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, 2017

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)

14 Philips Parkway, Montvale, NJ07645

(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 ☐oNo☒


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 ☐oNo☒


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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes☒x   No ☐


Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.      ☒

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”,filer,” “smaller reporting company”company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer☐oAccelerated filer☐o

Non-accelerated filer

(Do not check if a smaller reporting company)

☐

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 March 9, 2018February 27, 2023, there were 207.7026 shares of LLC Membership Interest outstanding.

 


RIDGEWOOD ENERGY A-1 FUND, LLC
2017
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
SELECTED FINANCIAL DATA[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
1817 
 ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
18
ITEM 9ACONTROLS AND PROCEDURES18 

ITEM 9B

OTHER INFORMATION

18 
 ITEM 9A9C
CONTROLS AND PROCEDURESDISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
18
ITEM 9B
OTHER INFORMATION
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 ACCOUNTINGACCOUNTANT FEES AND SERVICES
21
PART IV   
 ITEM 15
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
22
    
  
SIGNATURES
23

Table of Contents
Table of Contents

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 that1995. 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”.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
Table of Contents
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 Fundthe 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 Fundthe 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 and related well costs incurred by the Fund.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, 20172022 and 20162021 were $0.4 million and $0.3 million, respectively.million. Additionally, the Manager is entitled to receive a 15% interest inof the cash distributions from operations made by the Fund. The Fund did not pay distributionsDistributions paid to the Manager during the years ended December 31, 20172022 and 2016.


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 (“BOEM”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

Table of Contents

The Fund’s capital has been fully invested in projects.  Asand 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. Two members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and three members are based out of the Manager’s Houston, Texas office.  The Investment Committee’s current activities with respect to the Fund are principally related to the development and operation of properties in which it already has a working interest.


Participation and Joint Operating Agreements

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


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 existing projects areBeta 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 under and as required bypursuant to the Fund’s credit agreement applicable to the Beta Project. See Note 3 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.


Deep Gas Royalty Relief
On January 26, 2004, the BOEM promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the “Royalty Relief Rule”). The Fund does not currently have any projects that are eligible for royalty relief under the Royalty Relief Rule.  The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the OCS nor does it apply if the price of natural gas exceeds $11.80 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation.

project.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep Waterthe 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 two projects,one project, the Beta and Liberty projects,Project, which areis 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 $37.93$44.68 per barrel and $49.25$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 $4.74$5.58 per mmbtu and $8.21$9.67 per mmbtu) adjusted annually for inflation.

3
Table of Contents

Properties


Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned ana working interest as of December 31, 2017.2022. 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  5   0.10 

  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, 2017.2022. 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   460   6,124   122 

Developed Acres  Undeveloped Acres 
Gross  Net  Gross  Net 
 23,033   378   364   6 

Information regarding the Fund’s current projects, all ofBeta Project, which areis 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.

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Table of Contents
     Total Spent  Total  
   Working  through  Fund  
Project Interest  December 31, 2017  Budget Status
     (in thousands)  
Producing Properties             
Beta Project 2.0%  $17,312  $19,458 The Beta Project is expected to include the development of five wells.  Wells #1 and #2 commenced production during third quarter 2016 and fourth quarter 2016, respectively.  Wells #3  and #4 commenced production during second  quarter 2017 and  third quarter 2017, respectively. Well #5 began drilling in third quarter 2017 and is expected to commence production in first quarter 2018. The Fund expects to spend $1.2 million for additional development costs and $0.9 million for asset retirement obligations.
Liberty Project 2.0%     $3,004  $3,268 The Liberty Project, a single-well project, commenced production in 2010.  After being shut-in during early-2016 due to third-party facilities' repair and maintenance activities, the well resumed production in early-May 2016.  The well was shut-in again in late-June 2017 due to gas dehydration unit work, resuming production in late-September 2017. The operator is currently flowing the well's current zone together with the behind-pipe zone at no cost to the Fund.  The Fund expects to spend $0.3 million for asset retirement obligations.

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, 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. DuringIn 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 partythird-party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2017, the Fund had threehas two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations. The Fund’s current producing projects areBeta 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”,Changes,” “Results of Operations – Overview”Overview” and “Results of Operations – Oil and Gas Revenue”Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue.In the past, the Fund has entered, and in the future, may enter into transactions or derivative contracts that fix the future prices or establish a price floor for portions of its oil or natural gas production. 


Seasonality


Generally, the Fund'sFund’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'sFund’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 projectsBeta Project to produce year-round, the Fund’s properties areproject 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 2017.


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 properties areBeta Project is operated by LLOG Exploration Offshore, L.L.C. and Walter Oil & Gas Corporation.


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

Insurance


The Manager has obtained what it believes to be adequate insurance for the funds that it manages to cover the risks associated with the funds’ passive investments, including those of the Fund. Although the Fund is not an operator, the Manager has, nonetheless, obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to its projects. In addition, the Manager’s practice is to obtain insurance as a package that is intended to cover most, if not all, of the fundsentities 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.

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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, 2017,2022, the Fund has $1.5had $2.0 million invested in a salvage fund. On a monthly basis, the Fund expects to contributecontributes to the salvage fund a portion of theits operating income from the Beta Project, to fund its asset retirement obligations.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.


Competition

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

Employees


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


Offices


The administrative office of both the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 230 Royal Palm Way, Suite 102, Palm Beach, FL, 33480 and 1254 Enclave Parkway, Houston, TX 77077 and 125 Worth Avenue, Suite 318, Palm Beach, Florida, 33480.  In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.


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 regulations.regulation. The Fund owns projectsthe Beta Project that areis 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 April 2016,May 2019, BSEE adopted a final rule establishing updatedrevising standards for blowout prevention systems and other well controls pertaining to offshore activities (the “Well“2019 Well Control Rule”). The 2019 Well Control Rule became effective July 28, 2016,15, 2019, however compliance with certain provisions iswas deferred until 20182021 or thereafter as specified.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 has also published a policy statement onfinal rule revising regulations relating to oil and natural gas production safety culture with nine characteristics of a robustsystems, subsurface safety culture. In April 2017,devices and safety device testing (referred to as “Subpart H”); the “Presidential Order Implementing an America-First Offshore Energy Strategy”rule was issued, which, among other things, directed the BSEE to review the Well Control Rule.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. 

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BOEM Notice to Lessees on Supplemental Bonding


Financial Assurance Requirements

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL”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 userights-of-use and easements on the OCS (“Lessees”).  Generally, the new 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 new rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances.  On June 22,May 1, 2017, the Secretary of the Interior directed the BOEM announced thatto 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 will remain in effect pending the completion of itsthe review of NTL 2016-N01 by the identified Interior personnel. 

On October 16, 2020, BOEM and BSEE published a proposed new NTL. The Fund, as well asrule 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 industry participants, are workingsecurity 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 operatorsstatus is uncertain, and working interest partners 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 determinereview 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 agree upon the correct level of decommissioning obligations to(iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which theysupplemental financial assurance may be liable and the manner in which such obligations will be secured.required.   The impact of the NTL, if enforced without change or amendment,BOEM may require the Fund to fully secure all of its potential abandonment liabilities, to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially thiswhich potentially could increase costs to the Fund if theFund. The Fund is requirednot able to obtain additional supplemental bonding, fund escrow accountsevaluate the impact of the proposed new rule on its operations or obtain letters of credit.


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.

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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 any environmental damage.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 projects.


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, that occurred in the 1980s.spill. Among other things, the OPA clarifies the federal response authority to, and increasesdefines 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, andwith regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $633.85$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 $133.65$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 if applicable, 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.

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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.

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 regulationslaws 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.

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Dodd-FrankAct. 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.


On February 3, 2017,

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


Currently, under theFund’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. Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums.  In addition, as required by the Dodd-Frank Act, the CFTC has set “speculative position limits” (which are limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts.  These requirements under the Dodd-Frank Act could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties.  If as a result of the legislation and regulations, the Fund alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance.  The Fund is not currently, and has not been during 2017,2022, or at any time since 2012, a party to any derivative instruments or hedging programs.

The Dodd-Frank Act also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals.  Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013. On June 27, 2016, the SEC adopted amended resource extraction disclosure rules pursuant to Section 1504 of the Dodd-Frank Act. However, on February 14, 2017, a bill was passed by the United States Congress eliminating the SEC resource extraction disclosure rules. The SEC had one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act. The Fund cannot predict whether the SEC will issue replacement rules or, if it does, whether such rules will remain in effect.

ITEM 1A. RISK FACTORS


Not required.


ITEM 1B.  UNRESOLVED STAFF COMMENTS


None.

Not applicable.

ITEM 2.  PROPERTIES


The information regarding the Fund’s propertiesBeta 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

The following table sets forth the Fund’s drilling activity during

During the years ended December 31, 20172022 and 2016.  Gross wells are the total number of wells in which2021, the Fund has an interest.  Net wells are the sum of the Fund’s fractional working interests owned in the grosshad no drilling activity for exploratory and developmental wells.  All of the wells, which produce both oil and natural gas, are located in the offshore waters of the Gulf of Mexico.  See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about the well in-progress as of December 31, 2017.


  2017  2016 
   Gross  Net  Gross  Net 
Exploratory wells:            
 Productive  -   -   1   0.02 
 In-progress  -   -   -   - 
Exploratory well total  -   -   1   0.02 
                 
Development wells:                
 Productive  2   0.04   1   0.02 
 In-progress  1   0.02   1   0.02 
Development well total  3   0.06   2   0.04 

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 the Manager.


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 over thirtythirty-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, 20172022 and 20162021 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”,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. 

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Proved Undeveloped Reserves.  As of December 31, 2017,2022, the Fund had proved undeveloped reserves related to the Beta Project totaling 0.1 million41 thousand barrels of oil, 53 thousand barrels of natural gas liquid (“NGL”) and 3017 thousand mcf of natural gas. As of December 31, 2016,2021, the Fund had proved undeveloped reserves related to the Beta Project totaling 1845 thousand barrels of oil, 4 thousand barrels of NGL and 1019 thousand mcf of natural gas. The Beta Project was determined to be a discovery in 2012 and commenced production in third quarter 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, 2017,2022, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $2.5$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”,“Properties,” is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.


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, 20172022 and 20162021 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”Overview” and “Results of Operations – Operating Expenses”Expenses” is incorporated herein by reference.


Delivery Commitments

As of December 31, 2017,2022, the Fund had no delivery obligations or delivery commitments under any existing contracts.


ITEM 3.  LEGAL PROCEEDINGS


None.


ITEM 4.  MINE SAFETY DISCLOSURES

None.

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None.

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, 2018,2023, there were 638662 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. Due to the significantDistributions may be impacted by amounts of future capital required to developfor the costs associated with the well recompletions for the Beta Project, distributions have been impacted, and may be impacted inas budgeted, as well as the future by amounts reserved to provide for its ongoing development costs, debt service costs and funding itsof 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. The Fund did not pay distributions duringDuring the years ended December 31, 20172022 and 2016.


2021, the Fund paid distributions totaling $4.8 million and $0.9 million, respectively.

ITEM 6. SELECTED FINANCIAL DATA


Not required.

[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 madefunded from available cash from operations, as defined in accordance with the Fund’s LLC Agreement. TheAgreement, and the frequency and amount of such distributions are within the Manager’s discretion, subject to available cash flow from operations.discretion. The Fund’s remaining capital has been fully allocated to its projects. Asinvested and as a result, the Fund will not invest in any new projects.


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 Fundthe Fund’s operations. The FundManager 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 projectsFund’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 Fund.


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. DeclinesSignificant 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. Significant declines in prices couldrecoverable and result in non-cash charges to earnings due to impairment.impairment and higher depletion rates.

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Oil and natural gas commodity prices have been subject to significant fluctuationsvolatility 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 past several years.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. Despite operating in a volatile commodity price environment, the Fund continued to advance the development of the Beta Project, which commenced production during the second half of 2016. The Fund has suspended distributionswill continue to closely manage and continues to conservecoordinate its capital spending estimates within its expected cash flows to provide for the continued development ofcosts associated with the well recompletions for the Beta Project. Project, as budgeted. See “Results“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, 20172022 and 2016.  If oil2021 and natural gasthe effect of such average prices decline, even if only for a short period of time,on the Fund’s results of operations and liquidity will be adversely impacted.


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 followingis a discussion of the accounting policies and estimates the Fund believes have had or are most significant.


Accounting for Acquisition, Exploration and Development Costs
Acquisition, exploration and development costs are accounted for usingreasonably likely to have a material impact on the successful efforts method. CostsFund’s financial position or results of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized.  Costs of drilling and equipping productive wells and related production facilities are capitalized. Annual lease rentals and exploration expenses are expensed as incurred.

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.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 reservereserves 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.

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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 and, at times, with information provided by third-party abandonment consultants specializing in the oil and gas industry.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 on a bi-annual basis,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 annually and when management determines thatfor impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determinedRecoverability 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 assetoil and gas properties is impaired, and written down to fair value. Fair value which is determined using estimated future net discounted cash flows from the asset.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, reserve estimates of oil and natural gas reserves and future development costs or discount rates could result in a different calculatedsignificant impact on the amount of impairment.  Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of future net discounted cash flows from proved oil and natural gas reserves could change in the near term.


Results of Operations


The following table summarizes the Fund’s results of operations during the years ended December 31, 20172022 and 2016,2021, 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.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 

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    Year ended December 31, 
  2017  2016 
    (in thousands) 
Revenue      
Oil and gas revenue $3,865  $944 
Expenses        
Depletion and amortization  3,445   846 
Management fees to affiliate  374   349 
Operating expenses  642   296 
General and administrative expenses  168   152 
Total expenses  4,629   1,643 
Loss from operations  (764)  (699)
Interest expense, net  (744)  (243)
Net loss  (1,508)  (942)
Other comprehensive loss        
Unrealized loss on marketable securities  (1)  - 
Total comprehensive loss $(1,509) $(942)

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, 20172022 and 2016.2021. NGL sales are included within gas sales.


  Year ended December 31, 
  2017  2016 
Number of wells producing  5   3 
Total number of production days  1,261   378 
Oil sales (in thousands of barrels)  76   20 
Average oil price per barrel $46  $40 
Gas sales (in thousands of mcfs)  104   29 
Average gas price per mcf $3.35  $2.51 

  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 the above table were primarily relatedproduction rates during 2022 compared to the commencement of production2021 from two of the Beta Project.  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.   Generally, the Fund sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. In the first type of agreement, or a netback agreement, the Fund receives a price, net of transportation expense incurred by the purchaser, and the Fund records revenue at the net price received. In the second type of agreement, the Fund pays transportation expense directly, and transportation expense is included within operating expenses in the statements of operations.


Oil and gas revenue during the year ended December 31, 20172022 was $3.9$5.5 million, an increase of $2.9$2.3 million from the year ended December 31, 2016.2021. The increase was attributable to increased sales volume totaling $2.5 million coupled with increased oil and gas prices totaling $0.4$1.5 million coupled with increased sales volume totaling $0.8 million.

See “Overview”“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, 20172022 was $3.4$2.1 million, an increase of $2.6$0.1 million from the year ended December 31, 2016.2021. The increase was attributable to an increase in production volumes totaling $2.4$0.6 million coupled with an increaseand 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 $0.4 million partially, offset by an adjustment to the asset retirement obligation related to a fully depleted property totaling $0.1$0.8 million. The increasedecrease in the average depletion rate was primarily attributable to the onset of production of the Beta Project.  Depletion and amortization rates were also impacted by changes in reservereserves estimates provided annually by the Fund’s independent petroleum engineers.


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


Management Fees to Affiliate.  An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term capital commitments.

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


  Year ended December 31, 
  2017  2016 
  (in thousands) 
Lease operating expense $411  $118 
Insurance expense  125   105 
Transportation and processing expense  36   2 
Accretion expense  30   50 
Workover expense and other  40   21 
  $642  $296 

  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 relatesrelate to the Fund’s producing properties.projects. Insurance expense represents premiums related to the Fund’s properties,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 provedoil and gas properties. Workover expense represents costs to restore or stimulate production of existing reserves.

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The average production cost,

Production costs, which includesinclude lease operating expense, transportation and processing expense and insurance expense, was $6.12were $0.5 million ($7.54 per barrel of oil equivalent (“BOE”or “BOE”) during the year ended December 31, 2017,2022, compared to $9.14$0.4 million ($6.97 per BOEBOE) during the year ended December 31, 2016. The decrease was primarily attributable to the Beta Project, which had lower cost per BOE in 2017.  The Beta Project, which commenced production in third quarter 2016, has lower cost per BOE as compared to the Liberty Project due to the processing of production through its standalone facility. The2021. Production costs and production costs per BOE may decline over time as throughput increases fromwere relatively consistent during the project or other projects expected to tie-inyear ended December 31, 2022 compared to the facility.


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 Expense, NetIncome (Expense). Interest expense, net isDuring the year ended December 31, 2022, interest income (expense) was comprised of interest expense and amortization of debt discounts and deferred financing costs related to the Fund’s long-term borrowings (see “Liquidity Needs” below for additional information), and interest income earned on cash and cash equivalents and salvage fund.


Unrealized Loss on Marketable Securities.  The Fund has available-for-sale investments within its salvage fund in federal agency mortgage-backed securities.  Available-for-sale securities are carried in During the financial statements at fair valueyear ended December 31, 2021, interest income (expense) was comprised of interest expense and unrealized gains and lossesamortization of debt discounts related to the securities’ changes in fair value are recorded in other comprehensive income until realized.

December 31, 2021.

Capital Resources and Liquidity


Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 20172022 were $1.8$4.8 million, primarily related to revenue received of $3.7$5.8 million, partially offset by operating expenses of $1.3$0.5 million, management fees of $0.4$0.3 million and general and administrative expenses of $0.2 million and the settlement of an asset retirement obligation of $0.1 million.


Cash flows used inprovided by operating activities during the year ended December 31, 20162021 were $0.4$2.4 million, primarily related to management feesrevenue received of $0.3$3.5 million, partially offset by operating expenses of $0.3 million, the settlement of an asset retirement obligationobligations of $0.2$0.3 million, andmanagement fees of $0.3 million, general and administrative expenses of $0.1 million partially offset by revenue receivedand interest payments of $0.6$0.1 million.


Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 20172022 were $2.7$0.5 million, primarily related to capital expenditures for oil and gas properties.


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, 20162021 were $1.9$0.4 million, related to capital expenditures for oil and gas properties of $2.2$0.6 million and investments in salvage fund of $0.2 million, partially offset by proceeds from the salvage fund of $0.2$0.3 million.


Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 20172022 were $0.1$4.8 million, related to the repayment of long-term borrowings.


manager and shareholder distributions.

Cash flows provided byused in financing activities during the year ended December 31, 20162021 were $4.4$2.3 million, related to proceeds fromthe repayments of long-term borrowings.


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


Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering and in certain circumstances, through debt financing. The Fund’s remaining capital has been fully allocated to its projects. Asinvested 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.

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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 and borrowing repayments.properties. Such needs are funded utilizing operating income and existing cash on-hand.


As of December 31, 2017,2022, the Fund’s estimated capital commitments related to its oil and gas properties were $3.3$2.9 million (which include asset retirement obligations for the Fund’s projects of $2.1$1.8 million), of which $1.8 million$40 thousand is expected to be spent during the year ending December 31, 2018, related to the settlement of asset retirement obligations for certain of the Fund’s projects and the continued development of the Beta Project.  As a result of continued development of the Beta Project, the Fund has experienced negative cash flows for the year ended December 31, 2017.2023. Future results of operations and cash flows are dependent on the continued successful developmentrevenues from production and the related productionsale of oil and gas revenues 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 reservereserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments borrowing repayments and ongoing operations. ReserveReserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term commitments if needed.


The 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. Due to the significantHowever, distributions may be impacted by amounts of future capital required to developfor the costs associated with the well recompletions for the Beta Project, distributions have been impacted, and may be impacted inas budgeted, as well as the future, by amounts reserved to provide for its ongoing development costs, debt service costs and funding itsof estimated asset retirement obligations.


Credit Agreement
In November 2012, Distributions may also be impacted by fluctuations in oil and natural gas commodity prices.

Overriding Royalty Interest

Effective January 1, 2023, the Fund entered into a credit agreement (as amended on September 30, 2016 and September 15, 2017, the “Credit Agreement”) with Rahr Energy Investments LLC, as administrative agent and lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”), that provided for an aggregate loan commitment to the Fund of approximately $8.3 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of December 31, 2017 and 2016, the Fund had borrowings of $7.2 million and $7.3 million, respectively, under the Credit Agreement.  As of December 31, 2016, in accordance with the terms of the Credit Agreement, there were no additional borrowings available to the Fund.


The loan bears interest at 8% compounded annually. Monthly principal and interest payments are the lesser of the monthly fixed amount of approximately $0.1 million or the Debt Service Cap amount, as defined in the Credit Agreement, until the loan is repaid in full, in no event later than December 31, 2020. The Fund expects operating income from the Beta Project to be sufficient to cover the principal and interest payments required under the Credit Agreement. The loan may be prepaid by the Fund without premium or penalty.

As additional consideration to the Lenders, the Fund has agreed to convey anpercentage overriding royalty interest (“ORRI”)of 10.81% in its workingthe Fund’s net revenue interest in the Beta Project to the Lenders.  The Fund’s share of the Lenders’ aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all the other participating funds managed by the Manager. Such ORRI will not becomeProject’s oil and natural gas production becomes payable to the Lenders until after the Loan is repaid in full.

The Credit Agreement contains customary negative covenants including covenants that limitFund’s former lender, which was conveyed pursuant to the Fund’s abilitycredit agreement applicable to among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warrants and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the Lenders under the Credit Agreement may accelerate the maturity of the loan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund believes it is in compliance with all covenants under the Credit Agreement as of December 31, 2017 and 2016.

See Note 3 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 2017 and 2016 and does not anticipate the use of such arrangements in the future.

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, 20172022 and 2016,2021, other than those discussed in “Estimated Capital“Capital Expenditures” and “Liquidity Needs – Credit Agreement” above.


Recent Accounting Pronouncements


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


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 302302(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.

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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, 2017.2022. 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)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, 2017.2022.  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, 2017,2022, 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, 20172022 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.

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None.

PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages as of December 31, 20172022 are as follows:


Name, Age and Position with Registrant

 

Robert E. Swanson, 70

75

Chief Executive Officer

 

Kenneth W. Lang, 63

68

President and Chief Operating Officer

 

Kathleen P. McSherry, 52

57

Executive Vice President, and Chief Financial Officer

and Assistant Secretary

 
Robert L. Gold, 59
  Executive Vice President

Daniel V. Gulino, 57

62

Senior Vice President General Counsel- 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 Chairman, Chief Executive Officer and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC,the Investment Committee of Ridgewood Private Equity Partners, LLC Ridgewood Infrastructure, LLC and Ridgewood Securities Corporation, affiliates, 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 and Chief Operating Officer 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, and Chief Financial Officer and Assistant Secretary of Ridgewood Energy since 2001. Ms. McSherry holds a Bachelor of Science degree in Accounting from Kean University.


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

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


Board of Directors and Board Committees

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

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Code of Ethics

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


Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, 2017, all filing requirements applicable to its officers, directors and 10% beneficial owners were met on a timely basis.

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, 2018.2023. 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 and related well costs incurred by the Fund.Fund and fully depleted project investments. Management fees during each of the years ended December 31, 20172022 and 20162021 were $0.4 million and $0.3 million, respectively.


million.

The Manager is also entitled to receive a 15% interest inof the cash distributions from operations made by the Fund. The Fund did not pay distributionsDistributions paid to the Manager during the years ended December 31, 20172022 and 2016.


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. DuringIn 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 of all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third partythird-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 regardsregard 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 partythird-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
Table of Contents

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


The Fund has working interest ownership in certain projects to develop 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 ACCOUNTINGACCOUNTANT FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 20172022 and 2016.

  Year ended December 31, 
  2017  2016 
  (in thousands) 
Audit fees (1)
 $89  $88 
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
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 filesfiled on February 18, 2010

     
10.14 
Credit Agreement dated asDescription of November 27, 2012 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party theretoShares
 
Incorporated by reference to the Fund’s Form 8-K filed on December 3, 2012
10.2
First Amendment to Credit Agreement dated September 30, 2016 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto
Incorporated by reference to the Fund’s Form 10-K filed on March 2, 2017
10.3
Second Amendment to Credit Agreement and Reaffirmation of Waiver dated September 15, 2017 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto
Incorporated by reference to the Fund's Form 10-Q filed on November 7, 2017
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, and 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, and 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
Table of Contents

SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 RIDGEWOOD ENERGY A-1 FUND, LLC
     
     
Date:  March 9, 2018February 27, 2023By: /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

March 9, 2018
Robert E. Swanson

(Principal Executive Officer)

Robert E. Swanson 
   
   
/s/ KATHLEEN P. MCSHERRY

Executive Vice President, and Chief Financial Officer

March 9, 2018
Kathleen P. McSherry and
Assistant Secretary

(Principal Financial and Accounting Officer)

February 27, 2023
Kathleen P. McSherry 
   
RIDGEWOOD ENERGY CORPORATION  
   
BY:  /s/ ROBERT E. SWANSONChief Executive Officer of the ManagerMarch 9, 2018February 27, 2023
Robert E. Swanson  

23
23

INDEX TO FINANCIAL STATEMENTSPAGE
  
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
F-2
Balance Sheets as of December 31, 20172022 and 20162021
F-3F-5
Statements of Operations and Comprehensive Loss for the years ended December 31, 20172022 and 20162021
F-4F-6
Statements of Changes in Members' Capital for the years ended December 31, 20172022 and 20162021
F-5F-7
Statements of Cash Flows for the years ended December 31, 20172022 and 20162021
F-6F-8
Notes to Financial Statements
F-7F-9
Supplementary Financial Information - Information about Oil and Gas Producing Activities -
Unaudited
F-13F-16

F-1
F-1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


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

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, 20172022 and 2016,2021, the related statements of operations, and comprehensive loss, changes in members’members' capital, and cash flows, for each of the two years in the period ended December 31, 2017,2022, 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, 20172022 and 2016,2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017,2022, 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 (Untied(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’sFund'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
Table of Contents

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:

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

oEvaluating the reasonableness of the methodology used and the production volume decline curve.

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

oComparing 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
Table of Contents

 /s/

·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:

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

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

oComparing 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

Parsippany,

Morristown, New Jersey

March 9, 2018

February 27, 2023

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

F-4
F-2

RIDGEWOOD ENERGY A-1 FUND, LLC

BALANCE SHEETS

(in thousands, except share data)



     December 31, 
  2017  2016 
Assets      
Current assets:      
Cash and cash equivalents $2,423  $3,458 
Salvage fund  1,191   266 
Production receivable  491   324 
Other current assets  52   119 
Total current assets  4,157   4,167 
Salvage fund  355   1,286 
Oil and gas properties:        
Proved properties  20,498   18,056 
Less:  accumulated depletion and amortization  (7,391)  (3,804)
Total oil and gas properties, net  13,107   14,252 
Total assets $17,619  $19,705 
         
Liabilities and Members' Capital        
Current liabilities:        
Due to operators $609  $462 
Accrued expenses  54   566 
Current portion of long-term borrowings  1,566   690 
Asset retirement obligations  1,191   266 
Other current liabilities  40   - 
Total current liabilities  3,460   1,984 
Long-term borrowings  5,639   6,453 
Asset retirement obligations  210   1,409 
Other liabilities  -   40 
Total liabilities  9,309   9,886 
Commitments and contingencies (Note 4)        
Members' capital:        
Manager:        
Distributions  (5,058)  (5,058)
Retained earnings  5,484   5,117 
Manager's total  426   59 
Shareholders:        
Capital contributions (250 shares authorized;        
   207.7026 issued and outstanding)  41,143   41,143 
Syndication costs  (4,804)  (4,804)
Distributions  (35,427)  (35,427)
Retained earnings  6,970   8,845 
Shareholders' total  7,882   9,757 
Accumulated other comprehensive income  2   3 
Total members' capital  8,310   9,819 
Total liabilities and members' capital $17,619  $19,705 

        
  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
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RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(in thousands, except per share data)



    Year ended December 31, 
  2017  2016 
Revenue      
Oil and gas revenue $3,865  $944 
Expenses        
Depletion and amortization  3,445   846 
Management fees to affiliate (Note 2)  374   349 
Operating expenses  642   296 
General and administrative expenses  168   152 
Total expenses  4,629   1,643 
Loss from operations  (764)  (699)
Interest expense, net  (744)  (243)
Net loss  (1,508)  (942)
Other comprehensive loss        
Unrealized loss on marketable securities  (1)  - 
Total comprehensive loss $(1,509) $(942)
         
Manager Interest        
Net income $367  $20 
         
Shareholder Interest        
Net loss $(1,875) $(962)
Net loss per share $(9,025) $(4,631)

        
  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
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RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)


           Accumulated Other    
           Comprehensive    
   # of Shares  Manager  Shareholders  Income (loss)  Total 
Balances, December 31, 2015  207.7026  $39  $10,719  $3  $10,761 
 Net income (loss)  -   20   (962)  -   (942)
Balances, December 31, 2016  207.7026   59   9,757   3   9,819 
 Net income (loss)  -   367   (1,875)  -   (1,508)
 Other comprehensive loss  -   -   -   (1)  (1)
Balances, December 31, 2017  207.7026  $426  $7,882  $2  $8,310 
    

                 
  # 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
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RIDGEWOOD ENERGY A-1 FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)


    Year ended December 31, 
  2017  2016 
       
Cash flows from operating activities      
Net loss $(1,508) $(942)
Adjustments to reconcile net loss to net cash        
   provided by (used in) operating activities:        
Depletion and amortization  3,445   846 
Accretion expense  30   50 
Amortization of debt discounts and deferred financing costs  122   61 
Changes in assets and liabilities:        
Increase in production receivable  (167)  (337)
Decrease (increase) in other current assets  67   (79)
Increase in due to operators  62   - 
(Decrease) increase in accrued expenses  (200)  204 
Settlement of asset retirement obligation  (82)  (208)
Net cash provided by (used in) operating activities  1,769   (405)
         
Cash flows from investing activities        
Capital expenditures for oil and gas properties  (2,749)  (2,178)
Decrease in salvage fund  5   232 
Net cash used in investing activities  (2,744)  (1,946)
         
Cash flows from financing activities        
Long-term borrowings  -   4,365 
Repayment of long-term borrowings  (60)  - 
Net cash (used in) provided by financing activities  (60)  4,365 
         
Net (decrease) increase in cash and cash equivalents  (1,035)  2,014 
Cash and cash equivalents, beginning of year  3,458   1,444 
Cash and cash equivalents, end of year $2,423  $3,458 
         
Supplemental disclosure of cash flow information        
Cash paid for interest, net of amounts capitalized $817  $- 
         
Supplemental disclosure of non-cash investing activities        
Due to operators for accrued capital expenditures for
oil and gas properties
 $500  $415 

        
  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.

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


The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fundthe 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 Fundthe 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 3 and 4.


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, the Managermanagement 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.  Mortgage-backed securities within the

The Fund’s financial assets and liabilities consist of cash and cash equivalents, salvage fund, are recorded basedproduction 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 Level 2 inputs, as such instruments trade in over-the-counter markets.

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, 2017,2022, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250$250 thousand per insured financial institution. As of December 31, 2017,2022, 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. At December 31, 2017 and 2016, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale.  Available-for-sale securities are carried in the financial statements at fair value.


     Gross    
  Amortized  Unrealized  Fair 
  Cost  Gains  Value 
  (in thousands) 
Government National Mortgage Association security (GNMA July 2041)    
December 31, 2017 $46  $2  $48 
December 31, 2016 $64  $3  $67 

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

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

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Debt Discounts and Deferred Financing Costs
Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt such as the conveyance of override royalty interests related to the Beta Project.  These costs are deferred and amortized over the term of the debt period or until the redemption of the debt.  Unamortized debt discounts and deferred financing costs are presented as a reduction of “Long-term borrowings” on the balance sheets.  During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”.  See Note 3. “Credit Agreement – Beta Project Financing” for additional information.

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. Interest costs related to the Credit Agreement (see Note 3. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, 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.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. Bi-annually,Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2017 and 2016.


  2017  2016 
  (in thousands) 
Balance, beginning of year $1,675  $2,119 
Liabilities incurred  2   2 
Liabilities settled  (82)  (208)
Accretion expense  30   50 
Revision of estimates  (224)  (288)
Balance, end of year $1,401  $1,675 

During the year ended December 31, 2017, the Fund recorded credits to depletion expense totaling $0.1 million, which related to an adjustment to the asset retirement obligation for a fully depleted property. As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

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 

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 and Imbalances

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 isindustry. 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 purchasernetback 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 fixed or determinablecontractually 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 delivery has occurred and title has transferred, and collectabilityfrom 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 reasonably assured.generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities and other third parties. The Fund usesearns a fee for its services and recognizes these fees as revenue at the sales methodtime its performance obligations are satisfied as the control of accounting foroil 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 imbalances.handling, gathering and operating services agreement with affiliated entities and other third parties does not give rise to contract assets or liabilities. The volumesreceivables related to the Fund’s proportionate share of gas sold may differrevenue 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 volumesBeta Project operator to whichthe 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 entitled based onrequired 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 interestsestimates and the actual amounts received in the properties.  These differences create imbalancesmonth that arethe 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 as a liability only whenfrom performance obligations satisfied in previous periods was not significant.

Allowance for Credit Losses

The Fund is exposed to credit losses through the properties’ estimated remaining reserves netsale of oil and natural gas to customers. However, the Fund will not be sufficientonly sells to enablea 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 underproduced owner to recoup its entitled share through production.  The Fund’s recorded liability, if any, would be reflected in other liabilities.  Nocurrent status of customers' production receivables, are recorded for those wells where the Fund has taken less than its share of production.


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 annually and when management determines thatfor impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determinedRecoverability 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 assetoil and gas properties is impaired, and written down to fair value. Fair value which is determined using estimated future net discounted cash flows from the asset.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, reserve estimates of oil and gas reserves and future development costs or discount rates could result in a different calculatedsignificant impact on the amount of impairment.  Given the volatility

There were no impairments of oil and natural gas prices, it is reasonably possible thatproperties during the Fund’s estimate of future net discounted cash flows from proved oilyears ended December 31, 2022 and natural gas reserves could change in the near term.


2021. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. IfIn addition, significant declines in oil and natural gas commodity prices decline, even if only for a short periodcould reduce the quantities of time, it is possiblereserves that impairments of oil and gas properties will occur.

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 20142019 through 20162021 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%99% to shareholders and 1%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%85% of available cash from dispositions will be distributed to shareholders and 15%15% to the Manager.

Recent Accounting Pronouncements

In May 2014,

The Fund has considered recent accounting pronouncements issued during the Financial Accounting Standards Board (“FASB”) issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligationsyear ended December 31, 2022 and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance.  The accounting guidance may be applied either retrospectively or through the usefiling of a modified-retrospective method. Underthis report, and the Fund has not identified new accounting guidance, the revenue associated withstandards that it believes will have an impact on the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with its current revenue recognition model.  The Fund adopted the new accounting guidance using the modified retrospective method on January 1, 2018.  Although the Fund did not identify changes to its revenue recognition that resulted in a material cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance will result in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue recognition accounting guidance.


2.   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%2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  In addition, pursuant to the terms of the LLC Agreement,Fund and fully depleted project investments, however, the Manager is also 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 capital commitments. Management fees during each of the years ended December 31, 20172022 and 20162021 were $0.4 million and $0.3 million, respectively.

$0.3 million.

The Manager is also entitled to receive a 15% interest in15% of the cash distributions from operations made by the Fund. The Fund did not pay distributionsDistributions paid to the Manager during the years ended December 31, 20172022 and 2016.

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, 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 partythird-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 partythird-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.

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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 projects to develop oil and natural gas projects, which are also owned by other entities that are likewise managed by the Manager.


3. Credit Agreement – Beta Project Financing


In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016Commitments and September 15, 2017, the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provided for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Certain other funds managed by the Manager (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Funds. Contingencies

Capital Commitments

As of December 31, 2016, in accordance with the terms of the Credit Agreement, there were no additional borrowings available to the Ridgewood Participating Funds.


As of December 31, 2017 and 2016, the Fund had borrowings of $7.2 million and $7.3 million, respectively, under the Credit Agreement. The Loan bears interest at 8% compounded annually.  Principal and interest are repaid at the lesser of the monthly fixed amount of approximately $0.1 million or the Debt Service Cap amount as defined in the Credit Agreement, in no event later than December 31, 2020.  The Loan may be prepaid by the Fund without premium or penalty. On September 15, 2017, the Ridgewood Participating Funds entered into the second amendment to the Credit Agreement, which principally amended the definition of the net revenues, which is the basis for the calculation of the Debt Service Cap amount.

There were no unamortized debt discounts and deferred financing costs as of December 31, 2017. Unamortized debt discounts and deferred financing costs of $0.1 million as of December 31, 2016 are presented as a reduction of “Long-term borrowings” on the balance sheet.  Amortization expense during each of the years ended December 31, 2017 and 2016 of $0.1 million were expensed and included on the statements of operations within “Interest expense, net”. Amortization expense during the year ended December 31, 2016 of $0.1 million was capitalized and included on the balance sheet within “Oil and gas properties”.

As of December 31, 2017, there were no accrued interest costs outstanding.  As of December 31, 2016, accrued interest costs of $0.5 million, were included on the balance sheets within “Accrued expenses”. Interest costs incurred during the years ended December 31, 2017 and 2016 of $0.6 million and $0.2 million, respectively, were expensed and included on the statements of operations within “Interest expense, net”. Interest costs incurred during the year ended December 31, 2016 of $0.1 million were capitalized and included on the balance sheet within “Oil and gas properties”. During the years ended December 31, 2017 and 2016, the Fund made payments on the loan of $0.3 million and $0.1 million, respectively, which related to capitalized interest costs.

As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders.  The Fund’s share of the Lenders’ aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Such ORRI will not become payable to the Lenders until after the Loan is repaid in full.  The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2017 and 2016.

4.   Commitments and Contingencies

Capital Commitments
As of December 31, 2017,2022, the Fund’s estimated capital commitments related to its oil and gas properties were $3.3$2.9 million (which include asset retirement obligations for the Fund’s projects of $2.1$1.8 million), of which $1.8 million$40 thousand is expected to be spent during the year ending December 31, 2018, related to the settlement of asset retirement obligations for certain of the Fund’s projects and the continued development of the Beta Project.  As a result of continued development of the Beta Project, the Fund has experienced negative cash flows for the year ended December 31, 2017.2023. Future results of operations and cash flows are dependent on the continued successful developmentrevenues from production and the related productionsale of oil and natural gas revenues from the Beta Project.

Based upon its current cash position, salvage fund and its current reservereserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments borrowing repayments and ongoing operations. ReserveReserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.  However, if cash flow from operations is not sufficient to meet

Overriding Royalty Interest (ORRI)

Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s commitments,net revenue interest in the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financingBeta Project’s oil and natural gas production becomes payable to accommodate the Fund’s short-term commitments if needed.


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, 20172022 and 2016,2021, 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 Notice to Lessees on Supplemental Bonding

Financial Assurance Requirements

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”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 userights-of-use and easements on the Outer Continental Shelf (“Lessees”).  Generally, the new 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 new rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances.  On June 22,May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM announced thatto 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 will remain in effect pending the completion of itsthe 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 NTL. The Fund, as well asrule 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 industry participants, are workingsecurity 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 operatorsstatus is uncertain, and working interest partnersBOEM has indicated that it is reviewing the proposed rule.

Notwithstanding the uncertain status of NTL 2016-N01, BOEM had continued under existing law to determinereview 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 agree upon the correct level of decommissioning obligations to(iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which theysupplemental financial assurance may be liable and the manner in which such obligations will be secured.required.   The impact of the NTL, if enforced without change or amendment,BOEM may require the Fund to fully secure all of its potential abandonment liabilities, to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially thiswhich potentially could increase costs to the Fund if theFund. The Fund is requirednot able to obtain additional supplemental bonding, fund escrow accountsevaluate the impact of the proposed new rule on its operations or obtain letters of credit.


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 fundsentities managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other fundsentities 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

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, 
  2017  2016 
  (in thousands) 
Proved properties $20,498  $18,056 
Accumulated depletion and amortization  (7,391)  (3,804)
Oil and gas properties, net $13,107  $14,252 

Schedule of 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

Schedule of Cost 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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  Year ended December 31, 
  2017  2016 
  (in thousands) 
Exploration costs $15  $20 
Development costs  2,269   2,266 
  $2,284  $2,286 

Table III - Reserve Quantity Information


Schedule of Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 20172022 and 2016.2021. 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, 2017  December 31, 2016 
   United States 
   Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Total (BOE) (a)  Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Total (BOE) (a) 
                         
Proved developed and undeveloped reserves:    
Beginning of year  175,100   8,060   220,360   219,887   291,911   3,964   311,221   347,745 
Extensions and discoveries (b)  62,061   4,769   29,717   71,783   -   -   -   - 
Revisions of previous estimates (c)  100,237   15,902   (63,319)  105,585   (96,926)  5,575   (70,683)  (103,131)
Production  (75,797)  (8,130)  (54,318)  (92,980)  (19,885)  (1,479)  (20,178)  (24,727)
End of year  261,601   20,601   132,440   304,275   175,100   8,060   220,360   219,887 
                                 
Proved developed reserves:     
Beginning of year  156,860   8,060   209,960   199,914   14,355   3,964   103,054   35,494 
End of year  199,540   15,832   102,723   232,492   156,860   8,060   209,960   199,914 
                                 
Proved undeveloped reserves:     
Beginning of year  18,240   -   10,400   19,973   277,556   -   208,167   312,251 
End of year  62,061   4,769   29,717   71,783   18,240   -   10,400   19,973 

  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)Extensions and discoveries were attributable to extensions for the Beta Project.
(c)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

Schedule of 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, 
  2017  2016 
   (in thousands) 
Future cash inflows $12,596  $6,862 
Future production costs  (2,867)  (2,132)
Future development costs  (3,026)  (2,436)
Future net cash flows  6,703   2,294 
10% annual discount for estimated timing of cash flows  (970)  205 
Standardized measure of discounted future estimated net cash flows $5,733  $2,499 



      
  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


Schedule of 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, 
  2017  2016 
  (in thousands) 
Net change in sales and transfer prices and in production costs
 related to future production
 $2,458  $(2,890)
Sales and transfers of oil and gas produced during the period  (3,293)  (719)
Net change due to extensions, discoveries, and improved recovery  1,489   - 
Changes in estimated future development costs  37   4,593 
Net change due to revisions in quantities estimates  2,888   (2,417)
Accretion of discount  250   338 
Other  (595)  219 
Aggregate change in the standardized measure of discounted future net cash
 flows for the year
 $3,234  $(876)


      
  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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