flows used in operating activities for the six months ended June 30, 2010 were $1.4 million, primarily related to payments for control of well insurance of $0.6 million, management fees of $0.5 million, geological costs of $0.3 million and general and administrative expenses of $0.1 million.

Investing Cash Flows
Cash flows used in investing activities for the sixthree months ended June 30, 2011March 31, 2012 were $5.9$1.2 million, related to capital expenditures for oil and gas properties, inclusive of advances.properties.

Cash flows provided byused in investing activities for the sixthree months ended June 30, 2010March 31, 2011 were $1.1$4.5 million, primarily related to proceeds from the maturity of U.S. Treasury securities totaling $8.0 million, partially offset by capital expenditures for oil and gas properties totaling $6.9 million, inclusive of advances.properties.

Financing Cash Flows
Cash flows used in financing activities for the sixthree months ended June 30, 2011March 31, 2012 were $3.2 million, related to manager and shareholder distributions.

Cash flows provided byused in financing activities for the sixthree months ended June 30, 2010March 31, 2011 were $24 thousand,$1.2 million, related to capital contributions receivedmanager and shareholder distributions.

14


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 June 30, 2011,March 31, 2012, the Fund had committed to spend an additional $5.1$2.6 million related to its investment properties, of which $4.6$1.2 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.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, 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.
14


Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at June 30, 2011March 31, 2012 and December 31, 20102011 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 June 30, 2011March 31, 2012 and December 31, 20102011 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

See Note 3 of Notes to Unaudited Condensed Financial Statements – “Recent Accounting Standards” contained in this Quarterly Report for a discussion ofThe Fund has considered recent accounting pronouncements.pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

ITEM 3. 

Not required.

ITEM 4. 

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 March 31, 2012.

Table of ContentsJune 30, 2011.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended June 30, 2011March 31, 2012 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. 

None.

ITEM 1A. 

Not required.

ITEM 2. 

None.

ITEM 3. 

None.

ITEM 4.  (REMOVED AND RESERVED)

ITEM 5. OTHER INFORMATION
ITEM 4. 

None.

ITEM 5. 

None.


 
ITEM 6. 
 
EXHIBIT
NUMBER
TITLE OF EXHIBIT METHOD OF FILING
3.2Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy A-1 Fund, LLC dated April 13, 2011Incorporated by reference to the Fund’s Form 10Q filed on April 28, 2011
    
31.1Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) Filed herewith
    
31.2Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) Filed herewith
    
32Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund.Fund Filed herewith
    
101.INSXBRL Instance Document *
    
101.SCHXBRL Taxonomy Extension Schema *
    
101.CALXBRL Taxonomy Extension Calculation Linkbase *
    
101.LABXBRL Taxonomy Extension Label Linkbase *
    
101.PREXBRL 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 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.


 
SIGNATURES

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


    
RIDGEWOOD ENERGY A-1 FUND, LLC
Dated:July 26, 2011By:/s/ ROBERT E. SWANSON
Name:Robert E. Swanson
Title:Chief Executive Officer
      
Dated:   April 30, 2012By:       /s/ROBERT E. SWANSON
Name:Robert E. Swanson
Title:Chief Executive Officer
(Principal Executive Officer)
 
      
      
Dated:July 26, 2011   April 30, 2012By:/s/      /s/ KATHLEEN P. MCSHERRY
 
  Name: Kathleen P. McSherry
  Title: Executive Vice President and Chief Financial Officer
 
    (Principal Financial and Accounting Officer)
 

 
 17
18