10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

             For the quarterly period ended September 30, 2014

or

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________________to____________________________

Commission File No. 000-53895

Ridgewood Energy A-1 Fund, LLC

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of 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 filer	o	Accelerated filer	o
Non-accelerated filer (Do not check if a smaller reporting company)	o	Smaller reporting company	x

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

 Yes o     No x

As of October 21, 2014 the Fund had 207.7026 shares of LLC Membership Interest outstanding.

Table of Contents

			PAGE
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements		1
		Unaudited Condensed Balance Sheets as of September 30, 2014 and December 31, 2013	1
		Unaudited Condensed Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2014 and 2013	2
		Unaudited Condensed Statements of Cash Flows for the nine months ended September 30, 2014 and 2013	3
		Notes to Unaudited Condensed Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		15
Item 4.	Controls and Procedures		15
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		16
Item 1A.	Risk Factors		16
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		16
Item 3.	Defaults Upon Senior Securities		16
Item 4.	Mine Safety Disclosures		16
Item 5.	Other Information		16
Item 6.	Exhibits		16
	SIGNATURES		17

PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

RIDGEWOOD ENERGY A-1 FUND, LLC

UNAUDITED CONDENSED BALANCE SHEETS

(in thousands, except share data)

	September 30, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	5,081		$	4,690
Production receivable		242			962
Asset held for sale		-			1,266
Other current assets		32			72
Total current assets		5,355			6,990
Salvage fund		1,775			1,763
Other assets		397			488
Oil and gas properties:
Advances to operators for working interests and expenditures		-			68
Proved properties		16,899			15,735
Equipment and facilities - in progress		4,112			1,842
Less:  accumulated depletion, depreciation and amortization		(12,451	)		(11,547	)
Total oil and gas properties, net		8,560			6,098
Total assets	$	16,087		$	15,339
Liabilities and Members' Capital
Current liabilities:
Due to operators	$	1,141		$	1,241
Accrued expenses		32			39
Liability held for sale		-			684
Total current liabilities		1,173			1,964
Asset retirement obligations		946			946
Long-term borrowings		800			-
Other liabilities		11			-
Total liabilities		2,930			2,910
Commitments and contingencies (Note 5)
Members' capital:
Manager:
Distributions		(4,982	)		(4,480	)
Retained earnings		5,142			4,844
Manager's total		160			364
Shareholders:
Capital contributions (250 shares authorized;
207.7026 issued and outstanding)		41,143			41,143
Syndication costs		(4,804	)		(4,804	)
Distributions		(34,996	)		(25,389	)
Retained earnings		11,652			1,118
Shareholders' total		12,995			12,068
Accumulated other comprehensive income (loss)		2			(3	)
Total members' capital		13,157			12,429
Total liabilities and members' capital	$	16,087		$	15,339

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

(in thousands, except per share data)

	Three months ended September 30,					Nine months ended September 30,
	2014			2013		2014		2013
Revenue
Oil and gas revenue	$	793		$	2,591	$	2,593	$	9,682
Expenses
Depletion, depreciation and amortization		261			726		904		2,494
Management fees to affiliate (Note 3)		157			232		474		697
Operating expenses		221			514		486		1,640
Workover expense		14			55		161		116
General and administrative expenses		30			60		145		199
Total expenses		683			1,587		2,170		5,146
(Loss) gain on sale of oil and gas properties		(12	)		-		10,396		-
Income from operations		98			1,004		10,819		4,536
Interest income		5			3		13		12
Net income		103			1,007		10,832		4,548
Other comprehensive income (loss)
Unrealized gain (loss) on marketable securities		1			6		5		(11	)
Total comprehensive income	$	104		$	1,013	$	10,837	$	4,537
Manager Interest
Net income	$	57		$	253	$	298	$	1,032
Shareholder Interest
Net income	$	46		$	754	$	10,534	$	3,516
Net income per share	$	220		$	3,629	$	50,716	$	16,929

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)

	Nine months ended September 30,
	2014			2013
Cash flows from operating activities
Net income	$	10,832		$	4,548
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization		904			2,494
Gain on sale of oil and gas properties		(10,396	)		-
Changes in assets and liabilities:
Decrease in production receivable		720			953
Decrease (increase) in other current assets		40			(56	)
(Decrease) increase in due to operators		(282	)		139
Decrease in accrued expenses		(7	)		(3	)
Net cash provided by operating activities		1,811			8,075
Cash flows from investing activities
Payments to operators for working interests and expenditures		-			(95	)
Proceeds from sale of oil and gas properties		10,978			-
Capital expenditures for oil and gas properties		(3,082	)		(810	)
Interest reinvested in salvage fund		(7	)		(11	)
Net cash provided by (used in) investing activities		7,889			(916	)
Cash flows from financing activities
Long-term borrowings		800			-
Distributions		(10,109	)		(6,651	)
Net cash used in financing activities		(9,309	)		(6,651	)
Net increase in cash and cash equivalents		391			508
Cash and cash equivalents, beginning of period		4,690			5,045
Cash and cash equivalents, end of period	$	5,081		$	5,553
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$	68		$	-

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 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, 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’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.

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, 2013 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.

Fair Value Measurements

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.

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

4

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations.  At September 30, 2014 and December 31, 2013, 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.

			Gross
	Amortized		Unrealized			Fair
	Cost		Gains (Losses)			Value
	(in thousands)
Government National Mortgage Association securities (GNMA July 2041)
September 30, 2014	$	84	$	3		$	87
December 31, 2013	$	90	$	1		$	91
Federal National Mortgage Association security (FNMA January 2042)
September 30, 2014	$	143	$	(1	)	$	142
December 31, 2013	$	198	$	(4	)	$	194

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

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, 2014 and December 31, 2013, $0.4 million and $0.5 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $31 thousand for each of the three months ended September 30, 2014 and 2013. Amortization expense was $0.1 million for each of the nine months ended September 30, 2014 and 2013. 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”.

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.  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.

5

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, 2014 and December 31, 2013, amounts recorded in due to operators totaling $0.9 million and $0.7 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest.  The Fund may be required to advance its share of estimated cash expenditures for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures.  As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

Asset Retirement Obligations

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

Syndication Costs

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

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability 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 estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.

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 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.

6

Depletion, Depreciation and Amortization

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.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.

Income and Expense Allocation

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

Distributions

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

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.   During the nine months ended September 30, 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.

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

2.           Oil and Gas Properties

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’ interests 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.

The Fund had a 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 million, which was recognized during the nine months ended September 30, 2014.  There was no such amount recorded during the three and nine months ended September 30, 2013.

At December 31, 2013, the Fund’s balance sheet reflected the Raven Project’s cost and accumulated depletion classified as “Asset held for sale”, which totaled $1.3 million, and the Raven Project’s asset retirement obligation classified as “Liability held for sale”, which totaled $0.7 million.   Such asset was monetized and obligation was relieved upon the closing of the Raven Project’s sale.

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 adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.

Workover expense represents costs to restore or stimulate production of existing reserves. During the three and nine months ended September 30, 2014, the Fund recorded workover expense of $14 thousand and $0.2 million, respectively, related to the Carrera Project.  Workover expense of $0.1 million during each of the three and nine months ended September 30, 2013 related primarily to the Carrera, Alpha and Liberty projects.

7

3.           Related Parties

The LLC Agreement provides that the Manager render 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, 2014 were $0.2 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, 2014 were $0.1 million 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 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 nine months ended September 30, 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.

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.

4.           Credit Agreement – Beta Project Financing

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 bear interest at 8% compounded annually and accrue 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, 2014, the Fund had borrowings of $0.8 million under the Credit Agreement.  As of December 31, 2013, the Fund had no borrowings under the Credit Agreement.  During each of the three and nine months ended September 30, 2014, interest costs of $11 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.

As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interests 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 Credit Agreement contains customary covenants, for which the Fund believes it is in compliance at September 30, 2014 and December 31, 2013.

8

5.           Commitments and Contingencies

Capital Commitments

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 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, the Fund’s estimated capital commitments related to its investments in oil and gas properties were $11.9 million, of which $2.4 million is expected to be spent during the next twelve months.  These expected capital commitments, which include asset retirement obligations for the Fund’s projects of $2.5 million and projected interest costs of $2.1 million for the Beta Project, exceed available working capital and salvage fund by $5.9 million at September 30, 2014.  In November 2012, the Fund 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 on 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” – Beta Project Financing” for additional information.  The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

Environmental Considerations

The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems.  The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry.  However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims.  At September 30, 2014 and December 31, 2013, 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.  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.

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 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.

9

ITEM 2.                MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

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

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 2013 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.  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.

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.  The budget for each project is inclusive of estimated asset retirement obligations.

		Total Spent		Total
	Working	through		Fund
Project	Interest	September 30, 2014		Budget		Status
		(in thousands)
Non-producing Properties
Beta Project	2.0%	$	7,621	$	18,475	Well deemed to be a discovery in 2012. Completion efforts are ongoing and production is expected to commence in 2016.
Producing Properties
Alpha Project	3.75%	$	6,606	$	7,094	Production commenced in 2012.
Carrera Project	2.0%	$	3,250	$	3,510	Production commenced in 2011. Well is currently producing, however, was shut-in periodically during 2014 due to maintenance activities.
Liberty Project	2.0%	$	3,008	$	3,288	Production commenced in 2010. Well is currently producing, however, was shut-in periodically during 2014 due to maintenance activities. Recompletion is planned for 2015.
Sold Properties
Raven Project well #1 & #2	25.0%	$	11,452	$	11,452	In January 2014, the Fund sold its interest in the Raven Project. See "Raven Sale" below for additional information.

Raven Sale

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’ interests 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.

The Fund had a 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 million, which was recognized during the nine months ended September 30, 2014.  There was no such amount recorded during the three and nine months ended September 30, 2013.

Results of Operations

The following table summarizes the Fund’s results of operations for the three and nine months ended September 30, 2014 and 2013, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1.  “Financial Statements” in Part I in this Quarterly Report.

11

	Three months ended September 30,					Nine months ended September 30,
	2014			2013		2014		2013
	(in thousands)
Revenue
Oil and gas revenue	$	793		$	2,591	$	2,593	$	9,682
Expenses
Depletion, depreciation  and amortization		261			726		904		2,494
Management fees to affiliate		157			232		474		697
Operating expenses		221			514		486		1,640
Workover expense		14			55		161		116
General and administrative expenses		30			60		145		199
Total expenses		683			1,587		2,170		5,146
(Loss) gain on sale of oil and gas properties		(12	)		-		10,396		-
Income from operations		98			1,004		10,819		4,536
Interest income		5			3		13		12
Net income		103			1,007		10,832		4,548
Other comprehensive income (loss)
Unrealized gain (loss) on marketable securities		1			6		5		(11	)
Total comprehensive income	$	104		$	1,013	$	10,837	$	4,537

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the three and nine months ended September 30, 2014 and 2013.

	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Number of wells producing		3		4		3		5
Total number of production days		219		331		626		1,069
Oil sales (in thousands of barrels)		7		9		19		34
Average oil price per barrel	$	96	$	109	$	99	$	109
Gas sales (in thousands of mcfs)		26		458		117		1,550
Average gas price per mcf	$	4.87	$	3.64	$	5.12	$	3.94

The decreases in the number of wells producing, production days and sales volume were primarily attributable to the Raven Project, which was sold in January 2014, the Carrera Project, which was shut-in periodically during 2014, and natural declines in well production. See additional discussion in “Business Update” section above.

Oil and Gas Revenue.   Oil and gas revenue for the three months ended September 30, 2014 was $0.8 million, a $1.8 million decrease from the three months ended September 30, 2013.  The decrease was attributable to decreased sales volume totaling $1.8 million, of which $1.7 million related to the sale of the Raven Project.  Oil and gas revenue for the nine months ended September 30, 2014 was $2.6 million, a $7.1 million decrease from the nine months ended September 30, 2013.  The decrease was attributable to decreased sales volume totaling $7.2 million, of which $6.1 million related to the sale of the Raven Project.  See “Overview” above for additional information.

Depletion, Depreciation and Amortization.  Depletion, depreciation and amortization for the three months ended September 30, 2014 was $0.3 million, a decrease of $0.5 million from the three months ended September 30, 2013.  The decrease resulted from a decrease in production volume totaling $0.6 million, partially offset by an increase in average depletion rates totaling $0.2 million.  Depletion, depreciation and amortization for the nine months ended September 30, 2014 was $0.9 million, a decrease of $1.6 million from the nine months ended September 30, 2013.  The decrease resulted from a decrease in production volume totaling $2.2 million, partially offset by an increase in average depletion rates totaling $0.6 million. The increases in average depletion rates were primarily attributable to decreases in reserve estimates, primarily related to the Alpha Project, coupled with the impact of the sale of the Raven Project, which had lower cost reserves.  See “Overview” above for additional information.

12

Management Fees to Affiliate. Management fees for each of the three months ended September 30, 2014 and 2013 were $0.2 million.  Management fees for the nine months ended September 30, 2014 and 2013 were $0.5 million and $0.7 million, respectively.  An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.

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

	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
	(in thousands)
Lease operating expense	$	195	$	508	$	457	$	1,623
Dry-hole costs		21		-		17		-
Geological costs		5		6		12		17
	$	221	$	514	$	486	$	1,640

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 per barrel of oil equivalent (“BOE”) and $11.82 per BOE during the three and nine months ended September 30, 2014, respectively, compared to $5.97 per BOE and $5.55 per BOE during the three and nine months ended September 30, 2013, respectively.  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.

Workover Expense.  Workover expense represents costs to restore or stimulate production of existing reserves. During the three and nine months ended September 30, 2014, the Fund recorded workover expense of $14 thousand and $0.2 million, respectively, related to the Carrera Project.  Workover expense of $0.1 million during each of the three and nine months ended September 30, 2013 related primarily to the Carrera, Alpha and Liberty projects.

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

	Three months ended September 30,					Nine months ended September 30,
	2014			2013		2014		2013
	(in thousands)
Accounting and professional fees	$	32		$	28	$	92	$	113
Insurance expense		(3	)		31		50		82
Other		1			1		3		4
	$	30		$	60	$	145	$	199

Accounting and professional fees represent expenses for audits, quarterly reviews, tax preparation, reserve data engineering and reporting, and administration of filings. Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance.

(Loss) Gain on Sale of Oil and Gas Properties.  During the three months ended September 30, 2014, the Fund recorded a loss on sale of oil gas properties, which resulted from post-closing adjustments to the Raven Project sale price.  During the nine months ended September 30, 2014, the Fund recorded a gain on sale of oil and gas properties of $10.4 million related to the Raven Project.  See “Business Update” for additional information regarding the sale.  There were no such amounts recorded during the three and nine months ended September 30, 2013.

Interest Income.  Interest income is comprised of interest earned on cash and cash equivalents, salvage fund and available-for-sale investments.

Unrealized Gain (Loss) on Marketable Securities.  At September 30, 2014, the Fund had available-for-sale investments within its salvage fund in federal agency mortgage-backed securities totaling $0.2 million, which mature between 2041 and 2042.  Available-for-sale securities are carried in the financial statements at fair value and unrealized gains and losses related to the securities’ changes in fair value are recorded in other comprehensive income until realized.   The Fund recognized an unrealized gain of $1 thousand and $6 thousand during the three months ended September 30, 2014 and 2013, respectively.  The Fund recognized an unrealized gain of $5 thousand and an unrealized loss of $11 thousand during the nine months ended September 30, 2014 and 2013, respectively.

13

Capital Resources and Liquidity

Operating Cash Flows

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

Cash flows provided by operating activities for the nine months ended September 30, 2013 were $8.1 million, primarily related to revenue received of $10.6 million, partially offset by operating expenses paid of $1.6 million, management fees of $0.7 million, and general and administrative expenses paid of $0.3 million.

Investing Cash Flows

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

Cash flows used in investing activities for the nine months ended September 30, 2013 were $0.9 million, primarily related to capital expenditures for oil and gas properties, inclusive of advances.

Financing Cash Flows

Cash flows used in financing activities for the nine months ended September 30, 2014 were $9.3 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 million.

Cash flows used in financing activities for the nine months ended September 30, 2013 were $6.7 million, related to manager and shareholder distributions.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of September 30, 2014, 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 expects to spend an additional $10.9 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 investment 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 can invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.

Liquidity Needs

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

As of September 30, 2014, the Fund’s estimated capital commitments related to its investments in oil and gas properties were $11.9 million, of which $2.4 million is expected to be spent during the next twelve months.  These expected capital commitments, which include asset retirement obligations for the Fund’s projects of $2.5 million and projected interest costs of $2.1 million for the Beta Project, exceed available working capital and salvage fund by $5.9 million at September 30, 2014.  In November 2012, the Fund 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 on 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.

14

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 may 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.

Credit Agreement

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) 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, 2014, the Fund had borrowed $0.8 million under the Credit Agreement.  As of December 31, 2013, the Fund had no borrowings under the Credit Agreement.   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.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at September 30, 2014 and December 31, 2013 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators.  On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities.  The Fund does not negotiate such contracts.  No contractual obligations exist at September 30, 2014 and December 31, 2013, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs” – Credit Agreement above.

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.

ITEM 3.                QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4.                CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Fund’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Fund’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of September 30, 2014.

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

15

PART II – OTHER INFORMATION

ITEM 1.                LEGAL PROCEEDINGS

None.

ITEM 1A.             RISK FACTORS

Not required.

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

None.

ITEM 3.                DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.                MINE SAFETY DISCLOSURES

None.

ITEM 5.                OTHER INFORMATION

None.

ITEM 6.                EXHIBITS

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	Filed herewith
31.2	Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	Filed herewith
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund	Filed herewith
101.INS	XBRL Instance Document	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Filed herewith
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.LAB	XBRL Taxonomy Extension Label Linkbase	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Filed herewith

16

SIGNATURES

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.

				RIDGEWOOD ENERGY A-1 FUND, LLC
Dated:	October 21, 2014	By:	/s/	ROBERT E. SWANSON
			Name:	Robert E. Swanson
			Title:	Chief Executive Officer
				(Principal Executive Officer)
Dated:	October 21, 2014	By:	/s/	KATHLEEN P. MCSHERRY
			Name:	Kathleen P. McSherry
			Title:	Executive Vice President and Chief Financial Officer
				(Principal Financial and Accounting Officer)

17

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Robert E. Swanson, certify that:

1.        I have reviewed this Quarterly Report on Form 10-Q of Ridgewood Energy A-1 Fund, LLC;

2.        Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.        Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.        The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e) and 15d – 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.        The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	October 21, 2014
/s/	ROBERT E. SWANSON
Name:	Robert E. Swanson
Title:	Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Kathleen P. McSherry, certify that:

1.       I have reviewed this Quarterly Report on Form 10-Q of Ridgewood Energy A-1 Fund, LLC;

2.       Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.       Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.       The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e) and 15d – 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.       The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated:	October 21, 2014
/s/	KATHLEEN P. MCSHERRY
Name:	Kathleen P. McSherry
Title:	Executive Vice President and Chief Financial Officer
	(Principal Financial and Accounting Officer)

EX-32

EXHIBIT 32

CERTIFICATIONS PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Quarterly Report on Form 10-Q of the Ridgewood Energy A-1 Fund, LLC (the “Fund”) for the period ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof, (the “Report”), each of the undersigned officers of the Fund hereby certifies, pursuant to 18 U.S.C. (section) 1350, as adopted pursuant to (section) 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Fund.

Dated:	October 21, 2014
		/s/	ROBERT E. SWANSON
		Name:	Robert E. Swanson
		Title:	Chief Executive Officer
			(Principal Executive Officer)
Dated:	October 21, 2014
		/s/	KATHLEEN P. MCSHERRY
		Name:	Kathleen P. McSherry
		Title:	Executive Vice President and Chief Financial Officer
			(Principal Financial and Accounting Officer)

A signed original of this written statement or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to the Fund and will be retained by the Fund and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this report or as a separate disclosure document.

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Credit Agreement - Beta Project Financing

9 Months Ended

Sep. 30, 2014

Credit Agreement - Beta Project Financing [Abstract]

Credit Agreement - Beta Project Financing

4.           Credit Agreement – Beta Project Financing

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 bear interest at 8% compounded annually and accrue 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, 2014, the Fund had borrowings of $0.8 million under the Credit Agreement.  As of December 31, 2013, the Fund had no borrowings under the Credit Agreement.  During each of the three and nine months ended September 30, 2014, interest costs of $11 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.

As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interests 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 Credit Agreement contains customary covenants, for which the Fund believes it is in compliance at September 30, 2014 and December 31, 2013.

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Related Parties

9 Months Ended

Sep. 30, 2014

Related Parties [Abstract]

Related Parties

3.           Related Parties

The LLC Agreement provides that the Manager render 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, 2014 were $0.2 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, 2014 were $0.1 million 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 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 nine months ended September 30, 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.

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.

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UNAUDITED CONDENSED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 5,081	$ 4,690
Production receivable	242	962
Asset held for sale		1,266
Other current assets	32	72
Total current assets	5,355	6,990
Salvage fund	1,775	1,763
Other assets	397	488
Oil and gas properties:
Advances to operators for working interests and expenditures		68
Proved properties	16,899	15,735
Equipment and facilities - in progress	4,112	1,842
Less: accumulated depletion, depreciation and amortization	(12,451)	(11,547)
Total oil and gas properties, net	8,560	6,098
Total assets	16,087	15,339
Current liabilities:
Due to operators	1,141	1,241
Accrued expenses	32	39
Liability held for sale		684
Total current liabilities	1,173	1,964
Asset retirement obligations	946	946
Long-term borrowings	800
Other liabilities	11
Total liabilities	2,930	2,910
Commitments and contingencies (Note 5)
Members' capital:
Distributions	(4,982)	(4,480)
Retained earnings	5,142	4,844
Manager's total	160	364
Capital contributions (250 shares authorized; 207.7026 issued and outstanding)	41,143	41,143
Syndication costs	(4,804)	(4,804)
Distributions	(34,996)	(25,389)
Retained earnings	11,652	1,118
Shareholders' total	12,995	12,068
Accumulated other comprehensive income (loss)	2	(3)
Total members' capital	13,157	12,429
Total liabilities and members' capital	$ 16,087	$ 15,339

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Organization and Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2014

Organization and Summary of Significant Accounting Policies [Abstract]

Organization and Summary of Significant Accounting Policies

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, 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'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.

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, 2013 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.

Fair Value Measurements

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.

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

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations.  At September 30, 2014 and December 31, 2013, 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.

			Gross
	Amortized		Unrealized			Fair
	Cost		Gains (Losses)			Value
	(in thousands)
Government National Mortgage Association securities (GNMA July 2041)
September 30, 2014	$	84	$	3		$	87
December 31, 2013	$	90	$	1		$	91
Federal National Mortgage Association security (FNMA January 2042)
September 30, 2014	$	143	$	(1	)	$	142
December 31, 2013	$	198	$	(4	)	$	194

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

Debt discounts and deferred financing costs include lender fees and other costs of the Credit Agreement (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, 2014 and December 31, 2013, $0.4 million and $0.5 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $31 thousand for each of the three months ended September 30, 2014 and 2013. Amortization expense was $0.1 million for each of the nine months ended September 30, 2014 and 2013. 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”.

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.  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.

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, 2014 and December 31, 2013, amounts recorded in due to operators totaling $0.9 million and $0.7 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

The Fund's acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund's rights, title and interest.  The Fund may be required to advance its share of estimated cash expenditures for the succeeding month's operation. The Fund accounts for such payments as advances to operators for working interests and expenditures.  As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

Asset Retirement Obligations

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

Syndication Costs

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

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability 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 estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.

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 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

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.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund's income or loss is passed through and included in the tax returns of the Fund's shareholders.

Income and Expense Allocation

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

Distributions

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

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.   During the nine months ended September 30, 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.

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.

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Oil and Gas Properties

9 Months Ended

Sep. 30, 2014

Oil and Gas Properties [Abstract]

Oil and Gas Properties

2.           Oil and Gas Properties

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' interests 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.

The Fund had a 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 million, which was recognized during the nine months ended September 30, 2014.  There was no such amount recorded during the three and nine months ended September 30, 2013.

At December 31, 2013, the Fund's balance sheet reflected the Raven Project's cost and accumulated depletion classified as “Asset held for sale”, which totaled $1.3 million, and the Raven Project's asset retirement obligation classified as “Liability held for sale”, which totaled $0.7 million.   Such asset was monetized and obligation was relieved upon the closing of the Raven Project's sale.

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 adjustments to certain wells from their respective operators upon review and audit of the wells' costs.

Workover expense represents costs to restore or stimulate production of existing reserves. During the three and nine months ended September 30, 2014, the Fund recorded workover expense of $14 thousand and $0.2 million, respectively, related to the Carrera Project.  Workover expense of $0.1 million during each of the three and nine months ended September 30, 2013 related primarily to the Carrera, Alpha and Liberty projects.

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UNAUDITED CONDENSED BALANCE SHEETS (Parenthetical)	Sep. 30, 2014	Dec. 31, 2013
UNAUDITED CONDENSED BALANCE SHEETS [Abstract]
Shares authorized	250	250
Shares issued	207.7026	207.7026
Shares outstanding	207.7026	207.7026

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Commitments and Contingencies (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Commitments and Contingencies [Abstract]
Commitments for the drilling and development of investment properties	$ 11,900,000
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months	2,400,000
Commitments for asset retirement obligations included in estimated capital commitments	2,500,000
Commitments for projected interest costs included in estimated capital commitments	2,100,000
Commitments for the drilling and development of investment properties in excess of working capital	5,900,000
Credit agreement, maximum borrowing capacity	8,300,000
Long-term borrowings	$ 800,000

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 21, 2014
Document And Entity Information Abstract
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014
Entity Registrant Name	RIDGEWOOD ENERGY A-1 FUND LLC
Entity Central Index Key	0001457919
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		207.7026

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UNAUDITED CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenue
Oil and gas revenue	$ 793	$ 2,591	$ 2,593	$ 9,682
Expenses
Depletion, depreciation and amortization	261	726	904	2,494
Management fees to affiliate (Note 3)	157	232	474	697
Operating expenses	221	514	486	1,640
Workover expense	14	55	161	116
General and administrative expenses	30	60	145	199
Total expenses	683	1,587	2,170	5,146
(Loss) gain on sale of oil and gas properties	(12)		10,396
Income from operations	98	1,004	10,819	4,536
Interest income	5	3	13	12
Net income	103	1,007	10,832	4,548
Other comprehensive income (loss)
Unrealized gain (loss) on marketable securities	1	6	5	(11)
Total comprehensive income	104	1,013	10,837	4,537
Manager Interest
Net income	57	253	298	1,032
Shareholder Interest
Net income	$ 46	$ 754	$ 10,534	$ 3,516
Net income per share	$ 220	$ 3,629	$ 50,716	$ 16,929

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Organization and Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Organization and Summary of Significant Accounting Policies [Abstract]
Maximum cash balance federally insured per financial institution	$ 250,000		$ 250,000
Unamortized debt discounts and deferred financing costs	400,000		400,000		500,000
Amortization of financing costs	31,000	31,000	100,000	100,000
Value of capital expenditures for oil and gas properties owed to operators	900,000		900,000		700,000
Percentage of cash from operations allocated to shareholders	85.00%		85.00%
Percentage of cash from operations allocated to fund manager	15.00%		15.00%
Percentage of available cash from dispositions allocated to shareholders	99.00%		99.00%
Percentage of available cash from dispositions allocated to fund manager	1.00%		1.00%
Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions	85.00%		85.00%
Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions	15.00%		15.00%
Distributions related to Raven Project			$ 7,200,000

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Organization and Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2014

Organization and Summary of Significant Accounting Policies [Abstract]

Summary of Available-For-Sale Securities

			Gross
	Amortized		Unrealized			Fair
	Cost		Gains (Losses)			Value
	(in thousands)
Government National Mortgage Association securities (GNMA July 2041)
September 30, 2014	$	84	$	3		$	87
December 31, 2013	$	90	$	1		$	91
Federal National Mortgage Association security (FNMA January 2042)
September 30, 2014	$	143	$	(1	)	$	142
December 31, 2013	$	198	$	(4	)	$	194

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Related Parties (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Related Party Transaction [Line Items]
Annual management fee percentage rate	2.50%		2.50%
Annual management fees paid to Fund Manager	$ 157,000	$ 232,000	$ 474,000	$ 697,000
Percentage of total distributions allocated to Fund Manager	15.00%		15.00%
Fund Manager [Member]
Related Party Transaction [Line Items]
Distributions	(100,000)	(200,000)	(500,000)	(1,000,000)
Fund Manager [Member] | Raven Project [Member]
Related Party Transaction [Line Items]
Percentage of total distributions allocated to Fund Manager	1.00%		1.00%
Distributions			$ (100,000)

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Organization and Summary of Significant Accounting Policies (Schedule of Available-For-Sale Securities) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
GNMA July 2041 [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	$ 84	$ 90
Gross Unrealized Gains (Losses)	3	1
Fair Value	87	91
FNMA January 2042 [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	143	198
Gross Unrealized Gains (Losses)	(1)	(4)
Fair Value	$ 142	$ 194

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Oil and Gas Properties (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Oil and Gas Properties [Abstract]
Cash consideration	$ 21,700,000		$ 21,700,000
Working interest percentage			25.00%
Proceeds from sale of oil and gas properties			10,978,000
Carrying value of oil and gas properties at date of sale	600,000		600,000
(Loss) gain on sale of oil and gas properties	(12,000)		10,396,000
Asset held for sale					1,266,000
Liability held for sale					684,000
Workover expense	$ 14,000	$ 55,000	$ 161,000	$ 116,000

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Credit Agreement - Beta Project Financing (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Credit Agreement - Beta Project Financing [Abstract]
Credit agreement, maximum borrowing capacity	$ 8,300,000	$ 8,300,000
Credit agreement, interest rate	8.00%	8.00%
Credit agreement, contingency repayment rate, first seven months of production	1.25%	1.25%
Credit agreement, contingency repayment rate, after first seven months of production	4.50%	4.50%
Credit agreement, maturity date		Dec. 31, 2020
Long-term borrowings	800,000	800,000
Capitalized interest	11,000	11,000
Deferred financing cost				$ 600,000

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UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities
Net income	$ 10,832	$ 4,548
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	904	2,494
Gain on sale of oil and gas properties	(10,396)
Changes in assets and liabilities:
Decrease in production receivable	720	953
Decrease (increase) in other current assets	40	(56)
(Decrease) increase in due to operators	(282)	139
Decrease in accrued expenses	(7)	(3)
Net cash provided by operating activities	1,811	8,075
Cash flows from investing activities
Payments to operators for working interests and expenditures		(95)
Proceeds from sale of oil and gas properties	10,978
Capital expenditures for oil and gas properties	(3,082)	(810)
Interest reinvested in salvage fund	(7)	(11)
Net cash provided by (used in) investing activities	7,889	(916)
Cash flows from financing activities
Long-term borrowings	800
Distributions	(10,109)	(6,651)
Net cash used in financing activities	(9,309)	(6,651)
Net increase in cash and cash equivalents	391	508
Cash and cash equivalents, beginning of period	4,690	5,045
Cash and cash equivalents, end of period	5,081	5,553
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$ 68

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Organization and Summary of Significant Accounting Policies (Policy)

9 Months Ended

Sep. 30, 2014

Organization and Summary of Significant Accounting Policies [Abstract]

Basis of Presentation

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, 2013 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

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.

Fair Value Measurements

Fair Value Measurements

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.

Cash and Cash Equivalents

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

Salvage Fund

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations.  At September 30, 2014 and December 31, 2013, 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.

			Gross
	Amortized		Unrealized			Fair
	Cost		Gains (Losses)			Value
	(in thousands)
Government National Mortgage Association securities (GNMA July 2041)
September 30, 2014	$	84	$	3		$	87
December 31, 2013	$	90	$	1		$	91
Federal National Mortgage Association security (FNMA January 2042)
September 30, 2014	$	143	$	(1	)	$	142
December 31, 2013	$	198	$	(4	)	$	194

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

Debt Discounts and Deferred Financing Costs

Debt discounts and deferred financing costs include lender fees and other costs of the Credit Agreement (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, 2014 and December 31, 2013, $0.4 million and $0.5 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $31 thousand for each of the three months ended September 30, 2014 and 2013. Amortization expense was $0.1 million for each of the nine months ended September 30, 2014 and 2013. 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”.

Oil and Gas Properties

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.  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.

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, 2014 and December 31, 2013, amounts recorded in due to operators totaling $0.9 million and $0.7 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

Advances to Operators for Working Interests and Expenditures

The Fund's acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund's rights, title and interest.  The Fund may be required to advance its share of estimated cash expenditures for the succeeding month's operation. The Fund accounts for such payments as advances to operators for working interests and expenditures.  As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

Asset Retirement Obligations

Asset Retirement Obligations

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

Syndication Costs

Syndication Costs

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

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 collectability 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

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 estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.

Impairment of Long-Lived Assets

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 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

Depletion, Depreciation and Amortization

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.

Income Taxes

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund's income or loss is passed through and included in the tax returns of the Fund's shareholders.

Income and Expense Allocation

Income and Expense Allocation

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

Distributions

Distributions

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

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.   During the nine months ended September 30, 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.

Recent Accounting Pronouncements

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.