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, 2022

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. o

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). 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 February 27, 2023, there were 207.7026 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY A-1 FUND, LLC
2022 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	[RESERVED]	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	17
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	17
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	18
	ITEM 9A	CONTROLS AND PROCEDURES	18
	ITEM 9B	OTHER INFORMATION	18
	ITEM 9C	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	18
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 ACCOUNTANT FEES AND SERVICES	21
PART IV
	ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	22
		SIGNATURES	23

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. Such forward-looking statements 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 the impact on the Fund’s business and operations of any future widespread health emergencies or public health crises such as pandemics and epidemics, 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, the military conflict between Russia and Ukraine and the global response to such conflict, 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. Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders rely on the Manager to continue to manage the projects prudently, efficiently and fairly. 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, 2022 and 2021 were $0.3 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, 2022 and 2021 were $0.7 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 and 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 (“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 and 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 five 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. 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.

Concentration of Production and Revenues

A significant portion of the Fund’s revenues and cash flows are generated from the production and sale of oil and natural gas from the Beta Project. Because of this concentration, any significant production problems and curtailment, interruption in the availability of gathering, processing, or transportation infrastructure and services, impacts of adverse weather or inaccuracies in reserves estimates could have a material adverse impact on the Fund’s cash flows and expected operating results.

Project Information

The Fund’s Beta Project is 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 fixed percentage overriding royalty interests (“ORRI”) of 10.81% in its net revenue interest in the Beta Project’s oil and natural gas production, which was conveyed on January 1, 2023 and is payable to the former lender pursuant to the Fund’s credit agreement applicable to the project.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deepwater 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 one project, the Beta Project, which is eligible for royalty relief under the Deepwater Royalty Relief Act. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $44.68 per barrel and $58.01 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 $5.58 per mmbtu and $9.67 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, 2022. 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		7		0.11

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, 2022. 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
	23,033		378		364		6

Information regarding the Fund’s Beta Project, which is 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, 2022		Budget		Status
		(in thousands)
Beta Project	1.64%	$	16,478	$	18,733	The Beta Project, a seven-well project, commenced production from its first two wells in 2016. Additional wells commenced production in 2017, 2018 and 2019. During 2022, the project experienced shut-in from late-March 2022 to early-June 2022 for recompletion work. During 2021, the project experienced shut-in from May 2021 to late-September 2021 for recompletion work. The project also experienced storm shut-ins during third quarter of 2021 as a result of Hurricane Ida, which passed directly through the corridor where the project is located. The Fund expects to spend $1.1 million for additional development costs and $1.2 million for asset retirement obligations.

4

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 Beta Project is 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.

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 Beta Project to produce year-round, the project is 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 2022.

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 Beta Project is operated by Walter Oil & Gas Corporation.

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.

5

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, 2022, the Fund had $2.0 million invested in a salvage fund. On a monthly basis, the Fund contributes to the salvage fund a portion of its operating income to fund its asset retirement obligations as necessary. 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.

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.

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 regulation. The Fund owns the Beta Project that is 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.

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. On September 12, 2022, BSEE announced proposed revisions to provisions of the 2019 Well Control Rule to clarify blowout preventer system requirements and to modify specific blowout prevented equipment capability requirements. On September 14, 2022, the proposed rule was published in the Federal Register with a 60-day public comment period that closed on November 14, 2022. 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. On December 4, 2020, BOEM published a Record of Decision (“ROD”) for the final programmatic environmental impact statement for geological and geophysical survey activities in the Gulf of Mexico and adjacent state waters. The ROD provides for additional mitigation measures for application for future BOEM issued permits or authorizations toward further minimizing impacts of such geological and geophysical survey activities on marine resources. 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 18, 2022, 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. 

6

BOEM Supplemental Financial Assurance Requirements

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 natural 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 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 October 16, 2020, BOEM and BSEE published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with the Lessees’ obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. To date, the BOEM is not currently implementing NTL 2016-N01 and its status is uncertain, and BOEM has indicated that it is reviewing the proposed rule.

Notwithstanding the uncertain status of NTL 2016-N01, BOEM had continued under existing law to review supplemental financial assurance requirements relative to sole liability properties (i.e., properties in which only one company is liable for decommissioning).  However, on August 18, 2021, the BOEM issued a Note to Stakeholders in which the BOEM stated that it was expanding its financial assurance efforts beyond sole liability projects to include “supplemental financial assurance of certain high-risk, non-sole liability properties” (those properties with more than one company potentially liable for decommissioning costs). The BOEM identified (i) inactive properties, (ii) those with less than five years of production left, and (iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which supplemental financial assurance may be required.   The BOEM may require the Fund to fully secure all of its potential abandonment liabilities, which potentially could increase costs to the Fund. The Fund is not able to evaluate the impact of the proposed new rule on its operations or financial condition until a final rule is issued or some other definitive action is taken by the Interior or BOEM.

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, among other things, 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 impacts 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, or impacts that may be attributable to, the Fund’s Beta Project.

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 that occurred in the 1980s, including the Exxon Valdez spill. 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, with 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 (“Army”) proposed a revised definition of “waters of the United States” (“WOTUS”), 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 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 2020 Navigable Waters Protection Rule (“NWPR”) was then promulgated, with a replacement definition of WOTUS, and went into effect on June 22, 2020. A recent executive order revoked a prior executive order related to WOTUS and directed agencies to review certain actions, including the NWPR. On June 9, 2021, the Department of the Army and EPA announced their intent to initiate a new rulemaking process that would both restore a pre-2015 Clean Water Rule and develop a new rule to establish a new WOTUS definition, and then sought feedback from stakeholders. On September 3, 2021, following a court order vacating the NWPR, the Department of the Army and EPA announced that they had halted implementation of the NWPR and would interpret WOTUS consistent with the pre-2015 regulatory regime. On November 18, 2021, the EPA and the Department of the Army announced the signing of a proposed rule to revise the definition of WOTUS. On December 7, 2021, the proposed rule was published in the Federal Register with a 60-day public comment period that closed on February 7, 2022. On December 30, 2022, the EPA and the Department the Army announced a final rule establishing a revised definition of WOTUS that restores the pre-2015 regulatory regime. The new WOTUS definition will become effective 60 days after the final rule is published in the Federal Register. The definition of WOTUS is central to the pending U.S. Supreme Court decision in Sackett v. EPA, S.Ct. No. 21-454. The question presented in Sackett v. EPA is whether the proper test for determining if wetlands fall within the definition of WOTUS was expressed by the plurality in Rapanos v. United States, 547 U.S. 715 (2006). Oral arguments in Sackett v. EPA were held before the U.S. Supreme Court on October 3, 2022. 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.

8

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. OCSLA provides the Secretary of the Interior, through BOEM, with the statutory authority to regulate air quality over the Central and Western Gulf of Mexico. On June 5, 2020, BOEM published the Offshore Air Quality Rule, which revised the air quality regulations applicable to activities that BOEM authorizes on the OCS in the Western Gulf of Mexico. The Offshore Air Quality Rule, effective on July 6, 2020, brings the air quality standards that lessees and operators must meet in order to operate in the Western Gulf of Mexico into compliance with the current National Ambient Air Quality Standards and benchmarks set forth by the EPA under the Clean Air Act. 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 2020 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.

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, as well as litigation developments including matters before the U.S. Supreme Court in the 2021-2022 term, 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. Additionally, certain of the Fund’s operations (or actions relating to same) may be subject to the National Environmental Policy Act (“NEPA”), which requires in general that federal agencies assess the environmental effects of proposed federal actions, typically in the context of projects requiring a federal permit or authorization. Development of oil and gas pipelines are among the types of activities that could trigger NEPA and require such review. On July 16, 2020, the Council on Environmental Quality (“CEQ”) published a final rule to amend NEPA regulations to, among other things, clarify when NEPA applies, amend the definition of “effect” in the agency review, streamline the NEPA review, and provide additional flexibility for public involvement. Subsequently, in 2021, the CEQ withdrew the 2020 rule and is now engaged in a comprehensive review of the 2020 rule. The CEQ issued an Interim Final Rule on June 29, 2021, which extended the deadline by two years (to September 14, 2023) for federal agencies to develop or update their NEPA implementing procedures to conform to the CEQ regulations. As part of the CEQ’s two-phased approach to its review of the 2020 rule, on April 20, 2022, the CEQ published its final rule in the Federal Register for the Phase I rulemaking to amend a certain provision of the NEPA regulations, which, restored provisions that were in effect before the 2020 modification of the rule. This Phase I rule became effective on May 20, 2022. 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 the relevant requirements of 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 (including litigation developments relating to same) 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.

9

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 SEC reporting requirements.

Under the Fund’s 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. The Fund is not currently, and has not been during 2022, or at any time since 2012, a party to any derivative instruments or hedging programs.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.  PROPERTIES

The information regarding the Fund’s Beta Project 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

During the years ended December 31, 2022 and 2021, the Fund had no drilling activity for exploratory and developmental wells.

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, a Master of Business Administration, and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With thirty-five 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, 2022 and 2021 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, 2022, the Fund had proved undeveloped reserves related to the Beta Project totaling 41 thousand barrels of oil, 3 thousand barrels of natural gas liquid (“NGL”) and 17 thousand mcf of natural gas. As of December 31, 2021, the Fund had proved undeveloped reserves related to the Beta Project totaling 45 thousand barrels of oil, 4 thousand barrels of NGL and 19 thousand mcf of natural gas. The Beta Project was determined to be a discovery in 2012 and commenced production in 2016. 

The proved undeveloped reserves relating to the Beta Project, which were initially assigned at the end of the year 2021, are associated with planned well recompletions. During the year ended December 31, 2022, the Fund incurred costs to advance the development of its proved undeveloped reserves of $0.4 million, related to the Beta Project. As a result, proved undeveloped reserves of 30 thousand barrels of oil, 2 thousand barrels of NGL and 12 thousand mcf of natural gas were converted to proved developed producing reserves during 2022. The Fund expects additional recompletion operations to be completed in 2027 and 2028 related to the Beta Project.

Information regarding estimated future development costs relating to the Beta Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties,” is incorporated herein by reference. Estimated future development costs include capital spending on planned well recompletions. 

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, 2022 and 2021 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, 2022, 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, 2023, there were 662 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 amounts of future capital required for the costs associated with the well recompletions for the Beta Project, as budgeted, as well as the funding of estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices. 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, 2022 and 2021, the Fund paid distributions totaling $4.8 million and $0.9 million, respectively.

ITEM 6. [RESERVED]

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 invested and 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 Fund’s Beta Project.

Market Conditions

The oil and gas market, and the global economy in general, is subject to sources of uncertainty relating to: (i) further escalation in the Russia-Ukraine conflict, which could result in a major oil supply disruption; (ii) prolonged high inflationary environment, which could result in a deep global recession; and (iii) the refilling of strategic petroleum reserves by the U.S. and other nations, which could add to crude demand and potentially push oil prices higher. While the current outlook for oil and natural gas commodity prices is favorable, different outcomes of these issues would have different impacts on global economic growth and the performance of financial markets going into 2023 and the Fund, its operators and other working interest partners’ financial performance results may be materially adversely affected, which could affect the Fund’s liquidity and expected operating results. However, because the Fund owns the Beta Project with no debt and the project is a long-lived asset that is expected to produce over many years with relatively low operating costs, the Fund believes that it is positioned to weather this period of uncertainty and volatility in the global oil and gas market.

Commodity Price Changes

Changes in oil and natural gas commodity prices may significantly affect liquidity and expected operating results. Significant 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 and higher depletion rates.

12

Oil and natural gas commodity prices have been subject to significant volatility most recently due to the issues impacting market conditions described above. Although volatile, the overall trend for the crude oil market has been favorable during the year ended December 31, 2022, which positively impacted cash flow generated by the Beta Project. 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 the costs associated with the well recompletions for 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, 2022 and 2021 and the effect of such average prices on the Fund’s results of operations.

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:

· worldwide economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks, including war (such as the invasion of Ukraine by Russia), terrorism, political unrest, or health epidemics;

· weather conditions;

· economic conditions, including the impact of continued inflation and associated changes in monetary policy and demand for petroleum-based products;

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

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

· governmental regulations (inclusive of impacts of climate change), 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 have had or are reasonably likely to have a material impact on the Fund’s financial position or results of operations.

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 and estimated future cash flows of oil and gas properties used to test for impairment. 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 and net cash flows, 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 reserves 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 and net cash flows to change.

13

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.

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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and natural gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment.

Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 2022 and 2021, 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,
	2022		2021
	(in thousands)
Revenue
Oil and gas revenue	$	5,459	$	3,173
Other revenue		307		363
Total revenue		5,766		3,536
Expenses
Depletion and amortization		2,065		1,959
Operating expenses		544		386
Management fees to affiliate		291		294
General and administrative expenses		147		142
Total expenses		3,047		2,781
Income from operations		2,719		755
Interest income (expense)		7		(85	)
Net income		2,726		670

14

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, 2022 and 2021. NGL sales are included within gas sales.

	Year ended December 31,
	2022		2021
Number of wells producing		7		7
Total number of production days		2,463		2,232
Oil sales (in thousands of barrels)		54		44
Average oil price per barrel	$	91	$	66
Gas sales (in thousands of mcfs)		73		55
Average gas price per mcf	$	6.68	$	4.56

The production related increases noted in the table above were attributable to the Beta Project, which experienced significant periods of shut-ins during 2021 compared to 2022 due to well recompletion during May 2021 to September 2021 and storm-related safety shut-in during third quarter 2021. In addition, the Beta Project experienced increases in production rates during 2022 compared to 2021 from two of the project’s wells, which were recompleted and have been producing from new reservoir sands.

See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

Oil and Gas Revenue. Oil and gas revenue during the year ended December 31, 2022 was $5.5 million, an increase of $2.3 million from the year ended December 31, 2021. The increase was attributable to increased oil and gas prices totaling $1.5 million coupled with increased sales volume totaling $0.8 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 affiliated entities and other third parties. See Note 2 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, 2022 was $2.1 million, an increase of $0.1 million from the year ended December 31, 2021. The increase was attributable to an increase in production volumes totaling $0.6 million and adjustments to the asset retirement obligations related to fully depleted properties totaling $0.3 million, partially offset by a decrease in the average depletion rate totaling $0.8 million. The decrease in the average depletion rate was primarily attributable to the changes in reserves estimates provided annually by the Fund’s independent petroleum engineers.

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,
	2022		2021
	(in thousands)
Lease operating expense	$	276	$	171
Transportation and processing expense		170		131
Insurance expense		56		69
Accretion expense		27		27
Workover expense and other		15		(12	)
	$	544	$	386

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. Accretion expense relates to the asset retirement obligations established for the Fund’s oil and gas properties. Workover expense represents costs to restore or stimulate production of existing reserves.

15

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, were $0.5 million ($7.54 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2022, compared to $0.4 million ($6.97 per BOE) during the year ended December 31, 2021. Production costs and production costs per BOE were relatively consistent during the year ended December 31, 2022 compared to the year ended December 31, 2021.

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. All or a portion of such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term commitments.

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

Interest Income (Expense). During the year ended December 31, 2022, interest income (expense) was comprised of interest income earned on cash and cash equivalents and salvage fund. During the year ended December 31, 2021, interest income (expense) was comprised of interest expense and amortization of debt discounts related to the Fund’s long-term borrowings.  The Fund fully repaid its loan related to the Beta Project as of December 31, 2021.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 2022 were $4.8 million, primarily related to revenue received of $5.8 million, partially offset by operating expenses of $0.5 million, management fees of $0.3 million and general and administrative expenses of $0.1 million.

Cash flows provided by operating activities during the year ended December 31, 2021 were $2.4 million, related to revenue received of $3.5 million, partially offset by operating expenses of $0.3 million, the settlement of asset retirement obligations of $0.3 million, management fees of $0.3 million, general and administrative expenses of $0.1 million and interest payments of $0.1 million.

Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 2022 were $0.5 million, primarily related to capital expenditures for oil and gas properties of $0.4 million and investments in salvage fund of $0.2 million.

Cash flows used in investing activities during the year ended December 31, 2021 were $0.4 million, related to capital expenditures for oil and gas properties of $0.6 million and investments in salvage fund of $0.2 million, partially offset by proceeds from the salvage fund of $0.3 million.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 2022 were $4.8 million, related to manager and shareholder distributions.

Cash flows used in financing activities during the year ended December 31, 2021 were $2.3 million, related to the repayments of long-term borrowings of $1.4 million and manager and shareholder distributions of $0.9 million.

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.

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 invested and 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. Such investment activities, which include estimated capital spending on planned well recompletions for the Beta Project, are expected to be funded from cash flows from operations and existing cash-on-hand and not from equity, debt or off-balance sheet financing arrangements.

16

See Item 1. “Business” of this Annual Report under the heading “Properties” and “Liquidity Needs” below for additional information.

Liquidity Needs

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

As of December 31, 2022, the Fund’s estimated capital commitments related to its oil and gas properties were $2.9 million (which include asset retirement obligations for the Fund’s projects of $1.8 million), of which $40 thousand is expected to be spent during the year ending December 31, 2023. Future results of operations and cash flows are dependent on the revenues from production and sale of oil and gas from the Beta Project. In addition, cash flow from operations may be impacted by fluctuations in oil and natural gas commodity prices. Based upon its current cash position, salvage fund and its current reserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations. Reserves 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. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive all or a portion of the management fee at its own discretion.

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 amounts of future capital required for the costs associated with the well recompletions for the Beta Project, as budgeted, as well as the funding of estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices.

Overriding Royalty Interest

Effective January 1, 2023, the fixed percentage overriding royalty interest of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project.

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, 2022 and 2021, other than those discussed in “Capital Expenditures” 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.

17

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, 2022. 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, 2022.  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, 2022, the Fund’s internal control over financial reporting is effective.

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, 2022 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

18

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, 2022 are as follows:

Name, Age and Position with Registrant

Robert E. Swanson, 75

Chief Executive Officer

Kenneth W. Lang, 68

President

Kathleen P. McSherry, 57

Executive Vice President, Chief Financial Officer and Assistant Secretary

Daniel V. Gulino, 62

Senior Vice President - Legal 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 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 the Investment Committee of Ridgewood Private Equity Partners, LLC, an affiliate 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 of Ridgewood Energy since June 2009 and is a member of the Investment Committee. 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.

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

Daniel V. Gulino is Senior Vice President - Legal and Secretary for Ridgewood Energy and has served in that capacity for Ridgewood Energy since 2003. 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.

19

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: Legal Department.

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, 2023. 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, 2022 and 2021 were $0.3 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, 2022 and 2021 were $0.7 million and $0.1 million, respectively.

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. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, by 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). On September 23, 2020, a third-party working interest owner of the Claiborne Project executed a consent letter to assign the rights to the services under the PHA to Ridgewood Rattlesnake, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund III, L.P. (“Institutional Fund III”). On May 12, 2022, a third-party working interest owner executed an assignment and bill of sale agreement to assign the rights to the services under the PHA to Ridgewood Institutional IV Prospective Leases, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund IV, L.P. (“Institutional Fund IV”). Institutional Fund II, Institutional Fund III and Institutional Fund IV are entities that are managed by the Fund’s Manager. 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 2 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.

20

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 ACCOUNTANT FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 2022 and 2021.

	Year ended December 31,
	2022		2021
	(in thousands)
Audit fees (1)	$	82	$	85

⁽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	Incorporated by reference to the Fund’s Form 10-K filed on March 3, 2020
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, Chief Financial Officer and Assistant Secretary 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, Chief Financial Officer and Assistant Secretary of the Fund	Filed herewith
99.1	Report of Netherland, Sewell & Associates, Inc.	Filed herewith
101.INS	Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document	Filed herewith
101.SCH	Inline XBRL Taxonomy Extension Schema	Filed herewith
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase	Filed herewith
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase	Filed herewith
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase	Filed herewith
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)	Filed herewith

22

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:  February 27, 2023	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
		February 27, 2023
/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)
Robert E. Swanson
/s/ KATHLEEN P. MCSHERRY	Executive Vice President, Chief Financial Officer and Assistant Secretary (Principal Financial and Accounting Officer)	February 27, 2023
Kathleen P. McSherry
RIDGEWOOD ENERGY CORPORATION
BY:  /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	February 27, 2023
Robert E. Swanson

23

INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)	F-2
Balance Sheets as of December 31, 2022 and 2021	F-5
Statements of Operations for the years ended December 31, 2022 and 2021	F-6
Statements of Changes in Members' Capital for the years ended December 31, 2022 and 2021	F-7
Statements of Cash Flows for the years ended December 31, 2022 and 2021	F-8
Notes to Financial Statements	F-9
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-16

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the 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, 2022 and 2021, the related statements of operations, changes in members' capital, and cash flows, for each of the two years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2022, 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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Oil and Gas Properties, Depletion and Amortization and Impairment of Long-Lived Assets - Refer to Note 1 to the financial statements

Critical Audit Matter Description

As described in Note 1 to the financial statements, oil and gas properties are accounted for using the successful efforts method. 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 platforms and associated asset retirement costs. Also, 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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value.

F-2

Estimates of proved reserves are key components of the Fund’s most significant estimates involving its rate for recording depletion and amortization and estimated future cash flows of oil and gas properties used to test for impairment. 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. 

The Fund’s oil and gas properties, net balance was $3.7 million as of December 31, 2022 and depletion and amortization expense recognized was $2.1 million for the period ended December 31, 2022. No impairment was recognized during 2022.

We identified the impact of the oil and natural gas reserve quantities on the oil and gas properties and depletion and amortization financial statement line items and the evaluation of impairment of long-lived assets as a critical audit matter due to the significant judgments made by the Fund. The significant judgments made by the Fund include the use of specialists to develop and evaluate the Fund’s oil and natural gas reserve quantities, future cash flows, reserve risk weightings, future development costs, and future oil and natural gas commodity prices. Auditing these significant judgments required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the Fund’s estimates and assumptions related to oil and natural gas reserve quantities included the following, among others:

· We evaluated the reasonableness of the Fund’s oil and natural gas reserve quantities by performing the following procedures:

o Comparing the Fund’s oil and natural gas reserve quantities to historical production volumes.

o Evaluating the reasonableness of the methodology used and the production volume decline curve.

o Understanding the experience, qualifications and objectivity of management’s expert, an independent petroleum engineering firm.

o Comparing forecasts of proved undeveloped oil and natural gas reserves to historical conversions of proved undeveloped oil and natural gas reserves and communication from third-party well operators.

· We evaluated management’s assessed reserve risk weighting associated with the development of proved, probable and possible oil and natural gas reserve quantities by comparing the assessed risk to industry surveys. 

· We evaluated the reasonableness of future development costs by comparing such costs to the approval for expenditures, historical well cost data and communication from third-party well operators.

F-3

· We evaluated, with the assistance of our fair value specialists, the reasonableness of future oil and natural gas commodity prices by performing the following procedures:

o Understanding the methodology utilized by management for development of the future oil and natural gas commodity prices.

o Comparing the future oil and natural gas commodity prices to an independently determined range of prices.

o Comparing management’s future oil and natural gas commodity prices to published forward pricing indices and third-party industry sources. 

· We evaluated the future oil and natural gas commodity prices by comparing future oil and natural gas commodity price differentials to historical realized price differentials. 

/s/ Deloitte & Touche LLP

Morristown, New Jersey  

February 27, 2023

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

F-4

RIDGEWOOD ENERGY A-1 FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2022			2021
Assets
Current assets:
Cash and cash equivalents	$	264		$	791
Salvage fund		40			46
Production receivable		365			329
Due from affiliate (Note 2)		10			19
Other current assets		32			36
Total current assets		711			1,221
Salvage fund		1,986			1,830
Oil and gas properties:
Proved properties		17,927			17,439
Less:  accumulated depletion and amortization		(14,181	)		(12,116	)
Total oil and gas properties, net		3,746			5,323
Total assets	$	6,443		$	8,374
Liabilities and Members' Capital
Current liabilities:
Due to operators	$	24		$	27
Accrued expenses		119			66
Asset retirement obligations		40			46
Total current liabilities		183			139
Asset retirement obligations		1,035			888
Total liabilities		1,218			1,027
Commitments and contingencies (Note 3)
Members' capital:
Manager:
Distributions		(6,317	)		(5,589	)
Retained earnings		7,651			6,950
Manager's total		1,334			1,361
Shareholders:
Capital contributions (250 shares authorized; 207.7026 issued and outstanding)		41,143			41,143
Syndication costs		(4,804	)		(4,804	)
Distributions		(42,556	)		(38,436	)
Retained earnings		10,108			8,083
Shareholders' total		3,891			5,986
Total members' capital		5,225			7,347
Total liabilities and members' capital	$	6,443		$	8,374

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

F-5

RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2022		2021
Revenue
Oil and gas revenue	$	5,459	$	3,173
Other revenue		307		363
Total revenue		5,766		3,536
Expenses
Depletion and amortization		2,065		1,959
Operating expenses		544		386
Management fees to affiliate (Note 2)		291		294
General and administrative expenses		147		142
Total expenses		3,047		2,781
Income from operations		2,719		755
Interest income (expense)		7		(85	)
Net income	$	2,726	$	670
Manager Interest
Net income	$	701	$	390
Shareholder Interest
Net income	$	2,025	$	280
Net income per share	$	9,753	$	1,347

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

F-6

RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2020		207.7026	$	1,099		$	6,435		$	7,534
Distributions		-		(128	)		(729	)		(857	)
Net income		-		390			280			670
Balances, December 31, 2021		207.7026	$	1,361		$	5,986		$	7,347
Distributions		-		(728	)		(4,120	)		(4,848	)
Net income		-		701			2,025			2,726
Balances, December 31, 2022		207.7026	$	1,334		$	3,891		$	5,225

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

F-7

RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2022			2021
Cash flows from operating activities
Net income	$	2,726		$	670
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization		2,065			1,959
Accretion expense		27			27
Amortization of debt discounts		-			7
Changes in assets and liabilities:
Increase in production receivable		(36	)		(108	)
Decrease in due from affiliate		9			73
Decrease in other current assets		4			11
Increase in due to operators		3			5
Increase in accrued expenses		53			15
Settlement of asset retirement obligations		(6	)		(305	)
Net cash provided by operating activities		4,845			2,354
Cash flows from investing activities
Capital expenditures for oil and gas properties		(374	)		(579	)
Proceeds from salvage fund		6			305
Increase in salvage fund		(156	)		(155	)
Net cash used in investing activities		(524	)		(429	)
Cash flows from financing activities
Repayments of long-term borrowings		-			(1,427	)
Distributions		(4,848	)		(857	)
Net cash used in financing activities		(4,848	)		(2,284	)
Net decrease in cash and cash equivalents		(527	)		(359	)
Cash and cash equivalents, beginning of year		791			1,150
Cash and cash equivalents, end of year	$	264		$	791
Supplemental disclosure of cash flow information
Cash paid for interest	$	-		$	78
Supplemental disclosure of non-cash investing activities
Due to operators for accrued capital expenditures for oil and gas properties	$	-		$	6

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

F-8

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 2 and 3.

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, salvage fund, production receivable, due from affiliate, other current assets, due to operators and accrued expenses. The carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. 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, 2022, 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, 2022, 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.

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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.

Accrued Expenses

Accrued expenses consist of the following:

	December 31,
	2022		2021
	(in thousands)
Accrued accounting and legal fees	$	63	$	66
Accrued royalty		56		-
	$	119	$	66

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, 2022 and 2021:

	December 31,
	2022			2021
	(in thousands)
Balance, beginning of year	$	934		$	1,565
Liabilities settled		(6	)		(305	)
Accretion expense		27			27
Revision of estimates		120			(353	)
Balance, end of year	$	1,075		$	934

During the year ended December 31, 2021, the Fund recorded credits to depletion expense totaling $0.3 million, which related to adjustments to the asset retirement obligations for fully depleted properties.

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.

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Revenue Recognition

Oil and gas revenues from contracts with customers are recognized at the point when control of oil and natural gas is transferred to the customers in accordance with Accounting Standard Codification Topic 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 revenues. 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 natural 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. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the Fund’s balance sheets.

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Other Revenue

Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities 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 affiliated entities 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 affiliates 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. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to 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, 2022 and 2021, revenue recognized from performance obligations satisfied in previous periods was not significant.

Allowance for Credit Losses

The Fund is exposed to credit losses through the sale of oil and natural gas to customers. However, the Fund only sells to a small number of major oil and gas companies that have investment-grade credit ratings. Based on historical collection experience, current and future economic and market conditions and a review of the current status of customers' production receivables, the Fund has not recorded an expected loss allowance as there are no past due receivable balances or projected credit losses.

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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment.

There were no impairments of oil and gas properties during the years ended December 31, 2022 and 2021. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. In addition, significant declines in oil and natural gas commodity prices could reduce the quantities of reserves that are commercially recoverable, which could result in impairment. 

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 2019 through 2021 tax returns remain open for examination by tax authorities.

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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

The Fund has considered recent accounting pronouncements issued during the year ended December 31, 2022 and through the filing of this report, and the Fund has not identified new standards that it believes will have an impact on the Fund’s financial statements.

2. 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, however, the Manager is permitted to waive all or a portion of the management fee at its own discretion. Therefore, all or a portion of the management fee may be temporarily waived to accommodate the Fund’s short-term commitments. Management fees during each of the years ended December 31, 2022 and 2021 were $0.3 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, 2022 and 2021 were $0.7 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. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, by 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). On September 23, 2020, a third-party working interest owner of the Claiborne Project executed a consent letter to assign the rights to the services under the PHA to Ridgewood Rattlesnake, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund III, L.P. (“Institutional Fund III”). On May 12, 2022, a third-party working interest owner executed an assignment and bill of sale agreement to assign the rights to the services under the PHA to Ridgewood Institutional IV Prospective Leases, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund IV, L.P. (“Institutional Fund IV”). Institutional Fund II, Institutional Fund III and Institutional Fund IV are entities that are managed by the Fund’s Manager. 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.

F-13

During each of the years ended December 31, 2022 and 2021, the Fund earned $0.1 million, representing its proportionate share of the production handling fees earned from affiliates, which are included within “Other revenue” on the Fund’s statements of operations. As of December 31, 2022 and 2021, the Fund’s receivables of $10 thousand and $19 thousand, respectively, related to the Fund’s proportionate share of revenue from affiliates 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. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to the Fund.

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.

3. Commitments and Contingencies

Capital Commitments

As of December 31, 2022, the Fund’s estimated capital commitments related to its oil and gas properties were $2.9 million (which include asset retirement obligations for the Fund’s projects of $1.8 million), of which $40 thousand is expected to be spent during the year ending December 31, 2023. Future results of operations and cash flows are dependent on the revenues from production and sale of oil and natural gas from the Beta Project. Based upon its current cash position, salvage fund and its current reserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations. Reserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.

Overriding Royalty Interest (ORRI)

Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The ORRI will be recorded as a reduction to oil and gas revenue on the Fund’s statement of operations and as accrued royalty within “Accrued expenses” on the Fund’s balance sheet.

Impact from market conditions

The oil and gas market, and the global economy in general, is subject to sources of uncertainty relating to: (i) further escalation in the Russia-Ukraine conflict, which could result in a major oil supply disruption; (ii) a prolonged high inflationary environment, which could result in a deep global recession; and (iii) the refilling of strategic petroleum reserves by the U.S. and other nations, which could add to crude demand and potentially push oil prices higher. The impact of these matters on global financial and commodity markets and their corresponding effect on the Fund remains uncertain.

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, 2022 and 2021, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

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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 Supplemental Financial Assurance Requirements

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 natural 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-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 October 16, 2020, BOEM and the Bureau of Safety and Environmental Enforcement published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with the Lessees’ obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. To date, the BOEM is not currently implementing NTL 2016-N01 and its status is uncertain, and BOEM has indicated that it is reviewing the proposed rule.

Notwithstanding the uncertain status of NTL 2016-N01, BOEM had continued under existing law to review supplemental financial assurance requirements relative to sole liability properties (i.e., properties in which only one company is liable for decommissioning).  However, on August 18, 2021, the BOEM issued a Note to Stakeholders in which the BOEM stated that it was expanding its financial assurance efforts beyond sole liability projects to include “supplemental financial assurance of certain high-risk, non-sole liability properties” (those properties with more than one company potentially liable for decommissioning costs). The BOEM identified (i) inactive properties, (ii) those with less than five years of production left, and (iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which supplemental financial assurance may be required.   The BOEM may require the Fund to fully secure all of its potential abandonment liabilities, which potentially could increase costs to the Fund. The Fund is not able to evaluate the impact of the proposed new rule on its operations or financial condition until a final rule is issued or some other definitive action is taken by the Interior or BOEM.

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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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,
	2022			2021
	(in thousands)
Proved properties	$	17,927		$	17,439
Accumulated depletion and amortization		(14,181	)		(12,116	)
Oil and gas properties, net	$	3,746		$	5,323

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

	Year ended December 31,
	2022		2021
	(in thousands)
Development costs	$	488	$	245
	$	488	$	245

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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, 2022 and 2021. 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, 2022												December 31, 2021
	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		175.7			13.7			71.4			201.4			130.6			11.1			63.8			152.3
Revisions of previous estimates (b)		(0.5	)		3.3			26.0			7.0			89.2			7.3			34.6			102.4
Production		(54.4	)		(6.5	)		(34.7	)		(66.7	)		(44.1	)		(4.7	)		(27.0	)		(53.3	)
End of year		120.8			10.5			62.7			141.7			175.7			13.7			71.4			201.4
Proved developed reserves:
Beginning of year		131.1			10.1			52.5			150.1			130.6			11.1			63.8			152.3
End of year		79.6			7.7			46.1			95.0			131.1			10.1			52.5			150.1
Proved undeveloped reserves:
Beginning of year		44.6			3.6			18.9			51.3			-			-			-			-
End of year		41.2			2.8			16.6			46.7			44.6			3.6			18.9			51.3

(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) Effective January 1, 2023, the fixed percentage overriding royalty interest (“ORRI”) of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The reserves shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI.

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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,
	2022			2021
	(in thousands)
Future cash inflows	$	11,624		$	11,504
Future production costs		(2,616	)		(2,327	)
Future development costs		(2,864	)		(2,318	)
Future net cash flows		6,144			6,859
10% annual discount for estimated timing of cash flows		(765	)		(1,280	)
Standardized measure of discounted future estimated net cash flows	$	5,379		$	5,579

Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The future cash inflows or future revenue shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI.

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,
	2022			2021
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	3,509		$	3,971
Sales and transfers of oil and gas produced during the period		(4,957	)		(2,802	)
Changes in estimated future development costs		(546	)		175
Net change due to revisions in quantities estimates		394			3,797
Accretion of discount		558			58
Other		842			(204	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(200	)	$	4,995

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-18

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:	February 27, 2023
/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:	February 27, 2023
/s/	KATHLEEN P. MCSHERRY
Name:	Kathleen P. McSherry
Title:	Executive Vice President, Chief Financial Officer and Assistant Secretary
	(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, 2022, 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:	February 27, 2023	/s/	ROBERT E. SWANSON
		Name:	Robert E. Swanson
		Title:	Chief Executive Officer
			(Principal Executive Officer)
Dated:	February 27, 2023	/s/	KATHLEEN P. MCSHERRY
		Name:	Kathleen P. McSherry
		Title:	Executive Vice President, Chief Financial Officer and Assistant Secretary
			(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, 2023

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, 2022, 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. It is also our understanding that a portion of Ridgewood A-1 Fund's net revenue interest in each of the blocks that compose Beta Field was conveyed to a third party on January 1, 2023; the effects of this conveyance are not accounted for in the reserves and future revenue shown in this report. 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, 2022, to be:

	Net Reserves						Future Net Revenue(1) (M$)
	Oil		NGL		Gas				Present Worth
Category	(MBBL)		(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		79.6		7.7		46.1		4,072.7		4,229.9
Proved Undeveloped		41.2		2.8		16.6		2,071.1		1,149.2
Total Proved		120.8		10.5		62.7		6,143.7		5,379.1

Totals may not add because of rounding.

⁽¹⁾ Future net revenue is after deducting estimated abandonment costs.

The oil volumes shown include crude oil only. 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, 2022, there are no proved developed non-producing 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 beyond those tracts for which undeveloped reserves have been estimated.

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 2022. For oil and NGL volumes, the average Light Louisiana Sweet spot price of $96.27 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $6.357 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 $89.66 per barrel of oil, $32.64 per barrel of NGL, and $7.206 per MCF of gas

Operating costs used in this report are based on operating expense records of Ridgewood Energy Corporation (Ridgewood). These costs include 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, platform, 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. 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, 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. Zachary R. Long, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2007 and has over 2 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. Executive Chairman
	/s/ John R. Cliver		/s/ Zachary R. Long
By:		By:
	John R. Cliver, P.E. 107216		Zachary R. Long, P.G. 11792
	Vice President		Vice President
Date Signed:  February 14, 2023		Date Signed:  February 14, 2023

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:

• 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);

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

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

• 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

• 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

Cover - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 27, 2023
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2022
Current Fiscal Year End Date	--12-31
Entity File Number	000-53895
Entity Registrant Name	Ridgewood Energy A-1 Fund, LLC
Entity Central Index Key	0001457919
Entity Tax Identification Number	01-0921132
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	14 Philips Parkway
Entity Address, City or Town	Montvale
Entity Address, State or Province	NJ
Entity Address, Postal Zip Code	07645
City Area Code	800
Local Phone Number	942-5550
Title of 12(b) Security	None
Entity Well Known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float	$ 0
Entity Common Stock, Shares Outstanding		207.7026
ICFR Auditor Attestation Flag	false
Auditor Firm ID	34
Auditor Name	Deloitte & Touche LLP
Auditor Location	Morristown, New Jersey

XML

BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 264	$ 791
Salvage fund	40	46
Production receivable	365	329
Due from affiliate (Note 2)	10	19
Other current assets	32	36
Total current assets	711	1,221
Salvage fund	1,986	1,830
Oil and gas properties:
Proved properties	17,927	17,439
Less:  accumulated depletion and amortization	(14,181)	(12,116)
Total oil and gas properties, net	3,746	5,323
Total assets	6,443	8,374
Current liabilities:
Due to operators	24	27
Accrued expenses	119	66
Asset retirement obligations	40	46
Total current liabilities	183	139
Asset retirement obligations	1,035	888
Total liabilities	1,218	1,027
Members' capital:
Distributions	(6,317)	(5,589)
Retained earnings	7,651	6,950
Manager's total	1,334	1,361
Shareholders:
Capital contributions (250 shares authorized; 207.7026 issued and outstanding)	41,143	41,143
Syndication costs	(4,804)	(4,804)
Distributions	(42,556)	(38,436)
Retained earnings	10,108	8,083
Shareholders' total	3,891	5,986
Total members' capital	5,225	7,347
Total liabilities and members' capital	$ 6,443	$ 8,374

XML

BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Shares authorized	250	250
Shares issued	207.7026	207.7026
Shares outstanding	207.7026	207.7026

XML

STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenue
Oil and gas revenue	$ 5,459	$ 3,173
Other revenue	307	363
Total revenue	5,766	3,536
Expenses
Depletion and amortization	2,065	1,959
Operating expenses	544	386
Management fees to affiliate (Note 2)	291	294
General and administrative expenses	147	142
Total expenses	3,047	2,781
Income from operations	2,719	755
Interest income (expense)	7	(85)
Net income	2,726	670
Manager Interest
Net income	701	390
Shareholder Interest
Net income	$ 2,025	$ 280
Net income per share	$ 9,753	$ 1,347

XML

STATEMENTS OF CHANGES IN PARTNERS CAPITAL - USD ($) $ in Thousands	Shares of Llc Interest [Member]	Fund Manager [Member]	Fund Shareholders [Member]	Total
Beginning balance, value at Dec. 31, 2020		$ 1,099	$ 6,435	$ 7,534
Beginning balance (in shares) at Dec. 31, 2020	207.7026
Distributions		(128)	(729)	(857)
Net income		390	280	670
Ending balance, value at Dec. 31, 2021		1,361	5,986	$ 7,347
Balance at ending (in shares) at Dec. 31, 2021	207.7026			207.7026
Distributions		(728)	(4,120)	$ (4,848)
Net income		701	2,025	2,726
Ending balance, value at Dec. 31, 2022		$ 1,334	$ 3,891	$ 5,225
Balance at ending (in shares) at Dec. 31, 2022	207.7026			207.7026

XML

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities
Net income	$ 2,726	$ 670
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization	2,065	1,959
Accretion expense	27	27
Amortization of debt discounts		7
Changes in assets and liabilities:
Increase in production receivable	(36)	(108)
Decrease in due from affiliate	9	73
Decrease in other current assets	4	11
Increase in due to operators	3	5
Increase in accrued expenses	53	15
Settlement of asset retirement obligations	(6)	(305)
Net cash provided by operating activities	4,845	2,354
Cash flows from investing activities
Capital expenditures for oil and gas properties	(374)	(579)
Proceeds from salvage fund	6	305
Increase in salvage fund	(156)	(155)
Net cash used in investing activities	(524)	(429)
Cash flows from financing activities
Repayments of long-term borrowings		(1,427)
Distributions	(4,848)	(857)
Net cash used in financing activities	(4,848)	(2,284)
Net decrease in cash and cash equivalents	(527)	(359)
Cash and cash equivalents, beginning of year	791	1,150
Cash and cash equivalents, end of year	264	791
Supplemental disclosure of cash flow information
Cash paid for interest		78
Supplemental disclosure of non-cash investing activities
Due to operators for accrued capital expenditures for oil and gas properties		$ 6

XML

Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Organization and Summary of Significant Accounting Policies

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy A-1 Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of March 2, 2009 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Manager has direct and exclusive control over the management of the Fund’s operations. 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 2 and 3.

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, salvage fund, production receivable, due from affiliate, other current assets, due to operators and accrued expenses. The carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. 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, 2022, 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, 2022, 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.

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.

Accrued Expenses

Accrued expenses consist of the following:

	December 31,
	2022		2021
	(in thousands)
Accrued accounting and legal fees	$	63	$	66
Accrued royalty		56		-
	$	119	$	66

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, 2022 and 2021:

	December 31,
	2022			2021
	(in thousands)
Balance, beginning of year	$	934		$	1,565
Liabilities settled		(6	)		(305	)
Accretion expense		27			27
Revision of estimates		120			(353	)
Balance, end of year	$	1,075		$	934

During the year ended December 31, 2021, the Fund recorded credits to depletion expense totaling $0.3 million, which related to adjustments to the asset retirement obligations for fully depleted properties.

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

Oil and gas revenues from contracts with customers are recognized at the point when control of oil and natural gas is transferred to the customers in accordance with Accounting Standard Codification Topic 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 revenues. 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 natural 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. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the Fund’s balance sheets.

Other Revenue

Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities 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 affiliated entities 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 affiliates 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. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to 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, 2022 and 2021, revenue recognized from performance obligations satisfied in previous periods was not significant.

Allowance for Credit Losses

The Fund is exposed to credit losses through the sale of oil and natural gas to customers. However, the Fund only sells to a small number of major oil and gas companies that have investment-grade credit ratings. Based on historical collection experience, current and future economic and market conditions and a review of the current status of customers' production receivables, the Fund has not recorded an expected loss allowance as there are no past due receivable balances or projected credit losses.

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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment.

There were no impairments of oil and gas properties during the years ended December 31, 2022 and 2021. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. In addition, significant declines in oil and natural gas commodity prices could reduce the quantities of reserves that are commercially recoverable, which could result in impairment. 

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 2019 through 2021 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

The Fund has considered recent accounting pronouncements issued during the year ended December 31, 2022 and through the filing of this report, and the Fund has not identified new standards that it believes will have an impact on the Fund’s financial statements.

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Related Parties

12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Related Parties

2. 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, however, the Manager is permitted to waive all or a portion of the management fee at its own discretion. Therefore, all or a portion of the management fee may be temporarily waived to accommodate the Fund’s short-term commitments. Management fees during each of the years ended December 31, 2022 and 2021 were $0.3 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, 2022 and 2021 were $0.7 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. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, by 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). On September 23, 2020, a third-party working interest owner of the Claiborne Project executed a consent letter to assign the rights to the services under the PHA to Ridgewood Rattlesnake, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund III, L.P. (“Institutional Fund III”). On May 12, 2022, a third-party working interest owner executed an assignment and bill of sale agreement to assign the rights to the services under the PHA to Ridgewood Institutional IV Prospective Leases, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund IV, L.P. (“Institutional Fund IV”). Institutional Fund II, Institutional Fund III and Institutional Fund IV are entities that are managed by the Fund’s Manager. 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 each of the years ended December 31, 2022 and 2021, the Fund earned $0.1 million, representing its proportionate share of the production handling fees earned from affiliates, which are included within “Other revenue” on the Fund’s statements of operations. As of December 31, 2022 and 2021, the Fund’s receivables of $10 thousand and $19 thousand, respectively, related to the Fund’s proportionate share of revenue from affiliates 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. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to the Fund.

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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Commitments and Contingencies

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

3. Commitments and Contingencies

Capital Commitments

As of December 31, 2022, the Fund’s estimated capital commitments related to its oil and gas properties were $2.9 million (which include asset retirement obligations for the Fund’s projects of $1.8 million), of which $40 thousand is expected to be spent during the year ending December 31, 2023. Future results of operations and cash flows are dependent on the revenues from production and sale of oil and natural gas from the Beta Project. Based upon its current cash position, salvage fund and its current reserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations. Reserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.

Overriding Royalty Interest (ORRI)

Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The ORRI will be recorded as a reduction to oil and gas revenue on the Fund’s statement of operations and as accrued royalty within “Accrued expenses” on the Fund’s balance sheet.

Impact from market conditions

The oil and gas market, and the global economy in general, is subject to sources of uncertainty relating to: (i) further escalation in the Russia-Ukraine conflict, which could result in a major oil supply disruption; (ii) a prolonged high inflationary environment, which could result in a deep global recession; and (iii) the refilling of strategic petroleum reserves by the U.S. and other nations, which could add to crude demand and potentially push oil prices higher. The impact of these matters on global financial and commodity markets and their corresponding effect on the Fund remains uncertain.

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, 2022 and 2021, 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 Supplemental Financial Assurance Requirements

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 natural 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-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 October 16, 2020, BOEM and the Bureau of Safety and Environmental Enforcement published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with the Lessees’ obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. To date, the BOEM is not currently implementing NTL 2016-N01 and its status is uncertain, and BOEM has indicated that it is reviewing the proposed rule.

Notwithstanding the uncertain status of NTL 2016-N01, BOEM had continued under existing law to review supplemental financial assurance requirements relative to sole liability properties (i.e., properties in which only one company is liable for decommissioning).  However, on August 18, 2021, the BOEM issued a Note to Stakeholders in which the BOEM stated that it was expanding its financial assurance efforts beyond sole liability projects to include “supplemental financial assurance of certain high-risk, non-sole liability properties” (those properties with more than one company potentially liable for decommissioning costs). The BOEM identified (i) inactive properties, (ii) those with less than five years of production left, and (iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which supplemental financial assurance may be required.   The BOEM may require the Fund to fully secure all of its potential abandonment liabilities, which potentially could increase costs to the Fund. The Fund is not able to evaluate the impact of the proposed new rule on its operations or financial condition until a final rule is issued or some other definitive action is taken by the Interior or BOEM.

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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Information about Oil and Gas Producing Activities

12 Months Ended

Dec. 31, 2022

Information About Oil And Gas Producing Activities

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,
	2022			2021
	(in thousands)
Proved properties	$	17,927		$	17,439
Accumulated depletion and amortization		(14,181	)		(12,116	)
Oil and gas properties, net	$	3,746		$	5,323

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

	Year ended December 31,
	2022		2021
	(in thousands)
Development costs	$	488	$	245
	$	488	$	245

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, 2022 and 2021. 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, 2022												December 31, 2021
	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		175.7			13.7			71.4			201.4			130.6			11.1			63.8			152.3
Revisions of previous estimates (b)		(0.5	)		3.3			26.0			7.0			89.2			7.3			34.6			102.4
Production		(54.4	)		(6.5	)		(34.7	)		(66.7	)		(44.1	)		(4.7	)		(27.0	)		(53.3	)
End of year		120.8			10.5			62.7			141.7			175.7			13.7			71.4			201.4
Proved developed reserves:
Beginning of year		131.1			10.1			52.5			150.1			130.6			11.1			63.8			152.3
End of year		79.6			7.7			46.1			95.0			131.1			10.1			52.5			150.1
Proved undeveloped reserves:
Beginning of year		44.6			3.6			18.9			51.3			-			-			-			-
End of year		41.2			2.8			16.6			46.7			44.6			3.6			18.9			51.3

(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) Effective January 1, 2023, the fixed percentage overriding royalty interest (“ORRI”) of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The reserves shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI.

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,
	2022			2021
	(in thousands)
Future cash inflows	$	11,624		$	11,504
Future production costs		(2,616	)		(2,327	)
Future development costs		(2,864	)		(2,318	)
Future net cash flows		6,144			6,859
10% annual discount for estimated timing of cash flows		(765	)		(1,280	)
Standardized measure of discounted future estimated net cash flows	$	5,379		$	5,579

Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The future cash inflows or future revenue shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI.

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,
	2022			2021
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	3,509		$	3,971
Sales and transfers of oil and gas produced during the period		(4,957	)		(2,802	)
Changes in estimated future development costs		(546	)		175
Net change due to revisions in quantities estimates		394			3,797
Accretion of discount		558			58
Other		842			(204	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(200	)	$	4,995

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 (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies [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, salvage fund, production receivable, due from affiliate, other current assets, due to operators and accrued expenses. The carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. 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, 2022, 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, 2022, 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.

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.

Accrued Expenses

Accrued Expenses

Accrued expenses consist of the following:

	December 31,
	2022		2021
	(in thousands)
Accrued accounting and legal fees	$	63	$	66
Accrued royalty		56		-
	$	119	$	66

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, 2022 and 2021:

	December 31,
	2022			2021
	(in thousands)
Balance, beginning of year	$	934		$	1,565
Liabilities settled		(6	)		(305	)
Accretion expense		27			27
Revision of estimates		120			(353	)
Balance, end of year	$	1,075		$	934

During the year ended December 31, 2021, the Fund recorded credits to depletion expense totaling $0.3 million, which related to adjustments to the asset retirement obligations for fully depleted properties.

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

Oil and gas revenues from contracts with customers are recognized at the point when control of oil and natural gas is transferred to the customers in accordance with Accounting Standard Codification Topic 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 revenues. 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 natural 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. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the Fund’s balance sheets.

Other Revenue

Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities 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 affiliated entities 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 affiliates 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. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to 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, 2022 and 2021, revenue recognized from performance obligations satisfied in previous periods was not significant.

Allowance for Credit Losses

Allowance for Credit Losses

The Fund is exposed to credit losses through the sale of oil and natural gas to customers. However, the Fund only sells to a small number of major oil and gas companies that have investment-grade credit ratings. Based on historical collection experience, current and future economic and market conditions and a review of the current status of customers' production receivables, the Fund has not recorded an expected loss allowance as there are no past due receivable balances or projected credit losses.

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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment.

There were no impairments of oil and gas properties during the years ended December 31, 2022 and 2021. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. In addition, significant declines in oil and natural gas commodity prices could reduce the quantities of reserves that are commercially recoverable, which could result in impairment. 

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 2019 through 2021 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

The Fund has considered recent accounting pronouncements issued during the year ended December 31, 2022 and through the filing of this report, and the Fund has not identified new standards that it believes will have an impact on the Fund’s financial statements.

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Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Accrued expenses consist of the following:

Accrued expenses consist of the following:

	December 31,
	2022		2021
	(in thousands)
Accrued accounting and legal fees	$	63	$	66
Accrued royalty		56		-
	$	119	$	66

Schedule of Changes in Asset Retirement Obligations

	December 31,
	2022			2021
	(in thousands)
Balance, beginning of year	$	934		$	1,565
Liabilities settled		(6	)		(305	)
Accretion expense		27			27
Revision of estimates		120			(353	)
Balance, end of year	$	1,075		$	934

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Information about Oil and Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2022

Information About Oil And Gas Producing Activities

Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities

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

	December 31,
	2022			2021
	(in thousands)
Proved properties	$	17,927		$	17,439
Accumulated depletion and amortization		(14,181	)		(12,116	)
Oil and gas properties, net	$	3,746		$	5,323

Schedule of Cost 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,
	2022		2021
	(in thousands)
Development costs	$	488	$	245
	$	488	$	245

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, 2022 and 2021. 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, 2022												December 31, 2021
	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		175.7			13.7			71.4			201.4			130.6			11.1			63.8			152.3
Revisions of previous estimates (b)		(0.5	)		3.3			26.0			7.0			89.2			7.3			34.6			102.4
Production		(54.4	)		(6.5	)		(34.7	)		(66.7	)		(44.1	)		(4.7	)		(27.0	)		(53.3	)
End of year		120.8			10.5			62.7			141.7			175.7			13.7			71.4			201.4
Proved developed reserves:
Beginning of year		131.1			10.1			52.5			150.1			130.6			11.1			63.8			152.3
End of year		79.6			7.7			46.1			95.0			131.1			10.1			52.5			150.1
Proved undeveloped reserves:
Beginning of year		44.6			3.6			18.9			51.3			-			-			-			-
End of year		41.2			2.8			16.6			46.7			44.6			3.6			18.9			51.3

(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) Effective January 1, 2023, the fixed percentage overriding royalty interest (“ORRI”) of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The reserves shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI.

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,
	2022			2021
	(in thousands)
Future cash inflows	$	11,624		$	11,504
Future production costs		(2,616	)		(2,327	)
Future development costs		(2,864	)		(2,318	)
Future net cash flows		6,144			6,859
10% annual discount for estimated timing of cash flows		(765	)		(1,280	)
Standardized measure of discounted future estimated net cash flows	$	5,379		$	5,579

Schedule of Changes in the Standardized Measure for Discounted Future Net 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,
	2022			2021
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	3,509		$	3,971
Sales and transfers of oil and gas produced during the period		(4,957	)		(2,802	)
Changes in estimated future development costs		(546	)		175
Net change due to revisions in quantities estimates		394			3,797
Accretion of discount		558			58
Other		842			(204	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(200	)	$	4,995

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Accrued expenses consist of the following: (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Accrued accounting and legal fees	$ 63	$ 66
Accrued royalty	56
Total	$ 119	$ 66

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Schedule of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Balance, beginning of year	$ 934	$ 1,565
Liabilities settled	(6)	(305)
Accretion expense	27	27
Revision of estimates	120	(353)
Balance, end of year	$ 1,075	$ 934

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Organization and Summary of Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2022
Accounting Policies [Abstract]
Cash insured amount		$ 250
Depletion credit	$ 300
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%

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Related Parties (Details Narrative) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Annual management fee percentage rate	2.50%
Management fees	$ 291	$ 294
Percentage of total distributions allocated to fund manager	15.00%
Partners' capital account, distribution	$ 4,848	857
Due from affiliate	10	19
Fund Manager [Member]
Related Party Transaction [Line Items]
Partners' capital account, distribution	728	128
Management [Member]
Related Party Transaction [Line Items]
Management fees	300	300
Institutional Funds [Member]
Related Party Transaction [Line Items]
Other revenues from affiliates	100	100
Due from affiliate	$ 10	$ 19

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Commitments and Contingencies (Details Narrative) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitments for the drilling and development of investment properties	$ 2.9
Commitments for asset retirement obligations included in estimated capital commitments	1.8
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months	$ 40.0

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Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Information About Oil And Gas Producing Activities
Proved properties	$ 17,927	$ 17,439
Accumulated depletion and amortization	(14,181)	(12,116)
Total oil and gas properties, net	$ 3,746	$ 5,323

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Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Information About Oil And Gas Producing Activities
Development costs	$ 488	$ 245
Total Costs	$ 488	$ 245

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Schedule of Reserve Quantity Information (Details)		12 Months Ended
		Dec. 31, 2022 MBbls Mcf	Dec. 31, 2021 MBbls Mcf
Oil [Member]
Reserve Quantities [Line Items]
Beginning of year		175.7	130.6
Revisions of previous estimates	[1]	(0.5)	89.2
Production		(54.4)	(44.1)
End of year		120.8	175.7
Beginning of year		131.1	130.6
End of year		79.6	131.1
Beginning of year		44.6
End of year		41.2	44.6
NGL (BBLS) [Member]
Reserve Quantities [Line Items]
Beginning of year		13.7	11.1
Revisions of previous estimates	[1]	3.3	7.3
Production		(6.5)	(4.7)
End of year		10.5	13.7
Beginning of year		10.1	11.1
End of year		7.7	10.1
Beginning of year		3.6
End of year		2.8	3.6
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of year | Mcf		71.4	63.8
Revisions of previous estimates | Mcf	[1]	26.0	34.6
Production | Mcf		(34.7)	(27.0)
End of year | Mcf		62.7	71.4
Beginning of year | Mcf		52.5	63.8
End of year | Mcf		46.1	52.5
Beginning of year | Mcf		18.9
End of year | Mcf		16.6	18.9
Other Nonrenewable Natural Resources [Member]
Reserve Quantities [Line Items]
Beginning of year	[2]	201.4	152.3
Revisions of previous estimates	[1],[2]	7.0	102.4
Production	[2]	(66.7)	(53.3)
End of year	[2]	141.7	201.4
Beginning of year	[2]	150.1	152.3
End of year	[2]	95.0	150.1
Beginning of year	[2]	51.3
End of year	[2]	46.7	51.3

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

[2] BOE refers to barrel of oil equivalent

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Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Information About Oil And Gas Producing Activities
Future cash inflows	$ 11,624	$ 11,504
Future production costs	(2,616)	(2,327)
Future development costs	(2,864)	(2,318)
Future net cash flows	6,144	6,859
10% annual discount for estimated timing of cash flows	(765)	(1,280)
Standardized measure of discounted future estimated net cash flows	$ 5,379	$ 5,579

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Schedule of Changes in the Standardized Measure for Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Information About Oil And Gas Producing Activities
Net change in sales and transfer prices and in production costs related to future production	$ 3,509	$ 3,971
Sales and transfers of oil and gas produced during the period	(4,957)	(2,802)
Changes in estimated future development costs	(546)	175
Net change due to revisions in quantities estimates	394	3,797
Accretion of discount	558	58
Other	842	(204)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$ (200)	$ 4,995