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.

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.

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, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up.  The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Manager has direct and exclusive control over the management of the Fund’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 3, 4 and 5.

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, 20132014 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.

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.

The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Cash and cash equivalents approximate fair value based on Level 1 inputs. Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.

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 are $250 thousand per insured financial institution.  At September 30, 2014,March 31, 2015, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

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, 2014March 31, 2015 and December 31, 2013,2014, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale.  Available-for-sale securities are carried in the financial statements at fair value.

The unrealized gains and losses on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government.  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.

Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 4. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”. At September 30, 2014March 31, 2015 and December 31, 2013, $0.42014, $0.3 million and $0.5$0.4 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $31 thousand forduring each of the three months ended September 30, 2014March 31, 2015 and 2013. Amortization expense was $0.1 million for each of the nine months ended September 30, 2014 and 2013.2014. During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”.

The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”  Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory drilling costs are expensed as dry-hole costs.  At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.

Interest costs related to the Credit Agreement (see Note 4. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction.  Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity and workover efforts are expensed as incurred.

 

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

At September 30, 2014March 31, 2015 and December 31, 2013,2014, amounts recorded in due to operators totaling $0.9$0.5 million and $0.7$0.8 million, respectively, related to capital expenditures for oil and gas properties.

The Fund’s acquisition of a working interest in a well or a projectan oil and gas property requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund may be required to advance its share of 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.

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

Syndication costs 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.

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 proved 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 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, depreciation and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs.  In certain circumstances, equipment and facilities costs are depreciated over the estimated useful life of the asset.

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.

Profits and losses are allocated to shareholders and the Manager in accordance with the LLC agreement.Agreement.

Distributions to shareholders are allocated in proportion to the number of shares held.  The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.   During the ninethree months ended September 30,March 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $7.2 million.  There were no such distributions during the three months ended September 30, 2014 and during the three and nine months ended September 30, 2013.March 31, 2015.

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.

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

ThePursuant to the terms of the LLC Agreement, provides that the Manager renderrenders management, administrative and advisory services to the Fund.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for the three and nine months ended September 30,March 31, 2015 and 2014 were $0.2$0.1 million and $0.5 million, respectively.  Management fees for the three and nine months ended September 30, 2013 were $0.2 million and $0.7 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions from operations paid to the Manager for the three and nine months ended September 30,March 31, 2015 and 2014 were $0.1 million$13 thousand and $0.5 million, respectively.  Distributions from operations paid to the Manager for the three and nine months ended September 30, 2013 were $0.2 million and $1.0$0.4 million, respectively.  In addition, the Manager is entitled to receive a 1% interest in cash distributions from dispositions.  Distributions from the sale of the Raven project paid to the Manager during the ninethree months ended September 30,March 31, 2014 were $0.1 million.  There were no such distributions during the three months ended September 30, 2014 and during the three and nine months ended September 30, 2013.March 31, 2015.

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

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

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

In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.

The Fund anticipates it will borrow approximately $8.3 million over the development period of the Beta Project, which will bearLoan bears interest at 8% compounded annually and accrueaccrues only on Loan proceeds as they are drawn. Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected in 2016. At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund’s total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund’s total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020. The Loan may be prepaid by the Fund without premium or penalty.  As of September 30,March 31, 2015 and December 31, 2014, the Fund had borrowings of $0.8$2.9 million under the Credit Agreement.  As of December 31, 2013, the Fund had no borrowingsand $1.8 million, respectively, under the Credit Agreement.  During each of the three and nine months ended September 30, 2014,March 31, 2015, interest costs of $11$44 thousand were capitalized and included on the balance sheet within “Oil and gas properties”. The Fund had no interest costs during the three and nine months ended September 30, 2013.March 31, 2014.

As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interestsinterest in the Beta Project to the Lenders.  The Fund recorded the additional consideration as debt discounts and deferred financing costs at a fair value of $0.6 million, which is amortized to interest expense over the expected payoff period of the Loan.  The fair value of the ORRI was determined using net discounted cash flows from the Beta Project related to the ORRI based on Level 3 inputs, which include projected net income from reserves and forward pricing curves. 

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investmentoil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis.  Currently, the Fund has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently anticipates such development will include a four-well development with related platform and pipeline infrastructure.  It is also possible that full development of the Beta Project will entail the drilling of an additional well beyond the four projected wells, the cost of which is not included in the below estimates.

As of September 30, 2014,March 31, 2015, the Fund’s estimated capital commitments related to its investments in oil and gas properties were $11.9$11.2 million of which $2.4 million is expected to be spent during the next twelve months.  These expected capital commitments, which(which include asset retirement obligations for the Fund’s projects of $2.5 million and projected interest costs of $2.1$2.0 million for the Beta Project,Project), of which $6.1 million is expected to be spent during the next twelve months. These expected capital commitments exceed available working capital and salvage fund by $5.9$4.6 million at September 30, 2014.  In November 2012, theMarch 31, 2015.  The Fund has entered into a credit agreement that provides for an aggregate loan commitment of up to $8.3 million, of which the Fund has borrowed $0.8 million at September 30, 2014, to provide capital toward the funding of the Fund’s share of development costs onfor the Beta Project.  Principal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2020.  See Note 4. “Credit Agreement”Agreement – Beta Project Financing” for additional information.  The

Based upon its current cash position and its current reserve estimates, the Fund expects that cash flowsflow from operations willand borrowings to be sufficient to fundcover its remaining commitments.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.

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, 2014March 31, 2015 and December 31, 2013,2014, there were no known environmental contingencies that required the Fund to record a liability.

During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.offshore.  If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations.  It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s business. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

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

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 and production 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 projects, investments, insurance, capital expenditures and liquidity.  Forward-looking statements made in this document speak only as of the date on which they are made.  The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

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.  The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects.  However, the Fund is not required to make distributions to shareholders except as provided in the Fund’s limited liability company agreement (the “LLC 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 projects, including ongoing management, administrative and advisory services.  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.  Factors affecting market pricing for oil and natural gas include:

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  The average production cost was $17.65$23.42 per barrel of oil equivalent (“BOE”) and $11.82during the three months ended March 31, 2015 compared to $7.44 per BOE during the three and nine months ended September 30, 2014, respectively, comparedMarch 31, 2014.   The increase is attributable to $5.97 per BOE and $5.55 per BOE during the three and nine months ended September 30, 2013, respectively.impact of ongoing costs for wells that are no longer producing, including the Alpha Project.  Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.  Geological costs which were related to the Beta Project, represent costs incurred to obtain seismic data, surveys, and lease rentals.

Cash flows provided byused in operating activities for the ninethree months ended September 30, 2014March 31, 2015 were $1.8 million, primarily$42 thousand, related to revenue received of $3.3 million, partially offset by operating expenses paid of $0.8$0.2 million, management fees of $0.5 million, workover expense paid of $0.2$0.1 million and general and administrative expenses paid of $0.1$33 thousand, partially offset by revenue received of $0.2 million.

Cash flows provided by operating activities for the ninethree months ended September 30, 2013March 31, 2014 were $8.1$1.6 million, primarily related to revenue received of $10.6$2.1 million, which includes $0.6 million that was remitted to the buyer of the Raven Project upon final settlement.  Revenue received was partially offset by operating expenses paid of $1.6$0.3 million and management fees of $0.7 million, and general and administrative expenses paid of $0.3$0.2 million.

Cash flows used in investing activities for the three months ended March 31, 2015 were $0.6 million, related to capital expenditures for oil and gas properties.

Cash flows provided by investing activities for the ninethree months ended September 30,March 31, 2014 were $7.9$10.2 million, primarily related to proceeds from the sale of the Raven Project of $11.0$10.8 million, partially offset by capital expenditures for oil and gas properties of $3.1$0.6 million.

Cash flows used inprovided by financing activities for the ninethree months ended September 30, 2014March 31, 2015 were $9.3$1.0 million, related to manager and shareholder distributions of $10.1 million, of which $7.2 million was related to the distribution of the proceeds from the sale of the Raven Project, partially offset by proceeds from long-term borrowings of $0.8$1.1 million, partially offset by manager and shareholder distributions totaling $0.1 million.

Cash flows used in financing activities for the ninethree months ended September 30, 2013March 31, 2014 were $6.7$9.1 million, related to manager and shareholder distributions.distributions, of which $7.2 million was related to the distribution of proceeds from the sale of the Raven Project.

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investmentoil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of September 30, 2014,March 31, 2015, the Fund hashad one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $10.9$10.1 million related to the development of this project, which the Fund anticipates will include a four-well development with related platform and pipeline infrastructure.  It is also possible that full development of the Beta Project will entail the drilling of an additional well beyond the four projected wells, the cost of which is not included in the above estimates. See “Liquidity Needs” below for additional information.

Capital expenditures for investmentoil and gas properties have been funded with the capital raised by the Fund in its private placement offering, and in certain circumstances, through debt financing. The number of projects in which the Fund cancould invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.

The Fund’s primary short-term liquidity needs are to fund its operations and capital expenditures for its investmentoil and gas properties. Such needs are funded utilizing operating income, existing cash on-hand and income earned therefrom.borrowings.

As of September 30, 2014,March 31, 2015, the Fund’s estimated capital commitments related to its investments in oil and gas properties were $11.9$11.2 million of which $2.4 million is expected to be spent during the next twelve months.  These expected capital commitments, which(which include asset retirement obligations for the Fund’s projects of $2.5 million and projected interest costs of $2.1$2.0 million for the Beta Project,Project), of which $6.1 million is expected to be spent during the next twelve months. These expected capital commitments exceed available working capital and salvage fund by $5.9$4.6 million at September 30, 2014.  In November 2012, theMarch 31, 2015. The Fund has entered into a credit agreement that provides for an aggregate loan commitment of up to $8.3 million, of which the Fund has borrowed $0.8 million at September 30, 2014, to provide capital toward the funding of the Fund’s share of development costs onfor the Beta Project.  Principal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2020.  See “Credit Agreement” below for additional information.  The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

 

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, 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. Due to the significant capital required to develop the Beta Project, distributions have been impacted, and maywill be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations.

In November 2012, theThe Fund has entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as administrative agent and lender (and any other banks or financial institutions that may in the future become a party thereto) that provides for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of September 30,March 31, 2015 and December 31, 2014, the Fund had borrowed $0.8$2.9 million and $1.8 million, respectively, under the Credit Agreement.  AsPrincipal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2013, the Fund had no borrowings under the Credit Agreement.2020.  See Note 4 of “Notes to Unaudited Condensed Financial Statements” – “Credit Agreement – Beta Project Financing” in Part I of this Quarterly Report for more information regarding the Credit Agreement.

The Fund had no off-balance sheet arrangements at September 30, 2014March 31, 2015 and December 31, 20132014 and does not anticipate the use of such arrangements in the future.

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, 2014March 31, 2015 and December 31, 2013,2014, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs” – Credit Agreement above.

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.

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, 2014.March 31, 2015.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended September 30, 2014March 31, 2015 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.

None.

Not required.

None.

None.

None.

None.

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