10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2019

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)

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:

Shares of LLC Membership Interest

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes o   No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     Yes o   No x

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 every Interactive Data File required to be submitted 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 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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	x	Smaller reporting company Emerging growth company	x o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes o   No x

There is no market for the shares of LLC Membership Interest in the Fund. As of March 3, 2020, there were 207.7026 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY A-1 FUND, LLC
2019 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	10
	ITEM 1B	UNRESOLVED STAFF COMMENTS	10
	ITEM 2	PROPERTIES	10
	ITEM 3	LEGAL PROCEEDINGS	11
	ITEM 4	MINE SAFETY DISCLOSURES	11
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	12
	ITEM 6	SELECTED FINANCIAL DATA	12
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	18
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	18
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	18
	ITEM 9A	CONTROLS AND PROCEDURES	18
	ITEM 9B	OTHER INFORMATION	19
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	19
	ITEM 11	EXECUTIVE COMPENSATION	20
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	20
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	20
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	21
PART IV
	ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	22
		SIGNATURES	24

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy A-1 Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections and 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 U.S. Private Securities Litigation Reform Act of 1995 that are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market and other conditions affecting the pricing, production and demand of oil and natural gas, the cost and availability of equipment, and changes in domestic and foreign governmental regulations, as well as other risks and uncertainties discussed in this Annual Report in Item 1. “Business” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. 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.

1

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) 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 initiated its private placement offering on March 2, 2009, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In November 2012, pursuant to the Fund’s limited liability company agreement (the “LLC Agreement”), Ridgewood Energy Corporation, as manager of the Fund converted all then outstanding Investor GP Shares to Limited Liability Shares.  There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s LLC Agreement and applicable federal and state securities laws. The private placement offering was terminated on October 13, 2009. The Fund raised $41.1 million and, after payment of $6.7 million in offering fees, commissions and investment fees, the Fund had $34.5 million for investments and operating expenses.

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. Historically, when the Fund sought project investments, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Annual Report.

As compensation for its services, the Manager is entitled to receive an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. The Manager is entitled to receive the management fee from the Fund regardless of the Fund’s profitability in that year. Management fees during each of the years ended December 31, 2019 and 2018 were $0.4 million. Additionally, the Manager is entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2019 and 2018 were $0.3 million and $0.1 million, respectively.

In addition to the management fee, the Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing periodic reports for shareholders and the Securities Exchange Commission (“SEC”), taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses.

Business Strategy

The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of oil and natural gas projects. The frequency and amount of such distributions are within the Manager’s discretion, subject to available cash flow from operations. The Fund, along with other exploration and production companies, has invested in the drilling and development of both shallow and deepwater oil and natural gas projects in the U.S. offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s ownership in its projects is recorded with the Bureau of Ocean Energy Management (“BOEM”), an agency of the United States Department of Interior, as a working interest, which is an undivided fractional interest in a lease block that provides the owner with the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production.

2

The Fund’s capital has been fully invested in projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest, as discussed below under the heading “Properties” in this Item 1. “Business” of this Annual Report.

Investment Committee

Ridgewood Energy maintains an investment committee consisting of six employees of the Manager (the “Investment Committee”). The members of the Investment Committee provide operational, financial, scientific and technical oil and gas expertise to the Fund. One member of the Investment Committee is based out of the Manager’s Palm Beach, Florida office, one member is based out of the Manager’s Montvale, New Jersey office and four members are based out of the Manager’s Houston, Texas office. The Investment Committee’s current activities with respect to the Fund are principally related to the development and operation of properties in which it already has a working interest.

Participation and Joint Operating Agreements

On behalf of the Fund, and with respect to the Fund’s projects, the Manager negotiated participation and joint operating agreements with the operators of each project. Under each joint operating agreement, proposals and decisions with respect to a project and related activities are generally made based on percentage ownership approvals and, although an operator’s percentage ownership may constitute a majority ownership, operators generally seek consensus relating to project decisions.

Project Information

The Fund’s existing projects are located in the waters of the Gulf of Mexico on the Outer Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“OCSLA”), which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS. See further discussion under the heading “Regulation” in this Item 1. “Business” of this Annual Report.

Leases in the OCS are generally issued for a primary lease term of 5, 7 or 10 years, depending on the water depth of the lease block. Once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee, or third-party operator for a project, may conduct additional geological studies and may determine to drill additional exploratory or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee’s working interest ownership percentage.

Royalty Payments

Generally, and depending on the lease, working interest owners of an offshore oil and natural gas lease under the OCSLA pay a royalty of 12.5%, 16.67% or 18.75% to the U.S. Government through the Office of Natural Resources Revenue (“ONRR”). Other than the ONRR royalties, the Fund does not have material royalty burdens with the exception of the overriding royalty interests (“ORRI”) payable to the lender under and as required by the Fund’s credit agreement applicable to the Beta Project. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Royalty Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Royalty Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Fund currently has three projects, the Beta, Diller and Liberty projects, which are eligible for royalty relief under the Deepwater Royalty Relief Act. The Marmalard Project no longer qualifies for royalty relief as the project reached the royalty suspension volumes during 2018. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $39.52 per barrel and $51.32 per barrel) adjusted annually for inflation. The Deepwater Royalty Relief Act does not apply to natural gas if the prices of natural gas exceed certain thresholds (currently estimated to be between $4.94 per mmbtu and $8.55 per mmbtu) adjusted annually for inflation.

3

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned a working interest as of December 31, 2019. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, each of which produces both oil and natural gas, are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

	Total Productive Wells
	Gross		Net
Oil and natural gas		8		0.13

Acreage Data

The following table sets forth the Fund’s working interests in developed and undeveloped oil and natural gas acreage as of December 31, 2019. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and natural gas leases that have varying terms. All of the Fund’s oil and natural gas acreage is located in the offshore waters of the Gulf of Mexico.

Developed Acres				Undeveloped Acres
Gross		Net		Gross		Net
	28,793		493		364		6

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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for information regarding the funding of the Fund’s capital commitments.

		Total Spent		Total
	Working	through		Fund
Project	Interest	December 31, 2019		Budget		Status
		(in thousands)
Beta Project	1.64%	$	15,518	$	16,950	The Beta Project is expected to include the development of seven wells.  Wells #1 and #2 commenced production in 2016.  Wells #3  and #4 commenced production in 2017. Wells #5 and #6 commenced production in first quarter 2018 and third quarter 2018, respectively. Well #7 commenced production in first quarter 2019. The Fund expects to spend $0.6 million for additional development costs and $0.8 million for asset retirement obligations.
Liberty Project	2.0%	$	3,004	$	3,268	The Liberty Project, a single-well project, commenced production in 2010.  The Fund expects to spend $0.3 million for asset retirement obligations.

4

Beta Project – Partial Sale of Working Interest

On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 2.0% working interest in the Beta Project and sold a 0.364% working interest to the Buyers for a total purchase price of $3.3 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $3.1 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $34 thousand, which was recorded as an adjustment to the purchase price.

The net carrying value of the working interest sold as of the closing date was approximately $2.2 million and the related asset retirement obligation was approximately $40 thousand. A gain to the Fund of $0.9 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized by the Fund to repay a portion of the long-term debt outstanding under its credit agreement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs – Credit Agreement” for information regarding the Fund’s credit agreement.

Marketing/Customers

The Manager, on behalf of the Fund, markets the Fund’s oil and natural gas to third parties consistent with industry practice. The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, the Fund has two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations. The Fund’s current producing projects are near existing transportation infrastructure and pipelines.

The Fund’s oil and natural gas generally is sold to its customers at prevailing market prices, which fluctuate with demand as a result of related industry variables.   The markets for, and prices of, oil and natural gas have been volatile, and they are 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.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes”, “Results of Operations – Overview” and “Results of Operations – Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue. In the past, the Fund has entered, and in the future, may enter into transactions or derivative contracts that establish a price floor for portions of its oil or natural gas production. 

Seasonality

Generally, the Fund’s business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is producing, the operator of the project extracts oil and natural gas reserves throughout the year. Once extracted, oil and natural gas can be sold at any time during the year.

However, notwithstanding the ability of the Fund’s projects to produce year-round, the Fund’s properties are located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any significant damage, shut-ins, or production stoppages due to hurricane activity in 2019.

Operators

The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable joint operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's properties are operated by LLOG Exploration Offshore, L.L.C. and Walter Oil & Gas Corporation.

5

Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders have to rely on the Manager to continue to manage the projects prudently, efficiently and fairly.

Insurance

The Manager has obtained what it believes to be adequate insurance for the funds that it manages to cover the risks associated with the funds’ passive investments, including those of the Fund. Although the Fund is not an operator, the Manager has, nonetheless, obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to its projects. In addition, the Manager’s practice is to obtain insurance as a package that is intended to cover most, if not all, of the entities under its management. The Manager re-evaluates its insurance coverage on an annual basis. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the insurable incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims during a particular policy period to the Fund or its affiliates, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for its proportionate share of the cost of dismantling and removal of production platforms and facilities and plugging and abandoning the wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2019, the Fund had $1.9 million invested in a salvage fund. On a monthly basis, the Fund contributes to the salvage fund a portion of the operating income from the Beta Project to fund its asset retirement obligations. Such contributions to the salvage fund will reduce the amount of cash distributions that could otherwise be made to investors by the Fund. Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.

Competition

Competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. The Fund, through the Manager, has competed with other companies for the acquisition of leases, as well as percentage ownership interests in oil and natural gas working interests in the secondary market. The Fund does not anticipate the acquisition of any additional ownership interests in oil and natural gas working interests as its capital has been fully allocated to current and past projects.

Employees

The Fund has no employees. The Manager operates and manages the Fund.

Offices

The administrative office of both the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 230 Royal Palm Way, Suite 102, Palm Beach, FL, 33480 and 1254 Enclave Parkway, Houston, TX 77077. In addition, the Manager maintains an additional office lease that is used for administrative purposes for the Fund and other funds managed by the Manager.

Regulation

Oil and natural gas exploration, development, production and transportation activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to regulations. The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations.

6

Outer Continental Shelf Lands Act

Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOEM. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. BSEE regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE adopted strict requirements for subsea drilling production equipment and had proposed new requirements to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. BSEE has also published a policy statement on safety culture with nine characteristics of a robust safety culture. In May 2019, BSEE adopted a final rule revising standards for blowout prevention systems and other well controls pertaining to offshore activities (the “2019 Well Control Rule”). The 2019 Well Control Rule became effective July 15, 2019, however compliance with certain provisions was deferred until 2021 or thereafter as specified in those provisions. The 2019 Well Control Rule imposes new requirements relating to, among, other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. The 2019 Well Control Rule applies directly to operators as opposed to non-operators. On September 28, 2018, the BSEE published a final rule revising regulations relating to oil and natural gas production safety systems, subsurface safety devices and safety device testing (referred to as “Subpart H”); the rule was effective December 27, 2018. Given the fact that compliance with the 2019 Well Control Rule and Subpart H is the responsibility of the operators and the exploration and development of each well is different, the future costs associated with compliance that will be incurred by non-operators, such as the Fund, cannot be determined or estimated. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, which civil penalties were increased and adjusted for inflation on March 2, 2018, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activities can result from either governmental or citizen prosecution. 

BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the OCS (“Lessees”).  Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-N01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of the review of NTL 2016-N01. As of December 31, 2019, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01.  The impact of NTL 2016-N01, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

Sales and Transportation of Oil and Natural Gas

The Fund, directly or indirectly through affiliated entities, sells its proportionate share of oil and natural gas to the market and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service-based. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different than the impact to other oil or natural gas producers and marketers.

7

Environmental Matters and Regulation

The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water, the handling and managing of waste materials, and the protection of aquatic species and habitats. While most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operators on the Fund’s behalf, the Fund shares the liability along with its other working interest owners for environmental damage attributable to the Fund’s operations. The environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that may be caused by the Fund’s projects.

Some of the environmental laws that apply to oil and natural gas exploration and production are described below:

Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez spill, that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to, and defines penalties for, such spills. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA, and regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $672.51 million (effective as of November 12, 2019), while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $137.66 million in other damages for each incident. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. A failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on the Fund’s operations or financial condition.

Clean Water Act. Generally, the Clean Water Act, as well as analogous state requirements, imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal or delegated state agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. On December 11, 2018, the Environmental Protection Agency (“EPA”) and Department of the Army proposed a revised definition of “waters of the United States”, clarifying the limits of federal authority under the Clean Water Act. The scope of this authority, as defined under a 2015 rule, was challenged in several federal district court actions and therefore was repealed by the EPA and Department of the Army on September 12, 2019. The repeal, which became effective on December 23, 2019, restored the previous regulation to how it existed prior to finalization of the 2015 Rule. The current proposed revision will be the subject of a 60-day public comment period, once published in the Federal Register. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), as well as analogous state requirements, restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act and comparable state requirements.

International Marine Organization 2020. In 2016, the International Marine Organization (“IMO”), a United Nations (“UN”) Agency, instituted a reduction in the sulfur specifications for global marine fuels from 3.5% to 0.5% effective January 1, 2020 in order to reduce the emissions of sulfur to the atmosphere. Shipping companies have the option to buy low sulfur fuel or install scrubbers to lower sulfur emissions to comply with the new regulation. UN member states (174 countries) are responsible for monitoring the compliance of the shipping community with this new regulation. The impact to the Fund from this new regulation could be that heavier sour crudes, such as from the Beta Project, could fall in value relative to lighter sweet crudes as a result of excess high sulfur fuel on the market and subsequent refinery crude slate changes. However, the price of heavier sour crudes in the market continues to be supported by tightness in supply for such crude, new refinery capacity consuming medium/high sulfur crudes and refinery optimization around high sulfur products. As such, the Fund believes IMO 2020 will not in the future have a material impact on the Fund’s operations or financial condition.

8

Climate Change. The oil and gas industry is subject to federal and state greenhouse gas monitoring, reporting and emissions control requirements. The current state of international climate initiatives and federal and state actions presents challenges to assessing the impact to the Fund’s operations in relation to future international agreements, federal and state legislation, and other new requirements. Future restrictions on emissions of greenhouse gases could have an impact on future operations.

Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act of 1976, as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment. The Fund’s operations may be subject to analogous and comparable state laws and regulations, in addition to these federal statutes and regulations.

The above represents a brief outline of significant environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated thereunder. The Fund does not believe that its environmental, health and safety risks are materially different from those of comparable companies in the United States in the offshore oil and gas industry. However, there are no assurances that the environmental laws described above will not result in curtailment of production; material increases in the costs of production, development or exploration; enforcement actions or other penalties as a result of any non-compliance with any such regulations; or otherwise have a material adverse effect on the Fund’s operating results and cash flows.

Dodd-Frank Act. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market and, in addition, requires certain additional Securities and Exchange Commission (“SEC”) reporting requirements.

On February 3, 2017, the “Presidential Executive Order on Core Principles for Regulating the United States Financial System” (the “Order”) was issued to review the Dodd-Frank Act.  A series of reports were issued by the U.S. Department of the Treasury in 2017 pursuant to the Order generally recommending the harmonization, balancing and streamlining of rules and regulations relating to, among other things, the over-the-counter derivatives market. The Fund cannot predict at this time what regulations or portions of the law relating to the over-the-counter derivatives market, if any, will be changed as a result of the Order. Any changes in the law or regulation as a result of the Order could result in a repeal, amendment to or delayed implementation of the Dodd-Frank Act.

Currently, under the LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. The Dodd-Frank Act mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums. In addition, as required by the Dodd-Frank Act, the CFTC has set “speculative position limits” (which are limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts. These requirements under the Dodd-Frank Act could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties. If as a result of the legislation and regulations, the Fund alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance. The Fund is not currently, and has not been during 2019, or at any time since 2012, a party to any derivative instruments or hedging programs.

9

The Dodd-Frank Act also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals.  Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013.  On June 27, 2016, the SEC adopted amended resource extraction disclosure rules pursuant to Section 1504 of the Dodd-Frank Act. However, on February 14, 2017, a bill was passed by the United States Congress eliminating the SEC resource extraction disclosure rules. The SEC had one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act. No replacement rules were proposed or issued by the SEC.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

The information regarding the Fund’s properties that is contained in Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties,” is incorporated herein by reference.

Drilling Activity

The following table sets forth the Fund’s drilling activity during the years ended December 31, 2019 and 2018. Gross wells are the total number of wells in which the Fund has a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, which produce both oil and natural gas, are located in the offshore waters of the Gulf of Mexico. During the years ended December 31, 2019 and 2018, the Fund had no drilling activity for exploratory wells.

	2019				2018
	Gross		Net		Gross		Net
Development wells:
Productive		1		0.02		2		0.03
In-progress		-		-		1		0.02
Development well total		1		0.02		3		0.05

Unaudited Oil and Gas Reserve Quantities

The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation.  Such control procedures include: 1) verification of input data that is provided to an independent petroleum engineering firm; 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines; and 3) a review of the reserve estimates by a third-party independent petroleum engineering firm.

The Manager’s primary technical person in charge of overseeing the Fund’s reserve estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over thirty years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation of exploration and development opportunities, and the oversight of drilling and production operations.

The Fund’s reserve estimates as of December 31, 2019 and 2018 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.

Proved Reserves. Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed oil and gas reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are proved reserves expected to be recovered through new wells on undrilled acreage, or through existing wells where a relatively major expenditure is required for recompletion. The information regarding the Fund’s proved reserves, which is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Critical Accounting Estimates – Proved Reserves”, is incorporated herein by reference.  The information regarding the Fund’s unaudited net quantities of proved developed and undeveloped reserves, which is contained in Table III in the “Supplementary Financial Information – Information about Oil and Gas Producing Activities – Unaudited” included in Item 8. “Financial Statements and Supplementary Data” of this Annual Report, is incorporated herein by reference. 

10

Proved Undeveloped Reserves.  As of December 31, 2019 and 2018, the Fund did not have any proved undeveloped reserves.

Production and Prices

The information regarding the Fund’s production of oil and natural gas, and certain price and cost information during the years ended December 31, 2019 and 2018 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference.

Delivery Commitments

As of December 31, 2019, the Fund had no delivery obligations or delivery commitments under any existing contracts.

ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4.  MINE SAFETY DISCLOSURES

None.

11

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is currently no established public trading market for the Shares. As of January 31, 2020, there were 642 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Distributions may be impacted by funding of estimated asset retirement obligations and amounts reserved to provide for the borrowing repayments for the Fund’s credit agreement applicable to the Beta Project, as described in Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report. There is no requirement to distribute available cash and, as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 2019 and 2018, the Fund paid distributions totaling $1.9 million and $0.5 million, respectively.

ITEM 6.  SELECTED FINANCIAL DATA

Not required.

ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview of the Fund’s Business

The Fund was organized primarily to 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 oil and natural gas projects. Distributions to shareholders, if any, are funded from available cash from operations, as defined in the Fund’s LLC Agreement, and the frequency and amount are within the Manager’s discretion. The Fund’s capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.

The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. The Manager 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 development and producing operations, as appropriate. The Manager also participates in distributions. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.

Commodity Price Changes

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

Oil and natural gas commodity prices have been subject to significant fluctuations during the past several years. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. The Fund will continue to closely manage and coordinate its capital spending estimates within its expected cash flows to provide for future development costs of the Beta Project, as budgeted. See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 2019 and 2018 and the effect of such average prices on the Fund’s results of operations. If oil and natural gas commodity prices decline, even if only for a short period of time, the Fund’s results of operations and liquidity will be adversely impacted.

Market pricing for oil and natural gas is 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. Factors affecting market pricing for oil and natural gas include:

· weather conditions;

· economic conditions, including demand for petroleum-based products;

12

· actions by OPEC, the Organization of Petroleum Exporting Countries;

· political instability in the Middle East and other major oil and gas producing regions;

· governmental regulations, both domestic and foreign;

· domestic and foreign tax policy;

· the pace adopted by foreign governments for the exploration, development, and production of their national reserves;

· the supply and price of foreign oil and gas;

· the cost of exploring for, producing and delivering oil and gas;

· the discovery rate of new oil and gas reserves;

· the rate of decline of existing and new oil and gas reserves;

· available pipeline and other oil and gas transportation capacity;

· the ability of oil and gas companies to raise capital;

· the overall supply and demand for oil and gas; and

· the price and availability of alternate fuel sources.

Critical Accounting Estimates

The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented.  The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows.  See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s significant accounting policies. The following is a discussion of the accounting policies and estimates the Fund believes are most significant.

Accounting for Acquisition, Exploration and Development Costs

Acquisition, exploration and development 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. Annual lease rentals and exploration expenses are expensed as incurred.

Proved Reserves

Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization. Annually, the Fund engages an independent petroleum engineering firm to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, oil and natural gas commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change.

Asset Retirement Obligations

Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed. The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics and ongoing discussions with the wells’ operators. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors such as the timing of settlements, the credit-adjusted risk-free rates used and inflation rates, including changing technology and the political and regulatory environment. Estimates are reviewed annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates.

13

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties whenever events and circumstances indicate that the recorded carrying value of the assets may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. 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.

Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 2019 and 2018, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.

	Year ended December 31,
	2019			2018
	(in thousands)
Revenue
Oil and gas revenue	$	3,605		$	4,947
Other revenue		233			50
Total revenue		3,838			4,997
Expenses
Depletion and amortization		1,873			3,199
Operating expenses		569			611
Management fees to affiliate		373			373
General and administrative expenses		181			188
Other general expense		164			-
Total expenses		3,160			4,371
Gain on sale of oil and gas properties		-			865
Income from operations		678			1,491
Other (loss) income
Gain on debt extinguishment		-			1,313
Other income		-			40
Interest expense, net		(218	)		(460	)
Total other (loss) income		(218	)		893
Net income		460			2,384
Other comprehensive loss
Unrealized loss on marketable securities		-			(1	)
Total comprehensive income	$	460		$	2,383

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 2019 and 2018. Natural gas liquid (“NGL”) sales are included within gas sales.

	Year ended December 31,
	2019		2018
Number of wells producing		8		7
Total number of production days		2,652		1,838
Oil sales (in thousands of barrels)		60		74
Average oil price per barrel	$	57	$	63
Gas sales (in thousands of mcfs)		82		108
Average gas price per mcf	$	2.43	$	3.53

The increase in production days was primarily related to the commencement of production of two wells in the Beta Project, one well during third quarter 2018 and one well during first quarter 2019. The decreases in oil and gas sales volumes were related to the Beta and Liberty projects. The decrease in the Beta Project production was primarily related to the partial sale of working interest in the project during third quarter 2018 coupled with periodic shut-ins during first half 2019 due to certain drilling and completion operations performed at the project’s production facility. The Liberty Project experienced a decrease in production primarily as a result of shut-ins during 2019 due to mechanical work. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

14

Oil and Gas Revenue. Oil and gas revenue during the year ended December 31, 2019 was $3.6 million, a decrease of $1.3 million from the year ended December 31, 2018. The decrease was attributable to decreased sales volume totaling $0.9 million coupled with decreased oil and gas prices totaling $0.4 million.

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

Other Revenue. Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. See Note 3 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information.

Depletion and Amortization. Depletion and amortization during the year ended December 31, 2019 was $1.9 million, a decrease of $1.3 million from the year ended December 31, 2018. The decrease was attributable to a decrease in the average depletion rate totaling $0.7 million coupled with a decrease in production volumes totaling $0.6 million. The decrease in the average depletion rate was primarily attributable to changes in reserve estimates provided annually by the Fund’s independent petroleum engineers. Depletion and amortization was also impacted by the partial sale of working interest in the Beta Project during third quarter 2018.

See “Overview” above for certain factors that impact the depletion and amortization volume and rate variances.

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

	Year ended December 31,
	2019		2018
	(in thousands)
Lease operating expense	$	306	$	378
Insurance expense		89		116
Transportation and processing expense		78		77
Workover expense		75		6
Accretion expense and other		21		34
	$	569	$	611

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

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, were $0.5 million ($6.43 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2019, compared to $0.6 million ($6.22 per BOE) during the year ended December 31, 2018. Production costs and production costs per BOE remained relatively consistent during the year ended December 31, 2019 compared to the year ended December 31, 2018.

See “Overview” above for factors that impact oil and natural gas production.

Management Fees to Affiliate. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments, is paid monthly to the Manager.

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

Other General Expense.  During the year ended December 31, 2019, the Fund recorded other general expense of $0.2 million representing its proportionate share of a settlement for a litigation between the Beta Project’s operator and a third-party. Although the Fund was not party to the litigation, the Fund is responsible for its proportionate share of the costs of the litigation as well as any settlement made or judgement imposed upon the operator of the Beta Project if the claim is based upon or arises from operations on the Beta Project.  See Note 5 of “Notes to Financial Statements” – “Commitments and Contingencies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for information regarding this expense.  There was no such amount recorded during the year ended December 31, 2018.

15

Gain on Sale of Oil and Gas Properties. During the year ended December 31, 2018, the Fund recorded a gain on sale of oil and gas properties of $0.9 million related to the sale of a portion of the Fund’s working interest in the Beta Project. See Item 1. “Business” of this Annual Report under the heading “Beta Project – Partial Sale of Working Interest” for additional information regarding the sale. There was no such amount recorded during the year ended December 31, 2019. 

Gain on Debt Extinguishment. During the year ended December 31, 2018, the Fund recorded a gain on debt extinguishment of $1.3 million related to accounting for the fourth amendment to the credit agreement. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Fund’s credit agreement. There was no such amount recorded during the year ended December 31, 2019.

Other Income.  During the year ended December 31, 2018, the Fund recorded other income of $40 thousand related to a fee received upon execution of the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. There were no such amounts recorded during the year ended December 31, 2019.

Interest Expense, Net. Interest expense, net is comprised of interest expense and amortization of debt discounts related to the Fund’s long-term borrowings, and interest income earned on cash and cash equivalents and salvage fund. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Fund’s credit agreement.

Unrealized Loss on Marketable Securities. The Fund had an available-for-sale investment within its salvage fund in federal agency mortgage-backed securities. Available-for-sale debt securities were carried in the financial statements at fair value and unrealized gains and losses related to the securities’ changes in fair value were recorded in other comprehensive income when realized. During fourth quarter 2019, the Fund sold its investment in available-for sale debt securities and the proceeds received remained within the salvage fund. See Note 1 of “Notes to Financial Statements” – “Organizational and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the sale of the available-for-sale debt securities.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 2019 were $2.7 million, primarily related to revenue received of $4.0 million, partially offset by operating expenses of $0.6 million, management fees of $0.4 million, interest payments of $0.2 million and general and administrative expenses of $0.2 million.

Cash flows provided by operating activities during the year ended December 31, 2018 were $3.5 million, primarily related to revenue received of $5.1 million, partially offset by operating expenses of $0.6 million, interest payments of $0.5 million, management fees of $0.4 million and general and administrative expenses of $0.2 million.

Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 2019 were $0.1 million, related to capital expenditures for oil and gas properties of $0.4 million and investments in salvage fund of $0.2 million, partially offset by the reimbursement received from operator for capital expenditures of $0.5 million relating to a portion of the cost of the Beta Project platform slot that was utilized by the other third-party working interest owners for the Beta Project’s 8th well. The Fund as well as other funds managed by the Manager that invested in the Beta Project elected not to participate in the drilling of the 8th well proposed by the Beta Project operator. 

Cash flows provided by investing activities during the year ended December 31, 2018 were $0.7 million, related to proceeds from sale of oil and gas properties of $3.1 million, partially offset by capital expenditures for oil and gas properties of $2.2 million and investments in salvage fund of $0.2 million. 

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 2019 were $3.2 million, related to manager and shareholder distributions of $1.9 million and the repayments of long-term borrowings of $1.3 million.

Cash flows used in financing activities during the year ended December 31, 2018 were $4.5 million, related to the repayments of long-term borrowings of $4.0 million and manager and shareholder distributions of $0.5 million.

16

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. See Item 1. “Business” of this Annual Report under the heading “Properties” and “Liquidity Needs” below for additional information.

Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering and through debt financing. The Fund’s capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.

Liquidity Needs

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

As of December 31, 2019, the Fund’s estimated capital commitments related to its oil and gas properties were $2.6 million (which include asset retirement obligations for the Fund’s projects of $1.9 million), none of which is expected to be spent during the year ending December 31, 2020. Future results of operations and cash flows are dependent on the related production of oil and gas revenues from the Beta Project. Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments and ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year.

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. However, distributions may be impacted by funding of estimated asset retirement obligations and amounts reserved to provide for the borrowing repayments for the Credit Agreement (defined below).

Credit Agreement

As of December 31, 2019 and 2018, the Fund had outstanding borrowings of $1.9 million and $3.2 million, respectively, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”).

Borrowings under the Credit Agreement bear interest at 8.75% compounded monthly. Principal and interest payments are based on the fixed percentage of the Fund’s Net Revenue, as defined in the Credit Agreement. Beginning on April 1, 2019 and each April 1^st thereafter, the Fund’s fixed percentage is the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually beginning April 1, 2019 and every April 1^st thereafter, and is based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineer’s proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan of December 31, 2022. As of April 1, 2019, the Fund’s fixed percentage was determined to be 30%. The loan may be prepaid by the Fund without premium or penalty. The Credit Agreement also provides for a fixed percentage of 10.81% overriding royalty interest to the lenders, which will become payable to the lenders in January 2023, and requires mandatory prepayment of excess cash flows received by the Fund from certain insurance reimbursements, platform related revenues, production handling fees and any additional revenues received with respect to the use of the Beta Project other than any revenues included in the calculation of Net Revenue, as well as proceeds from a sale or transfer of any interest in the Beta Project as permitted under the Credit Agreement.

The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warranties and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the lenders under the Credit Agreement may accelerate the maturity of the loan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund is in compliance with all covenants under the Credit Agreement as of December 31, 2019 and 2018.

17

See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 2019 and 2018 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 as of December 31, 2019 and 2018, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs – Credit Agreement” above.

Recent Accounting Pronouncements

See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of recent accounting pronouncements applicable to the Fund’s financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302(b) of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits and Financial Statement Schedules” and filed as part of this report.

ITEM 9.             CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2019. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

Management's Report on Internal Control over Financial Reporting

Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)).  The Fund’s internal control over financial reporting is designed 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.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2019.  In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2019, the Fund’s internal control over financial reporting is effective.

18

This Annual Report does not include an attestation report of the Fund’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Fund’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Fund, as a non-accelerated filer, to provide only management’s report in this Annual Report.

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages as of December 31, 2019 are as follows:

Name, Age and Position with Registrant

Robert E. Swanson, 72

Chief Executive Officer

Kenneth W. Lang, 65

President and Chief Operating Officer

Kathleen P. McSherry, 54

Executive Vice President and Chief Financial Officer

Robert L. Gold, 61

Executive Vice President

Daniel V. Gulino, 59

Senior Vice President, General Counsel and Secretary

The officers in the above table have been officers of the Fund since February 3, 2009, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC, Ridgewood Private Equity Partners, LLC, Ridgewood Infrastructure, LLC and Ridgewood Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is an inactive member of the New York and New Jersey State Bars. He is a graduate of Amherst College and Fordham University Law School.

Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Effective February 1, 2020, Mr. Lang will relinquish the role of Chief Operating Officer of Ridgewood Energy. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President – Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.

19

Kathleen P. McSherry has served as the Executive Vice President and Chief Financial Officer of Ridgewood Energy since 2001. Ms. McSherry holds a Bachelor of Science degree in Accounting from Kean University.

Robert L. Gold has served as a senior officer of Ridgewood Energy since 1987 and is a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.

Daniel V. Gulino is Senior Vice President - Legal Affairs and Secretary for Ridgewood Energy and has served in that capacity for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management, LLC, Ridgewood Private Equity Partners, LLC and Ridgewood Infrastructure, LLC and Senior Vice President & General Counsel of Ridgewood Securities Corporation.  Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars.  Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.

Board of Directors and Board Committees

The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure.  Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11. “Executive Compensation” of this Annual Report.  Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager, the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.

Code of Ethics

The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on the Manager’s website. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN: General Counsel.

ITEM 11. EXECUTIVE COMPENSATION

The executive officers of the Fund do not receive compensation from the Fund. The Manager and its affiliates compensate the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report for more information regarding Manager compensation and payments to affiliated entities.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 207.7026 shares outstanding as of January 31, 2020. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pursuant to the terms of the LLC Agreement, the Manager renders management, advisory and administrative services to the Fund. For such services, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 2019 and 2018 were $0.4 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2019 and 2018 were $0.3 million and $0.1 million, respectively.

20

Beta S&T, a wholly-owned subsidiary of the Manager, acts as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations, and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project.

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas produced through the Beta Project production facility. See Note 3 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the PHA.

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

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

Profits and losses are allocated in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 2019 and 2018.

	Year ended December 31,
	2019		2018
	(in thousands)
Audit fees (1)	$	86	$	87

⁽¹⁾ Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.

21

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1)     Financial Statements

See “Index to Financial Statements” set forth on page F-1.

(a) (2)     Financial Statement Schedules

None.

(a) (3)  

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING
3.1	Certificate of Formation of Ridgewood Energy A-1 Fund, LLC dated February 3, 2009	Incorporated by reference to the Fund's Form 10 filed on February 18, 2010
3.2	Certificate of Amendment of Ridgewood Energy A-1 Fund, LLC dated February 24, 2009	Incorporated by reference to the Fund's Form 10 filed on February 18, 2010
3.3	Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy A-1  Fund, LLC dated March 2, 2009	Incorporated by reference to the Fund’s Form 10 filed on February 18, 2010
4	Description of Shares	Filed herewith
10.1	Credit Agreement dated as of November 27, 2012 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund’s Form 8-K filed on December 3, 2012
10.2	First Amendment to Credit Agreement dated September 30, 2016 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund’s Form 10-K filed on March 2, 2017
10.3	Second Amendment to Credit Agreement and Reaffirmation of Waiver dated September 15, 2017 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund's Form 10-Q filed on November 7, 2017
10.4	Third Amendment to Credit Agreement dated June 1, 2018 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund’s Form 8-K filed on June 7, 2018

22

10.5	Fourth Amendment to Credit Agreement dated August 10, 2018 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund’s Form 10-Q filed on August 14, 2018
10.6	Purchase and Sale Agreement dated August 10, 2018 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, as Sellers and each individually a Seller and Walter Oil & Gas Corporation and Gordy Oil Company as Buyers and each individually a Buyer	Incorporated by reference to the Fund’s Form 10-Q filed on August 14, 2018
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
99.1	Report of Netherland, Sewell & Associates, Inc.	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

23

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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
Date:  March 3, 2020	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
		March 3, 2020
/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)
Robert E. Swanson
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	March 3, 2020
Kathleen P. McSherry
RIDGEWOOD ENERGY CORPORATION
BY:  /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	March 3, 2020
Robert E. Swanson

24

INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2019 and 2018	F-3
Statements of Operations and Comprehensive Income for the years ended December 31, 2019 and 2018	F-4
Statements of Changes in Members' Capital for the years ended December 31, 2019 and 2018	F-5
Statements of Cash Flows for the years ended December 31, 2019 and 2018	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-15

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Manager of Ridgewood Energy A-1 Fund, LLC

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Ridgewood Energy A-1 Fund, LLC (the "Fund") as of December 31, 2019 and 2018, the related statements of operations and comprehensive income, changes in members’ capital, and cash flows, for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Fund as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on the Fund's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Fund in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Fund’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Parsippany, New Jersey

March 3, 2020

We have served as the Fund's auditor since 2009.

F-2

RIDGEWOOD ENERGY A-1 FUND, LLC

BALANCE SHEETS

(in thousands, except share data) 

	December 31,
	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	1,566		$	2,124
Production receivable		391			338
Due from affiliate (Note 3)		13			50
Other current assets		37			48
Total current assets		2,007			2,560
Salvage fund		1,871			1,710
Oil and gas properties:
Proved properties		20,109			20,663
Less:  accumulated depletion and amortization		(11,302	)		(9,405	)
Total oil and gas properties, net		8,807			11,258
Total assets	$	12,685		$	15,528
Liabilities and Members' Capital
Current liabilities:
Due to operators	$	264		$	618
Accrued expenses		45			43
Current portion of long-term borrowings		898			945
Other current liabilities		164			-
Total current liabilities		1,371			1,606
Long-term borrowings		988			2,256
Asset retirement obligations		1,500			1,446
Total liabilities		3,859			5,308
Commitments and contingencies (Note 5)
Members' capital:
Manager:
Distributions		(5,407	)		(5,129	)
Retained earnings		6,424			6,054
Manager's total		1,017			925
Shareholders:
Capital contributions (250 shares authorized;
207.7026 issued and outstanding)		41,143			41,143
Syndication costs		(4,804	)		(4,804	)
Distributions		(37,404	)		(35,829	)
Retained earnings		8,874			8,784
Shareholders' total		7,809			9,294
Accumulated other comprehensive income		-			1
Total members' capital		8,826			10,220
Total liabilities and members' capital	$	12,685		$	15,528

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

F-3

RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(in thousands, except per share data) 

	Year ended December 31,
	2019			2018
Revenue
Oil and gas revenue	$	3,605		$	4,947
Other revenue		233			50
Total revenue		3,838			4,997
Expenses
Depletion and amortization		1,873			3,199
Operating expenses		569			611
Management fees to affiliate (Note 3)		373			373
General and administrative expenses		181			188
Other general expense		164			-
Total expenses		3,160			4,371
Gain on sale of oil and gas properties		-			865
Income from operations		678			1,491
Other (loss) income
Gain on debt extinguishment		-			1,313
Other income		-			40
Interest expense, net		(218	)		(460	)
Total other (loss) income		(218	)		893
Net income		460			2,384
Other comprehensive loss
Unrealized loss on marketable securities		-			(1	)
Total comprehensive income	$	460		$	2,383
Manager Interest
Net income	$	370		$	570
Shareholder Interest
Net income	$	90		$	1,814
Net income per share	$	432		$	8,732

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

F-4

RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

									Accumulated Other
									Comprehensive
	# of Shares		Manager			Shareholders			Income			Total
Balances, December 31, 2017		207.7026	$	426		$	7,882		$	2		$	8,310
Distributions		-		(71	)		(402	)		-			(473	)
Net income		-		570			1,814			-			2,384
Other comprehensive loss		-		-			-			(1	)		(1	)
Balances, December 31, 2018		207.7026	$	925		$	9,294		$	1		$	10,220
Distributions		-		(278	)		(1,575	)		-			(1,853	)
Net income		-		370			90			-			460
Amount reclassified from accumulated      other comprehensive income		-		-			-			(1	)		(1	)
Balances, December 31, 2019		207.7026	$	1,017		$	7,809		$	-		$	8,826

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

F-5

RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2019			2018
Cash flows from operating activities
Net income	$	460		$	2,384
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion and amortization		1,873			3,199
Gain on sale of oil and gas properties		-			(865	)
Accretion expense		22			25
Gain on debt extinguishment		-			(1,313	)
Amortization of debt discounts		4			1
Changes in assets and liabilities:
(Increase) decrease in production receivable		(53	)		144
Decrease (increase) in due from affiliate		37			(50	)
Decrease in other current assets		11			4
Increase in due to operators		151			-
Increase (decrease) in accrued expenses		2			(2	)
Increase (decrease) in other current liabilities		164			(40	)
Settlement of asset retirement obligations		-			(13	)
Net cash provided by operating activities		2,671			3,474
Cash flows from investing activities
Capital expenditures for oil and gas properties		(355	)		(2,211	)
Reimbursement from operator for capital expenditures		460			-
Proceeds from sale of oil and gas properties		-			3,065
Increase in salvage fund		(162	)		(165	)
Net cash (used in) provided by investing activities		(57	)		689
Cash flows from financing activities
Repayments of long-term borrowings		(1,319	)		(3,989	)
Distributions		(1,853	)		(473	)
Net cash used in financing activities		(3,172	)		(4,462	)
Net decrease in cash and cash equivalents		(558	)		(299	)
Cash and cash equivalents, beginning of year		2,124			2,423
Cash and cash equivalents, end of year	$	1,566		$	2,124
Supplemental disclosure of cash flow information
Cash paid for interest	$	234		$	468
Supplemental disclosure of non-cash investing activities
Due to operators for accrued capital expenditures for oil and gas properties	$	4		$	509

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

F-6

RIDGEWOOD ENERGY A-1 FUND, LLC

NOTES TO 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. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 3, 4 and 5.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“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, management reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. 

Fair Value Measurements

The Fund follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its financial statements. 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 consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.

The Fund’s financial assets and liabilities consist of cash and cash equivalents, production receivable, due from affiliate, other current assets, salvage fund, due to operators, accrued expenses, other current liabilities and long-term debt. Except for long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. Mortgage-backed securities within the salvage fund were recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets and the inputs were consistent with the Level 2 definition above. The Fund’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy. The fair value of long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis.

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2019, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2019, the Fund’s bank balances, including salvage fund, were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, 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. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. As of December 31, 2018, the Fund had an investment in federal agency mortgage-backed securities within the salvage fund as detailed in the following table, which was classified as available-for-sale. Available-for-sale securities were carried in the financial statements at fair value.

F-7

			Gross
	Amortized		Unrealized		Fair
	Cost		Gains		Value
	(in thousands)
Government National Mortgage Association security (GNMA July 2041)
December 31, 2018	$	36	$	1	$	37

The unrealized gains on the Fund's investment in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of the investment were guaranteed by an agency of the U.S. government. Unrealized gains or losses on available-for-sale debt securities were reported in other comprehensive income until realized.

On October 21, 2019, the Fund sold all of its investment for gross proceeds of $37 thousand resulting in a de minimis realized gain, which was recorded within “Other income” on the Fund’s statements of operations during the year ended December 31, 2019. The unrealized gain of $1 thousand was reclassified out of “Accumulated other comprehensive income” and into “Other income” at the time of the sale.

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.

Acquisition, exploration and development 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. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred.

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

The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties.

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Fund’s credit-adjusted risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2019 and 2018:

F-8

	December 31,
	2019		2018
	(in thousands)
Balance, beginning of year	$	1,446	$	1,401
Liabilities incurred		-		2
Liabilities settled/relieved		-		(54	)
Accretion expense		22		25
Revision of estimates		32		72
Balance, end of year	$	1,500	$	1,446

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

The Fund recognizes oil and gas revenue from contracts with customers at the point when control of oil and natural gas is transferred to the customer at an amount that reflects the consideration the Fund expects to be entitled to in accordance with Accounting Standard Codification 606 Revenue from Contracts with Customers (“ASC 606”). The Fund’s revenue recognition policies, performance obligations and significant judgements in applying ASC 606 are described below.

Oil and Gas Revenue

Generally, the Fund sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. Natural gas liquid (“NGL”) sales are included within gas sales. The Fund’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances.

In the first type of agreement, a netback agreement, the Fund receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Fund records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Fund delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Fund pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Fund records the transportation expense within operating expenses in the statements of operations.

Under the Fund’s natural gas processing contracts, the Fund delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Fund for the sale of NGLs. In this type of arrangement, the Fund evaluates whether it is the principal or agent in the transaction. The Fund concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Fund recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded as an expense within operating expenses in the statements of operations.

In certain instances, the Fund may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Fund delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Fund recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded as expense within operating expenses in the statements of operations.

The Fund assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Fund satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Fund’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery are reflected in revenue in the month payments are received.

F-9

Transaction Price Allocated to Remaining Performance Obligations

Under the Fund’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer.

Contract Balances

The Fund invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the balance sheets.

Other Revenue

Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. The Fund earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Fund, thus there are no unsatisfied performance obligations. The Fund’s project operator performs joint interest billing once the performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties does not give rise to contract assets or liabilities. The receivables related to the Fund’s proportionate share of revenue from an affiliate are included within “Due from affiliate” on the Fund’s balance sheets. The receivables related to the Fund’s proportionate share of revenue from third parties are presented as a reduction from “Due to operator” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund when the operator performs the joint interest billing of the lease operating expenses due from the Fund.

Prior Period Performance Obligations

The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. During the years ended December 31, 2019 and 2018, revenue recognized from performance obligations satisfied in previous periods was not significant.

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. 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.

There were no impairments of oil and gas properties during the years ended December 31, 2019 and 2018. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and costs to construct offshore platform and associated asset retirement costs.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2016 through 2018 tax returns remain open for examination by tax authorities.

F-10

Income and Expense Allocation

Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.

Distributions

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

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

Recent Accounting Pronouncements

In August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund will adopt this accounting guidance effective January 1, 2020. The adoption of this accounting guidance is not expected to have a material impact on the Fund’s financial statements.

In June 2016, the FASB issued accounting guidance on measurement of credit losses, which introduces, among other things, a new expected loss impairment model that applies to most financial assets measured at amortized cost and certain other instruments including trade and other receivables and other financial assets. Under the new accounting guidance, entities are required to estimate expected credit loss over the life of financial assets and record an allowance against the asset’s amortized cost basis to present the financial asset at the amount expected to be collected. The estimate of expected credit losses will require entities to incorporate considerations of historical information, current information and reasonable and supportable forecasts. The accounting guidance and the most recent update issued in February 2020 are effective for the Fund in the first quarter of 2023 with early adoption permitted. The Fund early adopted this accounting guidance and related updates on January 1, 2020 and the adoption did not have a material impact on the Fund’s financial statements.

In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance was effective for the Fund beginning January 1, 2019. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.

2. Oil and Gas Properties

The Fund, as well as other funds managed by the Manager, that invested in the Beta Project elected not to participate in the drilling of the 8th well proposed by Walter Oil and Gas Corporation. As a result, the Fund was due reimbursement for a portion of the cost relating to the slot on the Beta Project platform that was utilized by the other third-party working interest owners for the 8th well. On July 17, 2019, the Fund and the other third-party working interest owners in the Beta Project agreed to a reimbursement to the Fund of $0.5 million, which was recorded as a reduction to oil and gas properties on the Fund’s balance sheet as of December 31, 2019 and presented as “Reimbursement from operator for capital expenditures” in the investing section of the Fund’s statement of cash flows for the year ended December 31, 2019. The amount received was utilized by the Fund to repay a portion of the long-term debt outstanding under the Credit Agreement as defined below in Note 4.

F-11

On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 2.0% working interest in the Beta Project and sold a 0.364% working interest to the Buyers for a total purchase price of $3.3 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $3.1 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $34 thousand, which was recorded as an adjustment to the purchase price.

The net carrying value of the working interest sold as of the closing date was approximately $2.2 million and the related asset retirement obligation was approximately $40 thousand. A gain to the Fund of $0.9 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized by the Fund to repay a portion of the long-term debt outstanding under the Credit Agreement as defined below in Note 4.

3. Related Parties

Pursuant to the terms of the LLC Agreement, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 2019 and 2018 were $0.4 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2019 and 2018 were $0.3 million and $0.1 million, respectively.

Beta Sales and Transport, LLC

The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project.  In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project.

Production Handling, Gathering and Operating Services Agreement

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility.

During fourth quarter 2018, the Beta Project Owners commenced their production and handling services for the oil and natural gas produced from the Claiborne Project. During each of the years ended December 31, 2019 and 2018, the Fund earned $0.1 million, representing its proportionate share of the production handling fees earned from Institutional Fund II, which is included within “Other revenue” on the Fund’s statements of operations. As of December 31, 2019 and 2018, the Fund’s receivables of $13 thousand and $0.1 million, respectively, related to the Fund’s proportionate share of revenue from Institutional Fund II are included within “Due from affiliate” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund on behalf of the Claiborne Project working interest owners when the operator performs the joint interest billing of the lease operating expenses due from the Fund. The revenue received from the PHA is utilized by the Fund to repay a portion of the long-term debt outstanding under its Credit Agreement (defined below) until the loan is repaid in full, in no event later than December 31, 2022. During the year ended December 31, 2018, the Fund recorded other income of $40 thousand related to a fee received upon execution of the PHA. There were no such amounts recorded during the year ended December 31, 2019.

F-12

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

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

4. Credit Agreement – Beta Project Financing

As of December 31, 2019 and 2018, the Fund had outstanding borrowings of $1.9 million and $3.2 million, respectively, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”). As of December 31, 2019, the estimated fair value of the debt was $1.9 million.

Borrowings under the Credit Agreement bear interest at 8.75% compounded monthly. Principal and interest payments are based on the fixed percentage of the Fund’s Net Revenue, as defined in the Credit Agreement. Beginning on April 1, 2019 and each April 1^st thereafter, the Fund’s fixed percentage is the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually beginning April 1, 2019 and each April 1^st thereafter, and is based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineer’s proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan of December 31, 2022. As of April 1, 2019, the Fund’s fixed percentage was determined to be 30%. The loan may be prepaid by the Fund without premium or penalty. Pursuant to the Credit Agreement, the Fund also agreed to convey a fixed percentage of 10.81% overriding royalty interest in its working interest in the Beta Project to the lenders, which will become payable to the lenders on January 1, 2023.

As of December 31, 2019 and 2018, the unamortized debt discounts related to the loan of $11 thousand and $15 thousand, respectively, were presented as a reduction of “Long-term borrowings” on the Fund’s balance sheets. Amortization expense during the years ended December 31, 2019 and 2018 of $4 thousand and $1 thousand, respectively, was included on the Fund’s statements of operations within “Interest expense, net”. As of December 31, 2019 and 2018, there were no accrued interest costs outstanding. Interest costs incurred during the years ended December 31, 2019 and 2018 of $0.2 million and $0.5 million, respectively, were included on the Fund’s statements of operations within “Interest expense, net”.

As of December 31, 2019, the estimated principal repayments of debt are as follows: $0.9 million in 2020 and $1.0 million in 2021. The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2019 and 2018.

During third quarter 2018, the Fund determined that the terms of the fourth amendment to the Credit Agreement dated August 10, 2018 met the conditions of debt extinguishment pursuant to Accounting Standard Codification 470-50 Debt: Modification and Extinguishments guidance in a non-troubled debt restructuring. As a result, the Fund recorded a gain on debt extinguishment of $1.3 million, which was recorded within “Other income (loss)” in its statements of operations. The gain on debt extinguishment primarily represents non-cash gains associated with the change in the fair value of ORRI conveyed to the lenders totaling $1.3 million and the difference between the fair value of the new debt and the carrying amount of the old debt totaling $16 thousand.

5. Commitments and Contingencies

Capital Commitments

As of December 31, 2019, the Fund’s estimated capital commitments related to its oil and gas properties were $2.6 million (which include asset retirement obligations for the Fund’s projects of $1.9 million), none of which is expected to be spent during the year ending December 31, 2020. Future results of operations and cash flows are dependent on the related production of oil and gas revenues from the Beta Project.

Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments and ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.

F-13

Other Contingencies

The operator was subject to litigation with a third-party, relating to change order requests for the Beta Project platform.    The Fund was not a named party to the lawsuit filed and was not a party to the litigation; however, under the operating agreement (“OA”) the Fund is responsible for its proportionate share of costs of the litigation as well as any settlements made or judgement imposed upon the operator if the claim is based upon or arises from operations on the Beta project. Under the OA, the settlement required the Fund’s approval.  In February 2020, the Fund approved its proportionate share of the proposed settlement amount. The Fund determined that the approval of the proposed settlement represented the culmination of conditions existing as of December 31, 2019, and as a result, the Fund recorded its proportionate share of the settlement totaling $0.2 million within “Other general expense” on its statements of operations during the year ended December 31, 2019.

Environmental and Governmental Regulations

Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2019 and 2018, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. 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. 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.

BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of the review of NTL 2016-N01. As of December 31, 2019, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01.  The impact of NTL 2016-N01, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

Insurance Coverage

The Fund is subject to all risks inherent in the oil and natural gas business. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the entities managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other entities managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.

F-14

Ridgewood Energy A-1 Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities – Unaudited

In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of the Gulf of Mexico.

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2019			2018
	(in thousands)
Proved properties	$	20,109		$	20,663
Accumulated depletion and amortization		(11,302	)		(9,405	)
Oil and gas properties, net	$	8,807		$	11,258

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2019			2018
	(in thousands)
Exploration costs	$	(1	)	$	8
Development costs		(579	)		2,294
	$	(580	)	$	2,302

F-15

Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2019 and 2018. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

	December 31, 2019												December 31, 2018
	United States
	Oil (MBBLS)			NGL (MBBLS)			Gas (MMCF)			Total (MBOE) (a)			Oil (MBBLS)			NGL (MBBLS)			Gas (MMCF)			Total (MBOE) (a)
Proved developed and undeveloped reserves:
Beginning of year		304.2			24.2			152.0			353.8			261.6			20.6			132.4			304.3
Revisions of previous estimates (b)		22.4			4.5			44.2			34.2			156.7			14.5			92.4			186.6
Production		(59.6	)		(6.3	)		(40.3	)		(72.6	)		(73.3	)		(8.0	)		(53.6	)		(90.2	)
Sale of minerals in place (c)		-			-			-			-			(40.8	)		(2.9	)		(19.2	)		(46.9	)
End of year		267.0			22.4			155.9			315.4			304.2			24.2			152.0			353.8
Proved developed reserves:
Beginning of year		304.2			24.2			152.0			353.8			199.5			15.8			102.7			232.5
End of year		267.0			22.4			155.9			315.4			304.2			24.2			152.0			353.8
Proved undeveloped reserves:
Beginning of year		-			-			-			-			62.1			4.8			29.7			71.8
End of year		-			-			-			-			-			-			-			-

(a) BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency.

(b) Revisions of previous estimates were attributable to well performance.

(c) On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties.

F-16

Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

	December 31,
	2019			2018
	(in thousands)
Future cash inflows	$	15,118		$	20,066
Future production costs		(3,211	)		(2,627	)
Future development costs		(2,605	)		(2,631	)
Future net cash flows		9,302			14,808
10% annual discount for estimated timing of cash flows		(1,365	)		(2,439	)
Standardized measure of discounted future estimated net cash flows	$	7,937		$	12,369

Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

	Year ended December 31,
	2019			2018
	(in thousands)
Net change in sales and transfer prices and in production costs  related to future production	$	(3,113	)	$	4,466
Sales and transfers of oil and gas produced during the period		(3,132	)		(4,376	)
Net change due to purchases and sales of minerals in place		-			(787	)
Changes in estimated future development costs		26			395
Net change due to revisions in quantities estimates		1,102			7,686
Accretion of discount		1,237			573
Other		(552	)		(1,321	)
Aggregate change in the standardized measure of discounted future net cash  flows for the year	$	(4,432	)	$	6,636

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.

F-17

EX-4

Exhibit 4

DESCRIPTION OF THE REGISTRANT’S SHARES OF LLC MEMBERSHIP INTEREST

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

The following summary of Ridgewood Energy A-1 Fund, LLC’s shares of LLC membership interests is based on and qualified by the Fund’s Limited Liability Company Agreement (the “LLC Agreement”). For a complete description of the terms and provisions of the Fund’s shares refer to the LLC Agreement, which is filed as an exhibit to this Annual Report on Form 10-K.

The shares are membership interest in the Fund, which is a limited liability company (“Shares”). The following is a summary of certain provisions of the Fund’s LLC Agreement.

Control of LLC Operations

The powers vested in the Ridgewood Energy Corporation (the “Manager”), as manager of the Fund, under the LLC Agreement are broad. The Manager has full, exclusive and complete discretion in the management and control of the affairs of the Fund and shareholders have no power to take part in the management of, or to bind, the Fund except for the limited voting rights provided in the LLC Agreement and except as required by law.

The Fund’s officers are appointed by the Manager and may be removed by it at any time. Additionally, the Manager may authorize any sale, lease, pledge or other transfer of substantially all of a Fund’s assets without a vote of the shareholders.

Voting Rights and Amendments to the LLC Agreement

The Manager may amend the LLC Agreement without notice to or approval of the holders of Shares for the following purposes:

· to cure ambiguities or errors;

· to equitably resolve issues arising under the LLC Agreement so long as similarly situated shareholders are not treated materially differently;

· to comply with law;

· to make other changes that will not materially and adversely affect any shareholder’s interest;

· to maintain the federal income tax status of the Fund or any shareholder, as long as no shareholder’s liability is materially increased; and

· as otherwise provided in the LLC Agreement.

Other amendments to the LLC Agreement may be proposed either by the Manager or by holders of twenty-five percent or more of the outstanding Shares entitled to vote. A vote on the proposal may be made either by calling a meeting of the shareholders or by soliciting written consents. Proposed amendments require the approval of shareholders who hold of record at least a majority of the total Shares on the record date for the action, given at a meeting of shareholders or by written consents. Any amendment requiring shareholder action (other than an amendment to allow the Fund to be taxed other than as a partnership) may not increase any shareholder’s liability, change the capital contributions required of him or her or his or her rights in interest in the Fund’s profits, losses, deductions, credits, revenues or distributions in more than a de minimis matter, or change his or her rights on dissolution or any voting or management rights without such shareholder’s consent. Any amendment that changes the Manager’s management rights, other than the removal of the Manager, requires the consent of the Manager. Generally, shareholders have no right to vote on matters other than those involving (i) certain amendments to the LLC Agreement, (ii) the removal of the Manager, (iii) the conversion of the Fund to corporate form, (iv) the withdrawal of a shareholder, and (v) the designation of a new Manager upon a vacancy. If any matter requires a vote of shareholders, it must be approved by shareholders who own of record at least a majority of the Shares, or if a different vote is required by law, each shareholder will have voting rights equal to his or her total Shares for purposes of determining the number of votes cast or not cast.  Holders of Shares have one vote for each whole Share, and for each fractional Share, a fraction of one vote equal to the fraction of a Share it represents.

For all purposes, a majority of the Shares means Shares representing more than fifty percent of the combined voting power of all of the Shares entitled to vote on a certain matter.

Participation in Costs and Revenues

Available cash determines what amounts the Fund will be able to distribute in cash to shareholders. There are three types of available cash:

· available cash from operations;

· available cash from capital transactions; and

· available cash from temporary investments, which include investments in marketable securities, money market accounts, and similar type investments.

These terms are not defined by, and are not the same as, similar concepts under GAAP.  Available cash from operations is generally total cash received by the Fund from operations less related expenses, as further described in the LLC Agreement.  Available cash from capital transactions is generally proceeds received by the Fund in connection with the acquisition, transfer, distribution or disposition of Fund assets or interest that is made other than in the ordinary course of the Fund’s business.  Available cash from temporary investments is generally total cash received by the Fund in connection with its short-term investments.  There is no fixed requirement to distribute available cash. Instead, available cash will be distributed to shareholders to the extent, and at such times, as the Manager believes is advisable. Once the amount and timing of a distribution is determined, it shall be made to shareholders as described below.

Distributions from Operations

At such times during a calendar year as the Manager determines, if all early investment incentive distributions have been made in full, the Fund may make distributions up to the amount of the undistributed available cash from operations to shareholders. The Manager will be entitled to 15% and shareholders will be entitled to 85% of the available cash from operations distributed.

Distributions from Capital Transactions

Available cash from capital transactions that the Manager decides to distribute will be paid as follows:

· before shareholders have received total distributions (including distributions from available cash from operations and available cash from capital transactions) equal to their capital contributions, 99% of available cash from capital transactions will be distributed to shareholders and 1% to the Manager; and

· after shareholders have received total distributions (including available cash from operations and available cash from capital transactions) equal to their capital contributions, 85% of available cash from capital transactions will be distributed to shareholders and 15% to the Manager.

Distributions from Temporary Investments

The Manager may determine that the Fund make distributions up to the amount of the undistributed available cash from temporary, or short-term, investments to shareholders. The Manager will be entitled to 1% and shareholders will be entitled to 99% of the available cash from temporary investments distributed.

General Distribution Provisions

Distributions to shareholders under the foregoing provisions will be apportioned among them in proportion to their ownership of Shares. The Manager has the sole discretion to determine the amount and frequency of any distributions. However, distributions may not be made selectively to one shareholder or group of shareholders, but must be made ratably to all shareholders entitled to that type of distribution at that time. The Manager in its discretion nevertheless may credit select persons with a portion of the Manager’s compensation or distributions from the Fund.

Return of Capital Contributions

Each shareholder may look solely to the Fund assets and not to the Manager or the other shareholders for the return of such shareholder’s respective contributions to the Fund, and any returns or interest thereon, and has no right or power to demand or receive property other than cash from the Fund.  The Fund and the Manager will not be required to return any fees properly deducted from the original capital contribution or any costs and expenses incurred and paid by the Fund. 

Voluntary Additional Capital Contributions and Supplemental Offering of Shares

The LLC Agreement does not provide for any mandatory assessments of capital from shareholders. This means that the Fund cannot require any shareholder to contribute more money after the completion of such shareholder’s subscription and payment of such shareholder’s initial capital contribution.  

If voluntary additional capital contributions are requested by the Fund to fund additional project activities, the Manager will do so through a supplemental offering of shares in the Fund. The Manager has the discretion to determine the nature, scope, amount and terms of such supplemental offering.

A shareholder who elects to not participate in any supplemental offering of shares and does not provide additional capital contributions for such additional project activities will have no interest in such additional project activities, but will retain his interest in the projects in which the Fund has already invested. The failure of a shareholder to participate in a supplemental offering may have a dilutive effect on such shareholder’s investment.

Removal of Manager

Shareholders may propose the removal of the Manager, either by calling a meeting or soliciting consents in accordance with the terms of the LLC Agreement. Removal of the Manager requires the affirmative vote of a majority of the Shares and that the Manager has committed an illegal act or an act of gross negligence or willful misconduct that has had a material adverse effect on the Fund.  The shareholders may replace the removed Manager or fill a vacancy by a vote of a majority of the Shares.  In the event that the Manager is removed, the Fund must pay to the Manager a cash amount equal to its capital account balance and any fees or reimbursement to which the Manager is entitled.

Dissolution of Fund

The Fund will wind up, dissolve and terminate its operations on the earliest to occur of either (a) the determination by the Manager to terminate and dissolve the Fund or (b) any other event requiring dissolution by law.  Upon the dissolution of the Fund, the Fund will wind up its business, sell all of its assets (except as otherwise determined by the liquidating trustee), and liquidate the Fund’s assets to the Investors.

If, upon liquidation, the capital account of the Manager has a deficit balance, the Manager will be required to make additional capital contributions to the Fund in an amount necessary to restore such deficit balance to zero.

Transferability of Interests

The Shares are subject to transfer restrictions set forth in the LLC Agreement.  Under the terms of the LLC Agreement, no shareholder may assign or transfer all or any part of his or her interest in the Fund and no transferee will be deemed a substitute shareholder or be entitled to exercise or receive any of the rights, powers or benefits of a shareholder unless (i) such transferee has been approved and accepted by the Manager, in its sole and absolute discretion, as a substitute shareholder, and (ii) certain other requirements set forth in the LLC Agreement (including receipt of an opinion of counsel that the transfer does not have adverse effects under the securities laws) have been satisfied.  Notwithstanding the foregoing, an involuntary transfer of all or part of a shareholder’s Shares may occur by reason of (i) death, (ii) court order, (iii) dissolution of a shareholder which is an entity, (iv) bankruptcy, (v) divorce, (vi) foreclosure, or (vii) any other transfer by operation of law, pursuant to which the Shares are permitted to pass directly to the transferee and the transferee will become an assignee of such Shares and be subject to the terms and conditions of the LLC Agreement.  The transferee, however, will not become a member of the Fund unless and until admitted as a substitute shareholder as set forth above.

Liability 

Assuming compliance with the LLC Agreement and applicable formative and qualifying requirements in Delaware and any other jurisdiction in which the Fund conducts its business, a holder of Shares will not be personally liable under Delaware law or the LLC Agreement for any obligations of the Fund, except:

· to the extent of any unpaid capital contributions;

· for the amount of any wrongful distributions that render the Fund insolvent; and

· for any loss, damage or claim arising from any act or omission of such shareholder, including, without limitation, indemnification liabilities arising from any misrepresentation made by the shareholder to the Fund when purchasing Shares.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Robert E. Swanson, certify that:

1. I have reviewed this Annual Report on Form 10-K 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:	March 3, 2020
/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 Annual Report on Form 10-K 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:	March 3, 2020
/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 Annual Report on Form 10-K of the Ridgewood Energy A-1 Fund, LLC (the “Fund”) for the fiscal year ended December 31, 2019, 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:	March 3, 2020	/s/	ROBERT E. SWANSON
		Name:	Robert E. Swanson
		Title:	Chief Executive Officer
			(Principal Executive Officer)
Dated:	March 3, 2020	/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.

EX-99.1

Exhibit 99.1

February 14, 2020

Mr. W. Kent Webb

Ridgewood Energy Corporation

1254 Enclave Parkway, Suite 600

Houston, Texas 77077

Dear Mr. Webb:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2019, to the Ridgewood Energy A-1 Fund, LLC (Ridgewood A-1 Fund) interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Ridgewood A-1 Fund. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Ridgewood A-1 Fund's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Ridgewood A-1 Fund interest in these properties, as of December 31, 2019, to be:

	Net Reserves						Future Net Revenue (M$)
	Oil		NGL		Gas				Present Worth
Category	(MBBL)		(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		150.4		12.1		86.4		4,409.0		4,336.9
Proved Developed Non-Producing		116.5		10.3		69.5		4,892.5		3,600.3
Total Proved Developed		267.0		22.4		155.9		9,301.6		7,937.2

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2019, there are no proved undeveloped reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage.

Gross revenue is Ridgewood A-1 Fund's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Ridgewood A-1 Fund's share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2019. For oil and NGL volumes, the average Light Louisiana Sweet spot price of $61.17 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.578 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $53.94 per barrel of oil, $13.48 per barrel of NGL, and $2.659 per MCF of gas.

Operating costs used in this report are based on operating expense records of Ridgewood Energy Corporation (Ridgewood). These costs include production handling agreement fees and the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses are not included. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Ridgewood and are based on authorizations for expenditure and internal planning budgets. Capital costs are included as required for workovers and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Ridgewood's estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Ridgewood A-1 Fund interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Ridgewood A-1 Fund receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Ridgewood, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones and non-producing zones; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Ridgewood, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. John R. Cliver, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2009 and has over 5 years of prior industry experience. Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer
	/s/ John R. Cliver		/s/ Shane M. Howell
By:		By:
	John R. Cliver, P.E. 107216		Shane M. Howell, P.G. 11276
	Vice President		Vice President
Date Signed:  February 14, 2020		Date Signed:  February 14, 2020
JRC:PNH

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

Definitions - Page 1 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

Definitions - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

Definitions - Page 3 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

Definitions - Page 4 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). 

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

Definitions - Page 5 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

Ÿ The company's historical record at completing development of comparable long-term projects;

Ÿ The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

Ÿ The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

Ÿ The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

XML

Oil and Gas Properties

12 Months Ended

Dec. 31, 2019

Percentage of total distributions allocated to Fund Manager

Oil and Gas Properties

2. Oil and Gas Properties

The Fund, as well as other funds managed by the Manager, that invested in the Beta Project elected not to participate in the drilling of the 8th well proposed by Walter Oil and Gas Corporation. As a result, the Fund was due reimbursement for a portion of the cost relating to the slot on the Beta Project platform that was utilized by the other third-party working interest owners for the 8th well. On July 17, 2019, the Fund and the other third-party working interest owners in the Beta Project agreed to a reimbursement to the Fund of $0.5 million, which was recorded as a reduction to oil and gas properties on the Fund’s balance sheet as of December 31, 2019 and presented as “Reimbursement from operator for capital expenditures” in the investing section of the Fund’s statement of cash flows for the year ended December 31, 2019. The amount received was utilized by the Fund to repay a portion of the long-term debt outstanding under the Credit Agreement as defined below in Note 4.

On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 2.0% working interest in the Beta Project and sold a 0.364% working interest to the Buyers for a total purchase price of $3.3 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $3.1 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $34 thousand, which was recorded as an adjustment to the purchase price.

The net carrying value of the working interest sold as of the closing date was approximately $2.2 million and the related asset retirement obligation was approximately $40 thousand. A gain to the Fund of $0.9 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized by the Fund to repay a portion of the long-term debt outstanding under the Credit Agreement as defined below in Note 4.

XML

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue
Oil and gas revenue	$ 3,605	$ 4,947
Other revenue	233	50
Total revenue	3,838	4,997
Expenses
Depletion and amortization	1,873	3,199
Operating expenses	569	611
Management fees to affiliate	373	373
General and administrative expenses	181	188
Other general expense	164
Total expenses	3,160	4,371
Gain on sale of oil and gas properties		865
Income from operations	678	1,491
Other (loss) income
Gain on debt extinguishment		1,313
Other income		40
Interest expense, net	(218)	(460)
Total other (loss) income	(218)	893
Net income	460	2,384
Other comprehensive loss
Unrealized loss on marketable securities		(1)
Total comprehensive income	460	2,383
Manager Interest
Net income	370	570
Shareholder Interest
Net income	$ 90	$ 1,814
Net income per share	$ 432	$ 8,732

XML

Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Information About Oil And Gas Producing Activities [Abstract]
Exploration costs	$ (1)	$ 8
Development costs	(579)	2,294
Total costs	$ (580)	$ 2,302

XML

Related Parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Annual management fee percentage rate	2.50%
Annual management fees paid to Fund Manager	$ 373	$ 373
Percentage of total distributions allocated to Fund Manager	15.00%
Distributions	$ (1,853)	(473)
Other revenue from affiliate	100	100
Due from affiliate	13	50
Other income		40
Manager [Member]
Distributions	$ (278)	$ (71)

XML

Organization and Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Organization and Summary of Significant Accounting Policies [Abstract]
Cash insured amount	$ 250
Proceeds from sale of investments	37
Amount reclassified from accumulated other comprehensive income	$ 1
Percentage of cash from operations allocated to shareholders	85.00%
Percentage of cash from operations allocated to Fund Manager	15.00%
Percentage of cash from dispositions allocated to shareholders	99.00%
Percentage of cash from dispositions allocated to Fund Manager	1.00%
Percentage of cash from dispositions allocated to shareholders after distributions have equaled capital contributions	85.00%
Percentage of cash from dispositions allocated to Fund Manager after distributions have equaled capital contributions	15.00%

XML

Information about Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2019

Information About Oil And Gas Producing Activities [Abstract]

Information about Oil and Gas Producing Activities

Ridgewood Energy A-1 Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities – Unaudited

In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of the Gulf of Mexico.

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2019			2018
	(in thousands)
Proved properties	$	20,109		$	20,663
Accumulated depletion and amortization		(11,302	)		(9,405	)
Oil and gas properties, net	$	8,807		$	11,258

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2019			2018
	(in thousands)
Exploration costs	$	(1	)	$	8
Development costs		(579	)		2,294
	$	(580	)	$	2,302

Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2019 and 2018. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

	December 31, 2019												December 31, 2018
	United States
	Oil (MBBLS)			NGL (MBBLS)			Gas (MMCF)			Total (MBOE) (a)			Oil (MBBLS)			NGL (MBBLS)			Gas (MMCF)			Total (MBOE) (a)
Proved developed and undeveloped reserves:
Beginning of year		304.2			24.2			152.0			353.8			261.6			20.6			132.4			304.3
Revisions of previous estimates (b)		22.4			4.5			44.2			34.2			156.7			14.5			92.4			186.6
Production		(59.6	)		(6.3	)		(40.3	)		(72.6	)		(73.3	)		(8.0	)		(53.6	)		(90.2	)
Sale of minerals in place (c)		-			-			-			-			(40.8	)		(2.9	)		(19.2	)		(46.9	)
End of year		267.0			22.4			155.9			315.4			304.2			24.2			152.0			353.8
Proved developed reserves:
Beginning of year		304.2			24.2			152.0			353.8			199.5			15.8			102.7			232.5
End of year		267.0			22.4			155.9			315.4			304.2			24.2			152.0			353.8
Proved undeveloped reserves:
Beginning of year		-			-			-			-			62.1			4.8			29.7			71.8
End of year		-			-			-			-			-			-			-			-

(a) BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency.

(b) Revisions of previous estimates were attributable to well performance.

(c) On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties.

Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

	December 31,
	2019			2018
	(in thousands)
Future cash inflows	$	15,118		$	20,066
Future production costs		(3,211	)		(2,627	)
Future development costs		(2,605	)		(2,631	)
Future net cash flows		9,302			14,808
10% annual discount for estimated timing of cash flows		(1,365	)		(2,439	)
Standardized measure of discounted future estimated net cash flows	$	7,937		$	12,369

Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

	Year ended December 31,
	2019			2018
	(in thousands)
Net change in sales and transfer prices and in production costs  related to future production	$	(3,113	)	$	4,466
Sales and transfers of oil and gas produced during the period		(3,132	)		(4,376	)
Net change due to purchases and sales of minerals in place		-			(787	)
Changes in estimated future development costs		26			395
Net change due to revisions in quantities estimates		1,102			7,686
Accretion of discount		1,237			573
Other		(552	)		(1,321	)
Aggregate change in the standardized measure of discounted future net cash  flows for the year	$	(4,432	)	$	6,636

It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.

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Organization and Summary of Significant Accounting Policies (Schedule of Available-For-Sale Securities) (Details) - GNMA July 2041 [Member] $ in Thousands	Dec. 31, 2018 USD ($)
Amortized Cost	$ 36
Gross Unrealized Gains	1
Fair Value	$ 37

XML

Organization and Summary of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Use of Estimates

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“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, management reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. 

Fair Value Measurements

Fair Value Measurements

The Fund follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its financial statements. 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 consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.

The Fund’s financial assets and liabilities consist of cash and cash equivalents, production receivable, due from affiliate, other current assets, salvage fund, due to operators, accrued expenses, other current liabilities and long-term debt. Except for long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. Mortgage-backed securities within the salvage fund were recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets and the inputs were consistent with the Level 2 definition above. The Fund’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy. The fair value of long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis.

Cash and Cash Equivalents

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2019, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2019, the Fund’s bank balances, including salvage fund, were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

Salvage Fund

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, 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. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. As of December 31, 2018, the Fund had an investment in federal agency mortgage-backed securities within the salvage fund as detailed in the following table, which was classified as available-for-sale. Available-for-sale securities were carried in the financial statements at fair value.

			Gross
	Amortized		Unrealized		Fair
	Cost		Gains		Value
	(in thousands)
Government National Mortgage Association security (GNMA July 2041)
December 31, 2018	$	36	$	1	$	37

The unrealized gains on the Fund's investment in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of the investment were guaranteed by an agency of the U.S. government. Unrealized gains or losses on available-for-sale debt securities were reported in other comprehensive income until realized.

On October 21, 2019, the Fund sold all of its investment for gross proceeds of $37 thousand resulting in a de minimis realized gain, which was recorded within “Other income” on the Fund’s statements of operations during the year ended December 31, 2019. The unrealized gain of $1 thousand was reclassified out of “Accumulated other comprehensive income” and into “Other income” at the time of the sale.

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.

Acquisition, exploration and development 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. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred.

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

The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to 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. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Fund’s credit-adjusted risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2019 and 2018:

	December 31,
	2019		2018
	(in thousands)
Balance, beginning of year	$	1,446	$	1,401
Liabilities incurred		-		2
Liabilities settled/relieved		-		(54	)
Accretion expense		22		25
Revision of estimates		32		72
Balance, end of year	$	1,500	$	1,446

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

Revenue Recognition

The Fund recognizes oil and gas revenue from contracts with customers at the point when control of oil and natural gas is transferred to the customer at an amount that reflects the consideration the Fund expects to be entitled to in accordance with Accounting Standard Codification 606 Revenue from Contracts with Customers (“ASC 606”). The Fund’s revenue recognition policies, performance obligations and significant judgements in applying ASC 606 are described below.

Oil and Gas Revenue

Generally, the Fund sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. Natural gas liquid (“NGL”) sales are included within gas sales. The Fund’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances.

In the first type of agreement, a netback agreement, the Fund receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Fund records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Fund delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Fund pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Fund records the transportation expense within operating expenses in the statements of operations.

Under the Fund’s natural gas processing contracts, the Fund delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Fund for the sale of NGLs. In this type of arrangement, the Fund evaluates whether it is the principal or agent in the transaction. The Fund concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Fund recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded as an expense within operating expenses in the statements of operations.

In certain instances, the Fund may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Fund delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Fund recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded as expense within operating expenses in the statements of operations.

The Fund assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Fund satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Fund’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery are reflected in revenue in the month payments are received.

Transaction Price Allocated to Remaining Performance Obligations

Under the Fund’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer.

Contract Balances

The Fund invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the balance sheets.

Other Revenue

Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. The Fund earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Fund, thus there are no unsatisfied performance obligations. The Fund’s project operator performs joint interest billing once the performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties does not give rise to contract assets or liabilities. The receivables related to the Fund’s proportionate share of revenue from an affiliate are included within “Due from affiliate” on the Fund’s balance sheets. The receivables related to the Fund’s proportionate share of revenue from third parties are presented as a reduction from “Due to operator” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund when the operator performs the joint interest billing of the lease operating expenses due from the Fund.

Prior Period Performance Obligations

The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. During the years ended December 31, 2019 and 2018, revenue recognized from performance obligations satisfied in previous periods was not significant.

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. 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.

There were no impairments of oil and gas properties during the years ended December 31, 2019 and 2018. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

Depletion and Amortization

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and costs to construct offshore platform and associated asset retirement costs.

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. The Fund files U.S. Federal and State tax returns and the 2016 through 2018 tax returns remain open for examination by tax authorities.

Income and Expense Allocation

Income and Expense Allocation

Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.

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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund will adopt this accounting guidance effective January 1, 2020. The adoption of this accounting guidance is not expected to have a material impact on the Fund’s financial statements.

In June 2016, the FASB issued accounting guidance on measurement of credit losses, which introduces, among other things, a new expected loss impairment model that applies to most financial assets measured at amortized cost and certain other instruments including trade and other receivables and other financial assets. Under the new accounting guidance, entities are required to estimate expected credit loss over the life of financial assets and record an allowance against the asset’s amortized cost basis to present the financial asset at the amount expected to be collected. The estimate of expected credit losses will require entities to incorporate considerations of historical information, current information and reasonable and supportable forecasts. The accounting guidance and the most recent update issued in February 2020 are effective for the Fund in the first quarter of 2023 with early adoption permitted. The Fund early adopted this accounting guidance and related updates on January 1, 2020 and the adoption did not have a material impact on the Fund’s financial statements.

In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance was effective for the Fund beginning January 1, 2019. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.

XML

Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Mar. 03, 2020
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
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	2019
Document Fiscal Period Focus	FY
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity File Number	000-53895
Entity Current Reporting Status	Yes
Entity Well Known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Shell Company	false
Entity Interactive Data Current	Yes
Entity Incorporation, State or Country Code	DE
Entity Common Stock, Shares Outstanding		207.7026
Entity Public Float	$ 0

XML

STATEMENTS OF CHANGES IN PARTNERS CAPITAL - USD ($) $ in Thousands	# of Shares [Member]	Manager [Member]	Shareholders [Member]	Accumulated Other Comprehensive Income [Member]	Total
Balances at Dec. 31, 2017		$ 426	$ 7,882	$ 2	$ 8,310
Balances, shares at Dec. 31, 2017	207.7026
Distributions		(71)	(402)		(473)
Net income		570	1,814		2,384
Other comprehensive loss				(1)	(1)
Balances at Dec. 31, 2018		925	9,294	1	$ 10,220
Balances, shares at Dec. 31, 2018	207.7026				207.7026
Distributions		(278)	(1,575)		$ (1,853)
Net income		370	90		460
Other comprehensive loss
Amount reclassified from accumulated other comprehensive income				(1)	(1)
Balances at Dec. 31, 2019		$ 1,017	$ 7,809		$ 8,826
Balances, shares at Dec. 31, 2019	207.7026				207.7026

XML

Related Parties

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Parties

3. Related Parties

Pursuant to the terms of the LLC Agreement, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 2019 and 2018 were $0.4 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2019 and 2018 were $0.3 million and $0.1 million, respectively.

Beta Sales and Transport, LLC

The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project.  In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project.

Production Handling, Gathering and Operating Services Agreement

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility.

During fourth quarter 2018, the Beta Project Owners commenced their production and handling services for the oil and natural gas produced from the Claiborne Project. During each of the years ended December 31, 2019 and 2018, the Fund earned $0.1 million, representing its proportionate share of the production handling fees earned from Institutional Fund II, which is included within “Other revenue” on the Fund’s statements of operations. As of December 31, 2019 and 2018, the Fund’s receivables of $13 thousand and $0.1 million, respectively, related to the Fund’s proportionate share of revenue from Institutional Fund II are included within “Due from affiliate” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund on behalf of the Claiborne Project working interest owners when the operator performs the joint interest billing of the lease operating expenses due from the Fund. The revenue received from the PHA is utilized by the Fund to repay a portion of the long-term debt outstanding under its Credit Agreement (defined below) until the loan is repaid in full, in no event later than December 31, 2022. During the year ended December 31, 2018, the Fund recorded other income of $40 thousand related to a fee received upon execution of the PHA. There were no such amounts recorded during the year ended December 31, 2019.

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

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

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Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)		12 Months Ended
		Dec. 31, 2019 bbl Mcf	Dec. 31, 2018 bbl Mcf
Oil (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year		304,200	261,600
Revisions of previous estimates	[1]	22,400	156,700
Production		(59,600)	(73,300)
Sale of minerals in place	[2]		(40,800)
End of year		267,000	304,200
Proved developed reserves:
Beginning of year		304,200	199,500
End of year		267,000	304,200
Proved undeveloped reserves:
Beginning of year			62,100
End of year
NGL (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year		24,200	20,600
Revisions of previous estimates	[1]	4,500	14,500
Production		(6,300)	(8,000)
Sale of minerals in place	[2]		(2,900)
End of year		22,400	24,200
Proved developed reserves:
Beginning of year		24,200	15,800
End of year		22,400	24,200
Proved undeveloped reserves:
Beginning of year			4,800
End of year
Gas (MCF) [Member]
Proved developed and undeveloped reserves:
Beginning of year | Mcf		152,000	132,400
Revisions of previous estimates | Mcf	[1]	44,200	92,400
Production | Mcf		(40,300)	(53,600)
Sale of minerals in place | Mcf	[2]		(19,200)
End of year | Mcf		155,900	152,000
Proved developed reserves:
Beginning of year | Mcf		152,000	102,700
End of year | Mcf		155,900	152,000
Proved undeveloped reserves:
Beginning of year | Mcf			29,700
End of year | Mcf
Total (BOE) [Member]
Proved developed and undeveloped reserves:
Beginning of year	[3]	353,800	304,300
Revisions of previous estimates	[1],[3]	34,200	186,600
Production	[3]	(72,600)	(90,200)
Sale of minerals in place	[2],[3]		(46,900)
End of year	[3]	315,400	353,800
Proved developed reserves:
Beginning of year	[3]	353,800	232,500
End of year	[3]	315,400	353,800
Proved undeveloped reserves:
Beginning of year	[3]		71,800
End of year	[3]

[1] Revisions of previous estimates were attributable to well performance.

[2] On August 10, 2018, the Fund sold a portion of the Fund's working interest in the Beta Project to third parties.

[3] BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency.

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Credit Agreement - Beta Project Financing (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-term borrowings	$ 1,900	$ 3,200
Fair value of debt	$ 1,900
Interest rate	8.75%
Periodic payment, fixed percentage	30.00%
Overriding royalty interest	10.81%
Unamortized debt discounts	$ 11	15
Amortization of financing costs	4	1
Accrued interest
Interest expense	200	500
Estimated principal repayments - 2020	900
Estimated principal repayments - 2021	1,000
Gain on debt extinguishment		1,313
Change in fair value of ORRI		1,300
Difference between fair value of new debt and carrying amount of old debt		$ 16

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Oil and Gas Properties (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Aug. 10, 2018	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reimbursement from operator for capital expenditures			$ 460
Cash received				3,065
Gain on sale		$ (34)		865
Asset retirement obligation		$ 1,446	$ 1,500	$ 1,446	$ 1,401
Beta Project [Member]
Working interest percentage	2.00%
Working interest acquired by buyers	0.364%
Total purchase price	$ 3,300
Cash received	3,100
Carrying value	2,200
Asset retirement obligation	$ 40

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Information about Oil and Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2019

Information About Oil And Gas Producing Activities [Abstract]

Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities

Table I - Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2019			2018
	(in thousands)
Proved properties	$	20,109		$	20,663
Accumulated depletion and amortization		(11,302	)		(9,405	)
Oil and gas properties, net	$	8,807		$	11,258

Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

	Year ended December 31,
	2019			2018
	(in thousands)
Exploration costs	$	(1	)	$	8
Development costs		(579	)		2,294
	$	(580	)	$	2,302

Schedule of Reserve Quantity Information

Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2019 and 2018. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.

	December 31, 2019												December 31, 2018
	United States
	Oil (MBBLS)			NGL (MBBLS)			Gas (MMCF)			Total (MBOE) (a)			Oil (MBBLS)			NGL (MBBLS)			Gas (MMCF)			Total (MBOE) (a)
Proved developed and undeveloped reserves:
Beginning of year		304.2			24.2			152.0			353.8			261.6			20.6			132.4			304.3
Revisions of previous estimates (b)		22.4			4.5			44.2			34.2			156.7			14.5			92.4			186.6
Production		(59.6	)		(6.3	)		(40.3	)		(72.6	)		(73.3	)		(8.0	)		(53.6	)		(90.2	)
Sale of minerals in place (c)		-			-			-			-			(40.8	)		(2.9	)		(19.2	)		(46.9	)
End of year		267.0			22.4			155.9			315.4			304.2			24.2			152.0			353.8
Proved developed reserves:
Beginning of year		304.2			24.2			152.0			353.8			199.5			15.8			102.7			232.5
End of year		267.0			22.4			155.9			315.4			304.2			24.2			152.0			353.8
Proved undeveloped reserves:
Beginning of year		-			-			-			-			62.1			4.8			29.7			71.8
End of year		-			-			-			-			-			-			-			-

(a) BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency.

(b) Revisions of previous estimates were attributable to well performance.

(c) On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties.

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.

	December 31,
	2019			2018
	(in thousands)
Future cash inflows	$	15,118		$	20,066
Future production costs		(3,211	)		(2,627	)
Future development costs		(2,605	)		(2,631	)
Future net cash flows		9,302			14,808
10% annual discount for estimated timing of cash flows		(1,365	)		(2,439	)
Standardized measure of discounted future estimated net cash flows	$	7,937		$	12,369

Schedule of Changes in the Standardized Measure for Discounted Cash Flows

Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows

The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.

	Year ended December 31,
	2019			2018
	(in thousands)
Net change in sales and transfer prices and in production costs  related to future production	$	(3,113	)	$	4,466
Sales and transfers of oil and gas produced during the period		(3,132	)		(4,376	)
Net change due to purchases and sales of minerals in place		-			(787	)
Changes in estimated future development costs		26			395
Net change due to revisions in quantities estimates		1,102			7,686
Accretion of discount		1,237			573
Other		(552	)		(1,321	)
Aggregate change in the standardized measure of discounted future net cash  flows for the year	$	(4,432	)	$	6,636

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

5. Commitments and Contingencies

Capital Commitments

As of December 31, 2019, the Fund’s estimated capital commitments related to its oil and gas properties were $2.6 million (which include asset retirement obligations for the Fund’s projects of $1.9 million), none of which is expected to be spent during the year ending December 31, 2020. Future results of operations and cash flows are dependent on the related production of oil and gas revenues from the Beta Project.

Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments and ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.

Other Contingencies

The operator was subject to litigation with a third-party, relating to change order requests for the Beta Project platform.    The Fund was not a named party to the lawsuit filed and was not a party to the litigation; however, under the operating agreement (“OA”) the Fund is responsible for its proportionate share of costs of the litigation as well as any settlements made or judgement imposed upon the operator if the claim is based upon or arises from operations on the Beta project. Under the OA, the settlement required the Fund’s approval.  In February 2020, the Fund approved its proportionate share of the proposed settlement amount. The Fund determined that the approval of the proposed settlement represented the culmination of conditions existing as of December 31, 2019, and as a result, the Fund recorded its proportionate share of the settlement totaling $0.2 million within “Other general expense” on its statements of operations during the year ended December 31, 2019.

Environmental and Governmental Regulations

Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2019 and 2018, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. 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. 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.

BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of the review of NTL 2016-N01. As of December 31, 2019, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01.  The impact of NTL 2016-N01, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

Insurance Coverage

The Fund is subject to all risks inherent in the oil and natural gas business. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the entities managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other entities managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.

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BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Shares authorized	250	250
Shares issued	207.7026	207.7026
Shares outstanding	207.7026	207.7026

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Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [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. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 3, 4 and 5.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“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, management reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. 

Fair Value Measurements

The Fund follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its financial statements. 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 consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.

The Fund’s financial assets and liabilities consist of cash and cash equivalents, production receivable, due from affiliate, other current assets, salvage fund, due to operators, accrued expenses, other current liabilities and long-term debt. Except for long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. Mortgage-backed securities within the salvage fund were recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets and the inputs were consistent with the Level 2 definition above. The Fund’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy. The fair value of long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis.

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2019, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2019, the Fund’s bank balances, including salvage fund, were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, 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. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. As of December 31, 2018, the Fund had an investment in federal agency mortgage-backed securities within the salvage fund as detailed in the following table, which was classified as available-for-sale. Available-for-sale securities were carried in the financial statements at fair value.

			Gross
	Amortized		Unrealized		Fair
	Cost		Gains		Value
	(in thousands)
Government National Mortgage Association security (GNMA July 2041)
December 31, 2018	$	36	$	1	$	37

The unrealized gains on the Fund's investment in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of the investment were guaranteed by an agency of the U.S. government. Unrealized gains or losses on available-for-sale debt securities were reported in other comprehensive income until realized.

On October 21, 2019, the Fund sold all of its investment for gross proceeds of $37 thousand resulting in a de minimis realized gain, which was recorded within “Other income” on the Fund’s statements of operations during the year ended December 31, 2019. The unrealized gain of $1 thousand was reclassified out of “Accumulated other comprehensive income” and into “Other income” at the time of the sale.

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.

Acquisition, exploration and development 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. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred.

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

The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties.

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Fund’s credit-adjusted risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2019 and 2018:

	December 31,
	2019		2018
	(in thousands)
Balance, beginning of year	$	1,446	$	1,401
Liabilities incurred		-		2
Liabilities settled/relieved		-		(54	)
Accretion expense		22		25
Revision of estimates		32		72
Balance, end of year	$	1,500	$	1,446

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

The Fund recognizes oil and gas revenue from contracts with customers at the point when control of oil and natural gas is transferred to the customer at an amount that reflects the consideration the Fund expects to be entitled to in accordance with Accounting Standard Codification 606 Revenue from Contracts with Customers (“ASC 606”). The Fund’s revenue recognition policies, performance obligations and significant judgements in applying ASC 606 are described below.

Oil and Gas Revenue

Generally, the Fund sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. Natural gas liquid (“NGL”) sales are included within gas sales. The Fund’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances.

In the first type of agreement, a netback agreement, the Fund receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Fund records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Fund delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Fund pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Fund records the transportation expense within operating expenses in the statements of operations.

Under the Fund’s natural gas processing contracts, the Fund delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Fund for the sale of NGLs. In this type of arrangement, the Fund evaluates whether it is the principal or agent in the transaction. The Fund concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Fund recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded as an expense within operating expenses in the statements of operations.

In certain instances, the Fund may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Fund delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Fund recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded as expense within operating expenses in the statements of operations.

The Fund assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Fund satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Fund’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery are reflected in revenue in the month payments are received.

Transaction Price Allocated to Remaining Performance Obligations

Under the Fund’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer.

Contract Balances

The Fund invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the balance sheets.

Other Revenue

Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. The Fund earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Fund, thus there are no unsatisfied performance obligations. The Fund’s project operator performs joint interest billing once the performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties does not give rise to contract assets or liabilities. The receivables related to the Fund’s proportionate share of revenue from an affiliate are included within “Due from affiliate” on the Fund’s balance sheets. The receivables related to the Fund’s proportionate share of revenue from third parties are presented as a reduction from “Due to operator” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund when the operator performs the joint interest billing of the lease operating expenses due from the Fund.

Prior Period Performance Obligations

The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. During the years ended December 31, 2019 and 2018, revenue recognized from performance obligations satisfied in previous periods was not significant.

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. 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.

There were no impairments of oil and gas properties during the years ended December 31, 2019 and 2018. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and costs to construct offshore platform and associated asset retirement costs.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2016 through 2018 tax returns remain open for examination by tax authorities.

Income and Expense Allocation

Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.

Distributions

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

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

Recent Accounting Pronouncements

In August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund will adopt this accounting guidance effective January 1, 2020. The adoption of this accounting guidance is not expected to have a material impact on the Fund’s financial statements.

In June 2016, the FASB issued accounting guidance on measurement of credit losses, which introduces, among other things, a new expected loss impairment model that applies to most financial assets measured at amortized cost and certain other instruments including trade and other receivables and other financial assets. Under the new accounting guidance, entities are required to estimate expected credit loss over the life of financial assets and record an allowance against the asset’s amortized cost basis to present the financial asset at the amount expected to be collected. The estimate of expected credit losses will require entities to incorporate considerations of historical information, current information and reasonable and supportable forecasts. The accounting guidance and the most recent update issued in February 2020 are effective for the Fund in the first quarter of 2023 with early adoption permitted. The Fund early adopted this accounting guidance and related updates on January 1, 2020 and the adoption did not have a material impact on the Fund’s financial statements.

In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance was effective for the Fund beginning January 1, 2019. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.

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Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Information About Oil And Gas Producing Activities [Abstract]
Net change in sales and transfer prices and in production costs related to future production	$ (3,113)	$ 4,466
Sales and transfers of oil and gas produced during the period	(3,132)	(4,376)
Net change due to puchases and sales of minerals in place		(787)
Changes in estimated future development costs	26	395
Net change due to revisions in quantities estimates	1,102	7,686
Accretion of discount	1,237	573
Other	(552)	(1,321)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$ (4,432)	$ 6,636

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Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Information About Oil And Gas Producing Activities [Abstract]
Proved properties	$ 20,109	$ 20,663
Accumulated depletion and amortization	(11,302)	(9,405)
Total oil and gas properties, net	$ 8,807	$ 11,258

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BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 1,566	$ 2,124
Production receivable	391	338
Due from affiliate (Note 3)	13	50
Other current assets	37	48
Total current assets	2,007	2,560
Salvage fund	1,871	1,710
Oil and gas properties:
Proved properties	20,109	20,663
Less: accumulated depletion and amortization	(11,302)	(9,405)
Total oil and gas properties, net	8,807	11,258
Total assets	12,685	15,528
Current liabilities:
Due to operators	264	618
Accrued expenses	45	43
Current portion of long-term borrowings	898	945
Other current liabilities	164
Total current liabilities	1,371	1,606
Long-term borrowings	988	2,256
Asset retirement obligations	1,500	1,446
Total liabilities	3,859	5,308
Commitments and contingencies (Note 5)
Members' capital:
Distributions	(5,407)	(5,129)
Retained earnings	6,424	6,054
Manager's total	1,017	925
Capital contributions (250 shares authorized; 207.7026 issued and outstanding)	41,143	41,143
Syndication costs	(4,804)	(4,804)
Distributions	(37,404)	(35,829)
Retained earnings	8,874	8,784
Shareholders' total	7,809	9,294
Accumulated other comprehensive income		1
Total members' capital	8,826	10,220
Total liabilities and members' capital	$ 12,685	$ 15,528

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STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net income	$ 460	$ 2,384
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization	1,873	3,199
Gain on sale of oil and gas properties		(865)
Accretion expense	22	25
Gain on debt extinguishment		(1,313)
Amortization of debt discounts	4	1
Changes in assets and liabilities:
(Increase) decrease in production receivable	(53)	144
Decrease (increase) in due from affiliate	37	(50)
Decrease in other current assets	11	4
Increase in due to operators	151
Increase (decrease) in accrued expenses	2	(2)
Increase (decrease) in other current liabilities	164	(40)
Settlement of asset retirement obligations		(13)
Net cash provided by operating activities	2,671	3,474
Cash flows from investing activities
Capital expenditures for oil and gas properties	(355)	(2,211)
Reimbursement from operator for capital expenditures	460
Proceeds from sale of oil and gas properties		3,065
Increase in salvage fund	(162)	(165)
Net cash (used in) provided by investing activities	(57)	689
Cash flows from financing activities
Repayments of long-term borrowings	(1,319)	(3,989)
Distributions	(1,853)	(473)
Net cash used in financing activities	(3,172)	(4,462)
Net decrease in cash and cash equivalents	(558)	(299)
Cash and cash equivalents, beginning of year	2,124	2,423
Cash and cash equivalents, end of year	1,566	2,124
Supplemental disclosure of cash flow information
Cash paid for interest	234	468
Supplemental disclosure of non-cash investing activities
Due to operators for accrued capital expenditures for oil and gas properties	$ 4	$ 509

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Information about Oil and Gas Producing Activities (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Information About Oil And Gas Producing Activities [Abstract]
Future cash inflows	$ 15,118	$ 20,066
Future production costs	(3,211)	(2,627)
Future development costs	(2,605)	(2,631)
Future net cash flows	9,302	14,808
10% annual discount for estimated timing of cash flows	(1,365)	(2,439)
Standardized measure of discounted future net cash flows	$ 7,937	$ 12,369

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Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitments for the drilling and development of investment properties	$ 2,600
Commitments for asset retirement obligations included in estimated capital commitments	1,900
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months

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Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Available-For-Sale Securities

			Gross
	Amortized		Unrealized		Fair
	Cost		Gains		Value
	(in thousands)
Government National Mortgage Association security (GNMA July 2041)
December 31, 2018	$	36	$	1	$	37

Schedule of Changes in Asset Retirement Obligations

	December 31,
	2019		2018
	(in thousands)
Balance, beginning of year	$	1,446	$	1,401
Liabilities incurred		-		2
Liabilities settled/relieved		-		(54	)
Accretion expense		22		25
Revision of estimates		32		72
Balance, end of year	$	1,500	$	1,446

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Credit Agreement - Beta Project Financing

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Credit Agreement - Beta Project Financing

4. Credit Agreement – Beta Project Financing

As of December 31, 2019 and 2018, the Fund had outstanding borrowings of $1.9 million and $3.2 million, respectively, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”). As of December 31, 2019, the estimated fair value of the debt was $1.9 million.

Borrowings under the Credit Agreement bear interest at 8.75% compounded monthly. Principal and interest payments are based on the fixed percentage of the Fund’s Net Revenue, as defined in the Credit Agreement. Beginning on April 1, 2019 and each April 1^st thereafter, the Fund’s fixed percentage is the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually beginning April 1, 2019 and each April 1^st thereafter, and is based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineer’s proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan of December 31, 2022. As of April 1, 2019, the Fund’s fixed percentage was determined to be 30%. The loan may be prepaid by the Fund without premium or penalty. Pursuant to the Credit Agreement, the Fund also agreed to convey a fixed percentage of 10.81% overriding royalty interest in its working interest in the Beta Project to the lenders, which will become payable to the lenders on January 1, 2023.

As of December 31, 2019 and 2018, the unamortized debt discounts related to the loan of $11 thousand and $15 thousand, respectively, were presented as a reduction of “Long-term borrowings” on the Fund’s balance sheets. Amortization expense during the years ended December 31, 2019 and 2018 of $4 thousand and $1 thousand, respectively, was included on the Fund’s statements of operations within “Interest expense, net”. As of December 31, 2019 and 2018, there were no accrued interest costs outstanding. Interest costs incurred during the years ended December 31, 2019 and 2018 of $0.2 million and $0.5 million, respectively, were included on the Fund’s statements of operations within “Interest expense, net”.

As of December 31, 2019, the estimated principal repayments of debt are as follows: $0.9 million in 2020 and $1.0 million in 2021. The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2019 and 2018.

During third quarter 2018, the Fund determined that the terms of the fourth amendment to the Credit Agreement dated August 10, 2018 met the conditions of debt extinguishment pursuant to Accounting Standard Codification 470-50 Debt: Modification and Extinguishments guidance in a non-troubled debt restructuring. As a result, the Fund recorded a gain on debt extinguishment of $1.3 million, which was recorded within “Other income (loss)” in its statements of operations. The gain on debt extinguishment primarily represents non-cash gains associated with the change in the fair value of ORRI conveyed to the lenders totaling $1.3 million and the difference between the fair value of the new debt and the carrying amount of the old debt totaling $16 thousand.

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Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Balance, beginning of year	$ 1,446	$ 1,401
Liabilities incurred		2
Liabilities settled/relieved		(54)
Accretion expense	22	25
Revision of estimates	32	72
Balance, end of year	$ 1,500	$ 1,446