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 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 ☒     No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Securities Exchange Act.Act of 1934.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act)Act of 1934).

The Ridgewood Energy A-1 Fund, LLC (the "Fund"“Fund”), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement"Agreement”) dated as of March 2, 2009 by and among Ridgewood Energy Corporation (the "Manager"“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.  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.information and the management of the Fund’s investments in projects.  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, 3 and 4.

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, 20152016 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K (“2016 Annual Report”) filed with the Securities and Exchange Commission (“SEC”).  The year-end condensed balance sheet data was derived from audited financial statements for the year ended December 31, 2015,2016, but does not include all annual 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, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates.

The fair value measurement guidance provides a hierarchy that prioritizesFund has provided discussion of significant accounting policies in Note 1 of “Notes to Financial Statements” – “Organization and defines the typesSummary of inputs usedSignificant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within its 2016 Annual Report. There have been no significant changes 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 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.  Mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.

The Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for the dismantling and removalfunding 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.asset retirement obligations. As of SeptemberJune 30, 20162017 and December 31, 2015,2016, 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. Mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.

The unrealized gains 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.  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.

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination ofthat a property to beis either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  As indicated above,At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary.  The following table presents changes in asset retirement obligations during the six months ended June 30, 2017 and 2016.

During the six months ended June 30, 2017, the Fund recorded credits to depletion expense totaling $0.1 million related to an adjustment to the asset retirement obligation for a fully depleted property. The Fund maintains a salvage fund to provide for the funding of asset retirement obligations.

The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset.  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 discounted cash flows from proved oil and natural gas reserves could change in the near term.

Significant declinesFluctuations in oil and natural gas prices since fourth quarter 2014 have impactedmay impact the fair value of the Fund’s oil and gas properties. If oil and natural gas prices continue to decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund.  For such services, the Manager is entitled to 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. In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments. Management fees during each of the three and ninesix months ended SeptemberJune 30, 20162017 and 20152016 were $0.1 million and $0.3$0.2 million, respectively.

The Manager is also entitled to receive a 15% interest in cash distributions from operations made by the Fund.  The Fund did not pay distributions during the three and ninesix months ended SeptemberJune 30, 20162017 and during the three months ended September 30, 2015. Distributions paid to the Manager during the nine months ended September 30, 2015 were $13 thousand.

In May 2015,2016, the Fund entered into a master agreement with Beta Sales &and Transport, LLC, (“Beta S&T”), a wholly-ownedwholly owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager (the “Ridgewood Beta Funds”) to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. On June 1,The Fund has provided discussion of this agreement in Note 2 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within its 2016 the Ridgewood Beta Funds entered into a master agreement (the “Agreement”) with Beta S&T in which Beta S&T will purchase from Ridgewood Beta Funds all of their interests in oil and gas produced at the Beta Project and sell such volumes to unrelated third party purchasers. Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the Agreement or under any other agreements it enters into with regards to the oil and gas acquired from the Ridgewood Beta Funds.   The Ridgewood Beta Funds indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against as a result of or arising from any act or omission, breach and claims for losses or damages arising out of Beta S&T’s dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Beta Project. The revenues from the sale of oil and gas to third party purchasers are recorded as oil and gas revenue in the statements of operations and expenses are recorded as operating expenses in the statements of operations.Annual Report.

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

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

In November 2012,As of June 30, 2017 and December 31, 2016, the Fund entered into ahad borrowings of $7.3 million under the credit agreement (as amended on September 30, 2016, 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 aggregateagreement. The 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. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. Certain other funds managed by Ridgewood (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Funds. The Manager serves as the manager for each of the Ridgewood Participating Funds.

As of September 30, 2016 and December 31, 2015, the Fund had borrowings of $4.0 million and $2.9 million, respectively, under the Credit Agreement. The unamortizedUnamortized debt discounts and deferred financing costs of $0.2$0.1 million as of SeptemberJune 30, 20162017 and December 31, 20152016 are presented as a reduction of “Long-term borrowings” on the balance sheets (see Note 1. “Organizationsheets.  Amortization expense during the three and Summarysix months ended June 30, 2017 of Significant Accounting Policies - Recent Accounting Pronouncements”).

As of June 30, 2017 and December 31, 2016, accrued interest costs of $0.4 million and $0.5 million, respectively, were accruedincluded on the balance sheetsheets within “Accrued expenses” as of September 30, 2016 and “Accrued expenses” and “Other liabilities” as of December 31, 2015.  As a result of the Beta Project’s commencement of production in third quarter 2016, interest. Interest costs incurred during the three and six months ended SeptemberJune 30, 20162017 of $0.1$0.2 million and $0.3 million, respectively, were expensed and are included on the statementstatements of operations within “Interest (expense) income, net”. Such amounts are accruedInterest costs incurred during each of the three and six months ended June 30, 2016 of $0.1 million were capitalized and included on the balance sheet within “Accrued expenses”“Oil and gas properties”. During the three and six months ended June 30, 2017, the Fund made payments on the loan of $0.2 million and $0.3 million, respectively, which related to capitalized interest costs.

 

   

As additional consideration to the Lenders,lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders.lenders. Such ORRI will not accrue or become payable to the lenders until after the loan is repaid in full. The Credit Agreementcredit agreement contains customary covenants, forwith which the Fund believes it was in compliance as of SeptemberJune 30, 20162017 and December 31, 2015.2016.

Based upon its current cash position and its current reserve estimates, and its current development plan of the Beta Project, the Fund expects cash flow from operations and borrowings to be sufficient to cover its commitments, borrowing repayments as well asand 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.  However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term commitments if needed.

The exploration for and developmentMany aspects of the oil and natural gas involves the extraction, productionindustry are subject to federal, state and transportation of materials which, under certain conditions, can be hazardous or causelocal environmental pollution problems.laws and regulations. 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.regulations. 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. As of SeptemberJune 30, 20162017 and December 31, 2015,2016, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

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 oilOil and gas industry both onshorelegislation and offshore.  If anyadministrative regulations are periodically changed for a variety of political, economic, and other reasons. Any such proposals were to be enactedfuture laws and regulations could result in increased compliance costs or adopted theyadditional operating restrictions, which could potentially materially impacthave a material adverse effect on the Fund’s operations.operating results and cash flows. 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

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effectmaterially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Fund’s operating resultsOuter Continental Shelf (“Lessees”).  Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and cash flows.additional security requirements of such Lessees,  (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance.  The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of its review of the new NTL. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured.  The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas.gas business. 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.  ClaimsDepending on the extent, nature and payment of claims made by the Fund or other funds managed by the Manager, can reduce or eliminateyearly insurance forcoverage may be exhausted and become insufficient to cover a claim by the Fund.Fund in a given year.

     

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 USU.S. 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 and other conditions affecting the pricing, production and productiondemand of oil and natural gas, the cost and availability of equipment, and changes in domestic and foreign 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 discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).  In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented.  The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows. See Note 1 of “Notes to Unaudited Condensed Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 1. “Financial Statements” within Part I of this Quarterly Report for a discussion of the Fund’s significant accounting policies. NoThere were no changes have been made to the Fund’s critical accounting policies and estimates from those disclosed in its 2015 Annual Report on Form 10-K.10-K for the year ended December 31, 2016.

The Fund is a Delaware limited liability company formed on February 3, 2009was organized primarily 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. Distributions to shareholders are made in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”). The Fund does not expect in the future to investigate or invest in any additional projects other than those in which it currently has a working interest. The Fund’s remaining capital has been fully allocated to complete such projects.

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 or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations.  As compensation for its services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund.  The 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.

Changes in commodity prices may significantly affect liquidity and expected operating results.  ReductionsDeclines in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable.  Significant declines in prices could result in non-cash charges to earnings due to impairment.

Since fourth quarter 2014, there has been a significant decline in oilOil and natural gas prices.  commodity prices have been subject to significant fluctuations during the past several years. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. Despite operating in a sustained lower commodity price environment, the Fund continued to advance the development of the Beta Project. During the second half of 2016, Beta Project well #1 and well #2 commenced production and during second quarter 2017, Beta Project well #3 commenced production. The Fund has suspended distributions and continues to conserve cash to complete the final phase of the Beta Project as budgeted.  See “Results“Results of Operations” under this Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for more information on the average oil and natural gas prices received by the Fund during the three and ninesix months ended SeptemberJune 30, 20162017 and 20152016 and the effect of such decreased average prices on the Fund’s results of operations.  If oil and natural gas commodity prices continue to decline, even if only for a short period of time, the Fund’s results of operations and liquidity will continue to be adversely impacted.

The following table summarizes the Fund’s results of operations during the three and ninesix months ended SeptemberJune 30, 20162017 and 2015,2016, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1.  “Financial Statements” in Part I of this Quarterly Report.

Overview.  The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the three and ninesix months ended SeptemberJune 30, 20162017 and 2015.2016.  Natural gas liquid (“NGL”) sales are included within gas sales.

The increases duringin the three months ended September 30, 2016above table were primarily related to the commencement of production of three wells in the Beta Project.  The decreasesProject, two wells during the nine months ended September 30,second half of 2016 were related toand one well during the second quarter 2017, coupled with the Liberty Project, which had been shut-in during the early part of 2016.  See additional discussion in “Business Update” section above.

Oil and Gas Revenue.   TheGenerally, the Fund generally sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. Both types of agreements may include transportation charges. One type of agreement isIn a netback agreement, under which the Fund sells oil and gas at the wellhead and receives a price, net of transportation expense incurred by the purchaser. In this case,purchaser, and the Fund records revenue at the net price received fromreceived. In the purchaser. The second type of agreement, is one whereby the Fund pays transportation expense directly. In that case,directly, and transportation expense is included within operating expenseexpenses in the statements of operations.

Oil and gas revenue during the three months ended SeptemberJune 30, 20162017 was $0.2$1.0 million, an increase of $0.1$0.9 million from the three months ended SeptemberJune 30, 2015.2016. The increase was primarily attributable to increased sales volume.volume totaling $0.9 million coupled with increased oil and gas prices totaling $0.1 million.

Oil and gas revenue during the ninesix months ended SeptemberJune 30, 20162017 was $0.4$1.9 million, a decreasean increase of $0.1$1.8 million from the ninesix months ended SeptemberJune 30, 2015.2016. The decreaseincrease was attributable to decreasedincreased sales volume totaling $0.1$1.5 million coupled with decreasedincreased oil and gas prices totaling $0.1$0.3 million.

See “Overview” above for factors that impact the oil and gas revenue volume and rate variances.

Depletion and Amortization.  Depletion and amortization during the three months ended SeptemberJune 30, 20162017 was $0.2$1.2 million, an increase of $0.1$1.2 million from the three months ended SeptemberJune 30, 2015.2016.  The increase was primarily attributable to an increase in the average depletion rate.rate totaling $0.9 million coupled with an increase in production volumes totaling $0.3 million.

Depletion and amortization during the ninesix months ended SeptemberJune 30, 20162017 was $0.2$2.2 million, a decreasean increase of $0.5$2.1 million from the ninesix months ended SeptemberJune 30, 2015.2016.  The decreaseincrease was primarily attributable to adjustments to asset retirement obligations related to fully depleted properties totaling $0.6 million, which were recorded in second quarter 2015, partially offset by an increase in the average depletion rate totaling $1.8 million coupled with an increase in production volumes totaling $0.5 million, partially offset by an adjustment to the asset retirement obligation related to a fully depleted property totaling $0.1 million.

The increases in the average depletion rates were primarily attributable to the onset of production of the Beta Project, which has higher cost of reserves.Project.  See “Overview” above for certain factors that impact the depletion and amortization volume and rate variances.  Depletion and amortization rates may also be impacted by changes in reserve estimates provided annually by the Fund’s independent petroleum engineers.

Management Fees to Affiliate.  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. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term capital commitments.

 

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

     

Lease operating expense, which includes transportation and processing expense, relates to the Fund’s producing properties. Insurance expense represents premiums related to the Fund’s properties, which vary depending upon the number of wells producing or drilling. Lease operatingAccretion expense relates to the Fund’s producing properties.  Accretion expense related to the asset retirement obligations established for the Fund’s proved properties. Workover expense represents costs to restore or stimulate production of existing reserves.

The average production cost, which includes lease operating expense, transportation and processing expense and insurance expense, was $12.69$5.76 per barrel of oil equivalent (“BOE”) and $12.75$6.39 per BOE during the three and ninesix months ended SeptemberJune 30, 2016,2017, respectively, compared to $16.32$9.09 per BOE and $16.85$12.97 per BOE during the three and ninesix months ended SeptemberJune 30, 2015,2016, respectively. The decreases were primarily attributable to the Liberty Project, which had higher cost per BOE in 2016 due to costs incurred by the Fundas a result of third-party facilities’ repair and maintenance activities during 2015 for wells that were no longer producing, partially offset by the impact of costs associated with the commencement of production forfirst quarter 2016.  In addition, the Beta Project during third quarter 2016.has lower cost per BOE as compared to other projects due to the processing of production through its standalone facility. The production costs per BOE may decline over time as throughput increases from the project or other projects expected to tie-in to the facility.

General and Administrative Expenses.  General and administrative expenses represent costs specifically identifiable or allocable to the Fund, such as accounting and professional fees and insurance expenses.

Interest (Expense) Income, Net.  Interest (expense) income, net is comprised of interest expense and amortization of debt discounts and deferred financing costs related to the Fund’s long-term borrowings (see “Liquidity Needs” below for additional information), and interest income earned on cash and cash equivalents and salvage fund.

Cash flows provided by operating activities during the six months ended June 30, 2017 were $1.3 million, related to revenue received of $1.9 million, partially offset by operating expenses of $0.3 million, management fees of $0.2 million, general and administrative expenses of $0.1 million, and the settlement of an asset retirement obligation of $0.1 million.

Cash flows used in operating activities during the ninesix months ended SeptemberJune 30, 2016 were $0.3$0.1 million, related to management fees of $0.3 million, operating expenses of $0.2 million and general and administrative expenses of $0.1 million, partially offset by revenue received of $0.2 million.

Cash flows used in investing activities during the ninesix months ended SeptemberJune 30, 20162017 were $1.5$1.7 million, primarily related to capital expenditures for oil and gas properties.properties of $1.8 million, partially offset by proceeds from salvage fund of $0.1 million.

Cash flows used in investing activities during the ninesix months ended SeptemberJune 30, 20152016 were $2.0$0.8 million, primarily related to capital expenditures for oil and gas properties.

CashThere were no cash flows provided byfrom financing activities during the ninesix months ended SeptemberJune 30, 2016 were $1.1 million, related to proceeds from long-term borrowings.

     

 

The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis.  See “Business Update” under this Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for information regarding the Fund’s current projects. See “Liquidity Needs” below for additional information.

Capital expenditures for oil 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 ofFund’s remaining capital has been fully allocated to complete its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which the Fund could invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.it currently has a working interest.

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

As of SeptemberJune 30, 2016,2017, the Fund’s estimated capital commitments related to its oil and gas properties were $5.6$3.1 million (which include asset retirement obligations for the Fund’s projects of $2.7$2.3 million), of which $3.4$0.6 million is expected to be spent during the next twelve months. These expected capital commitments exceed available working capital and salvage fund by $4.2 million asmonths primarily related to the completion of September 30, 2016. The Fund has entered into a credit agreement to provide capital forthe final phase of the Beta Project. See “Credit Agreement” belowAs a result of continued development of the Beta Project, the Fund has experienced negative cash flows for additional information.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments.

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 willmay be impacted in the future, by amounts reserved to provide for itstheir ongoing development costs, debt service costs, and funding itstheir estimated asset retirement obligations.

In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016, 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 to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of SeptemberJune 30, 20162017 and December 31, 2015,2016, the Fund had borrowed $4.0$7.3 million and $2.9 million, respectively, under the Credit Agreement. As of December 31, 2016, in accordance with the terms of the Credit Agreement, there are no additional borrowings available to the Fund.

As additional consideration to Unaudited Condensed Financial Statements” – “Credit Agreement –the lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project Financing” containedto the lenders.  The Fund’s share of the lender’s aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all the other participating funds managed by the Manager. Such ORRI will not accrue or become payable to the lenders until after the loan is repaid in Item 1. “Financial Statements” within Part I of this Quarterly Report for more information regarding the Credit Agreement.full.

The Fund had no off-balance sheet arrangements as of SeptemberJune 30, 20162017 and December 31, 20152016 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 as of SeptemberJune 30, 20162017 and December 31, 2015,2016, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs – Credit Agreement” above.

See Note 1 of “Notes to Unaudited Condensed Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 1. “Financial Statements” within Part I of this Quarterly Report for a discussion of recent accounting pronouncements.