UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒

ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31 2021, 2023

or

o

or

☐ 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. 000-52576

Ridgewood Energy S Fund, LLC

(Exact name of registrant as specified in its charter)

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☒x   No  ☐o

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

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 ☐ oNo ☒x

There is 0no market for the shares of LLC Membership Interest in the Fund. As of February 28, 2022,26, 2024, there were 839.5395 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY S FUND, LLC
20212023 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy S Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections and statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Such forward-looking statements are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include the impact on the Fund’s business and operations of the ongoing novel coronavirus (“COVID-19”) pandemic and any other 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 conflicts between Russia and Ukraine and Israel and Hamas and the global response to such conflicts, acts of terrorism and changes in domestic and foreign governmental regulations, as well as other risks and uncertainties discussed in this Annual Report in Item 1. “Business” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Examples of forward-looking statements made herein include statements regarding projects, investments, insurance, capital expenditures and liquidity. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

PART I

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on December 19, 2005 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 February 1, 2006, selling whole and fractional shares of LLC membership interests (“Shares”), primarily at $150 thousand per whole Share. 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 limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws.  The private placement offering was terminated on June 12, 2006. The Fund raised $124.4 million and, after payment of $19.9 million in offering fees, commissions and investment fees, the Fund had $104.5 million for investments and operating expenses.

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. Historically, when the Fund sought project investments, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects. Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders rely on the Manager to continue to manage the projects prudently, efficiently and fairly. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Annual Report.

As compensation for its services, the Manager is entitled to receive an annual management fee, payable monthly, equal to 2.5% of the total capital contributions madewhich was waived by the Fund’s shareholders, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Effective April 1, 2020, the Manager waived its management fee for the remaining life of the Fund. Management feesFund during the year ended December 31, 2020 were $0.1 million. Additionally, the2020. The Manager is entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 20212023 and 20202022 were $0.1$0.4 million and $14 thousand,$0.7 million, respectively.

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

Business Strategy

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

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. One member of the Investment Committee is based out of the Manager’s Palm Beach, Florida office, one member is based out of the Manager’s Montvale, New Jersey office and 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 13.34% 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.project.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deepwater Royalty Relief Act of 1995 (the “Deepwater Royalty Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Royalty Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Fund currently has one project, the Beta Project, which is eligible for royalty relief under the Deepwater Royalty Relief Act. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $41.60$46.19 per barrel and $54.01$59.97 per barrel) adjusted annually for inflation. The Deepwater Royalty Relief Act does not apply to natural gas if the prices of natural gas exceed certain thresholds (currently estimated to be between $5.20$5.77 per mmbtu and $9.00$10.00 per mmbtu) adjusted annually for inflation.

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned a working interest as of December 31, 2021.2023. 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.

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, 2021.2023. 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.

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.

Marketing/Customers

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

The Fund’s oil and natural gas generally is sold to its customers at prevailing market prices, which fluctuate with demand as a result of related industry variables.  The markets for, and prices of, oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence; therefore, it is impossible to predict the future price of oil and natural gas with any certainty.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes,” “Results of Operations – Overview” and “Results of Operations – Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue. In the past, the Fund has entered, and in the future, may enter into transactions or derivative contracts that establish a price floor for portions of its oil or natural gas production. 

Seasonality

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

However, notwithstanding the ability of the Fund’s Beta Project to produce year-round, the project is located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. In the third quarter of 2021, Hurricane Ida passed directly through the corridor where the Fund’s Beta Project is located. Although theThe Fund did not experience any significant damage, from Hurricane Ida, the Beta Project needed to be shut-in in accordance with safety protocols as well asshut-ins, or production stoppages due to the impact of the storm on third-party midstream and downstream infrastructure to which the Beta Project’s production flows. hurricane activity in 2023.

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 propertyBeta Project is operated by 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 entities under its management. The Manager re-evaluates its insurance coverage on an annual basis. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the insurable incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims during a particular policy period to the Fund or its affiliates, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for its proportionate share of the cost of dismantling and removal of production platforms and facilities and plugging and abandoning the wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2021,2023, the Fund had $1.3$1.6 million invested in a salvage fund. On a monthly basis, the Fund contributes 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. In addition, the Manager maintains an additional office lease that is used for administrative purposes for the Fund and other funds managed by the Manager.

Regulation

Oil and natural gas exploration, development, production and transportation activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to 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 May 2019, BSEE adopted a final rule revising standards for blowout prevention systems and other well controls pertaining to offshore activities (the “2019 Well Control Rule”). The 2019 Well Control Rule became effective July 15, 2019, however compliance with certain provisions was deferred until 2021 or thereafter as specified in those provisions. The 2019 Well Control Rule imposes new requirements relating to, among other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. The 2019 Well Control Rule applies directly to operators as opposed to non-operators. On September 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 final revision to the 2019 Well Control Rule was published in the Federal Register on August 23, 2023, and became effective on October 23, 2023. On September 28, 2018, the BSEE published a final rule revising regulations relating to oil and natural gas production safety systems, subsurface safety devices and safety device testing (referred to as “Subpart H”); the rule was effective December 27, 2018. Given the fact that compliance with the 2019 Well Control Rule and Subpart H is the responsibility of the operators and the exploration and development of each well is different, the future costs associated with compliance that will be incurred by non-operators, such as the Fund, cannot be determined or estimated. On December 4, 2020, BOEM published a Record of Decision (“ROD”) for the final programmatic environmental impact statement for geological and geophysical survey activities in the Gulf of Mexico and adjacent state waters. The ROD provides for additional mitigation measures for application for future BOEM issued permits or authorizations toward further minimizing impacts of such geological and geophysical survey activities on marine resources. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, which civil penalties were increased and adjusted for inflation on April 15, 2021,March 24, 2023, 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. 

Effective January 20, 2021, the Secretary of the Interior issued Order No. 3395 under the authority of Section 2 of Reorganization Plan No. 3 of 1950 (64 Stat. 1262) consistent with 200 DM 1 for the purpose of implementing a targeted and time-limited elevation of relevant decisions at the Interior for review.  One item under review is temporarily suspending the issuance of any onshore or offshore fossil fuel authorization, including but not limited to a lease, amendment to a lease, affirmative extension of a lease, contract, or other agreement, or permit to drill.  This does not limit existing operations under valid leases.  Prior to Order No. 3395 expiring on March 21, 2021, the Secretary of the Interior issued a letter to Bureau Directors dated March 19, 2021 confirming the matters that still need review and approval of the Office of the Assistant Secretary for Land and Minerals Management. Such matters include extension of applications for permit to drill, Records of Decision, lease sale notices and lease suspensions. As the Fund’s capital has been fully invested and it does not expect to invest in any new projects, the Fund believes the secretarial order will not have an impact on the Fund’s operations or financial condition.

BSEE and BOEM Supplemental Financial Assurance Requirements

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and natural gas leases and owners of pipeline rights-of-way, rights-of-use and easements on the OCS (“Lessees”).  Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance.  The rule became effective as of September 12, 2016;2016, however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances.  On May 1, 2017, the Secretary of the Interior directed the BOEM to complete a review of NTL 2016-N01 to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. 

was not fully implemented.

On October 16, 2020, BOEM and BSEE published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with the Lessees’ obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. To date, Upon review of the 2020 joint proposed rule and analysis of public comments, the Interior elected to separate the BOEM isand BSEE portions of the supplemental bonding requirements. BSEE finalized some provisions from the 2020 proposal as discussed below. BOEM rescinded its portion of the 2020 proposed rule and issued its new proposed rule below.

On April 18, 2023, BSEE published a final rule at 88 FR 23569 on Risk Management, Financial Assurance and Loss Prevention, wherein BSEE clarified and formalized its regulations related to decommissioning responsibilities of OCS oil, gas, and sulfur lessees and grant holders to ensure compliance with lease, grant, and regulatory obligations. The rule became effective May 18, 2023. The rule implements provisions of the 2020 proposed rule intended to clarify decommissioning responsibilities of right-of-use and easement grant holders and to formalize BSEE's policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal set forth in the 2020 proposed rule to amend BSEE's regulations to require BSEE to proceed in reverse chronological order against predecessor lessees, owners of operating rights, and grant holders when requiring such entities to perform their accrued decommissioning obligations if the current lessees, owners, or holders have failed to perform. In addition, BSEE also decided not currently implementing NTL 2016-N01 and its status is uncertain, but has indicated that it is reviewingto finalize the proposed appeal bonding requirements in this final rule.

NotwithstandingOn June 29, 2023, BOEM published a proposed rule, that if adopted as initially proposed, would substantially revise the uncertain status of NTL 2016-N01, BOEM had continued under existing law to review supplemental financial assurance requirements relative to sole liability properties (i.e., propertiesdecommission offshore wells and infrastructure once they are no longer in use. The proposed rule proposes a simplified test using only two criteria by which only one company is liable for decommissioning).  However, on August 18, 2021, the BOEM issued a Note to Stakeholders in which the BOEM stated that it was expanding its financial assurance efforts beyond sole liability projects to include “supplemental financial assurance of certain high-risk, non-sole liability properties” (those properties with more than one company potentially liable for decommissioning costs). The BOEM identified (i) inactive properties, (ii) those with less than five years of production left, and (iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for whichwould determine whether supplemental financial assurance mayshould be required.  The BOEM may requirerequired of OCS oil and gas lessees: (1) credit rating, and (2) the Fund to fully secure allratio of its potential abandonment liabilities, which potentially could increase coststhe value of proved oil and gas reserves of the lease to the Fund.estimated decommissioning liability associated with the reserves. In addition, as it relates to supplemental financial assurance requirements for OCS oil and gas right-of-use and easement grant holders, BOEM will only consider the first criteria – i.e., credit rating. Under the proposed rule, BOEM would no longer consider or rely upon the financial strength of prior grant holders and lessees in determining whether, or how much, supplemental financial assurance should be provided by the current grant holders and lessees. The proposed rule would allow existing lessees and grant holders to request phased-in payments over three years for new financial assurance amounts. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. The Fund is not able to evaluate the impact of the proposed new rule on its operations or financial condition until a final rule is issued or some other definitive action is taken by the Interior or BOEM.

Sales and Transportation of Oil and Natural Gas

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

Environmental Matters and Regulation

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

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

Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and was enacted in response to the numerous tanker spills that occurred in the 1980s, including the Exxon Valdez spill. Among other things, the OPA clarifies the federal response authority to, and defines penalties for, such spills. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA, with regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $672.51$725.7 million (effective as(as of November 12, 2019)December 23, 2022), while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $137.66$167.8 million in other damages for each incident.incident (as of April 14, 2023). These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. A failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on the Fund’s operations or financial condition.

Clean Water Act. Generally, the Clean Water Act, as well as analogous state requirements, imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal or delegated state agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. On December 11, 2018, the Environmental Protection Agency (“EPA”) and Department of the Army (“Army”) proposed a revised definition of “waters of the United States” (“WOTUS”), clarifying the limits of federal authority under the Clean Water Act. The scope of this authority, as defined under a 2015 rule, was challenged in several federal district court actions and therefore was repealed by the EPA and the Army on September 12, 2019. The repeal, which became effective on December 23, 2019, restored the previous regulation to how it existed prior to finalization of the 2015 Rule. The 2020 Navigable Waters Protection Rule (“NWPR”) was then promulgated, with a replacement definition of WOTUS, and went into effect on June 22, 2020. A recent executive order revoked a prior executive order related to WOTUS and directed agencies to review certain actions, including the NWPR. On June 9, 2021, the Department of the Army and EPA announced their intent to initiate a new rulemaking process that would both restore a pre-2015 Clean Water Rule and develop a new rule to establish a new WOTUS definition, and then sought feedback from stakeholders. On September 3, 2021, following a court order vacating the NWPR, the Department of the Army and EPA announced that they had halted implementation of the NWPR and would interpret WOTUS consistent with the pre-2015 regulatory regime. On November 18, 2021, the EPA and the Department of the Army announced the signing of a proposed rule to revise the definition of WOTUS. On December 7, 2021, the proposed rule was published in the Federal Register with a 60-day public comment period that closed on February 7, 2022. AOn 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 “2022 Definition”). The 2022 Definition is expectedcentral to be issued bythe U.S. Supreme Court decision in Sackett v. EPA, 598 U.S. 651 (2023). On May 25, 2023, the U.S, Supreme Court rendered its decision in Sackett v. EPA, which rejected the 2022 Definition. On August 29, 2023, the EPA laterand the Department of the Army issued a final rulemaking revising the 2022 Definition in 2022.an effort to conform the definition of WOTUS to the Sackett v. EPA decision (the “WOTUS Rule”). The WOTUS Rule is effective as of September 8, 2023. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), as well as analogous state requirements, restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. OCSLA provides the Secretary of the Interior, through BOEM, with the statutory authority to regulate air quality over the Central and Western Gulf of Mexico. On June 5, 2020, BOEM published the Offshore Air Quality Rule, which revised the air quality regulations applicable to activities that BOEM authorizes on the OCS in the Western Gulf of Mexico. The Offshore Air Quality Rule, effective on July 6, 2020, brings the air quality standards that lessees and operators must meet in order to operate in the Western Gulf of Mexico into compliance with the current National Ambient Air Quality Standards and benchmarks set forth by the EPA under the Clean Air Act. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act and comparable state requirements.

International MarineMaritime Organization 2020. In 2016, the International MarineMaritime Organization (“IMO”), a United Nations (“UN”) Agency, instituted a reduction in the sulfur specifications for global marine fuels from 3.5% to 0.5% effective January 1, 2020 in order to reduce the emissions of sulfur to the atmosphere. Shipping companies have the option to buy low sulfur fuel or install scrubbers to lower sulfur emissions to comply with the new regulation. The IMO currently has 175 UN member states (174 countries)that are responsible for monitoring the compliance of the shipping community with this new regulation. The impact to the Fund from this new2020 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. On July 7, 2023, the Maritime Environmental Protection Committee of IMO adopted the 2023 IMO Strategy on Reduction of GHG emission technologies, fuels and/or energy sources to represent at least 5% of energy used by international shipping by 2030. The Fund is not able to evaluate the impact of the 2023 IMO Strategy to its operations or financial condition until specific regulatory measures are adopted or some other definitive action is taken by the IMO.

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”), as amended by the Fiscal Responsibility Act of 2023, 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. On July 31, 2023, the CEQ published a proposed rule in the Federal Register for the Phase II rulemaking, opening a 60-day public comment period. According to CEQ, the proposed Phase II rule seeks to revise the NEPA regulations in ways that would provide for an effective environmental review process that promotes better decision making and regulatory certainty, ensure full and fair public involvement, and provide for sound decision making grounded in science, including consideration of relevant environmental, climate change, and environmental justice effects. The public comment period closed on September 29, 2023, and CEQ is reviewing the comments received. On January 9, 2023, the CEQ published in 88 FR 1196 interim guidance to assist agencies with analyzing GHG emissions and climate change effects for projects that are subject to NEPA review; this guidance became effective immediately. The Fund’s operations may be subject to analogous and comparable state laws and regulations, in addition to these federal statutes and regulations.

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

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

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 derivatives market. The Fund cannot predict at this time what regulations or portions of the law relating to the over-the-counter derivatives market, if any, will be changed as a result of the Order. Any changes in the law or regulation as a result of the Order could result in a repeal, amendment to or delayed implementation of the Dodd-Frank Act.

Currently, under 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 2021,2023, or at any time since 2012, a party to any derivative instruments or hedging programs.

Not required.

Not applicable.

Pursuant to the terms of the Fund’s LLC Agreement, the Manager renders management, advisory and administrative services to the Fund, which includes the assessing, identifying, and managing of material risks from cybersecurity threats through its Corporate IT Security Governance program. Ridgewood Energy’s Corporate IT Security Governance program consists of an information security framework and organizational structure with senior management oversight that are designed to safeguard critical information assets.

Cybersecurity risk is evaluated based upon risk-based approach. An analysis of information and technology assets that ranks the assets based upon their risk of potential internal and external threats and the impact of the potential loss of integrity, confidentiality, and availability of that asset is updated as appropriate. An Information Security Risk Assessment led by the Manager’s Chief Information Officer (“CIO”) is performed on an annual basis, and/or upon major changes of cybersecurity related processes and infrastructure, for evaluating the potential impacts to key technology, processes, and people upon known relevant threats. Either a mitigating action plan and/or risk acceptance with valid business reasons is required as a response to each identified risk. The results of the Information Security Risk Assessment are available to senior management for review and approval.

The Manager has developed and implemented additional programs that assist in reducing risk and providing additional protection of confidential information including:

On December 16, 2020, the SEC adopted the final resource extraction disclosure rules, which became effective on March 16, 2021. As adopted, the rule requires domestic or foreign reporting issuer to disclose payments made by the issuer of a subsidiary or entity controlled by the issuer to the U.S. federal government or a foreign government if the issuer engages in the commercial development of oil, natural gas, or minerals. The Fund, as a smaller reporting company, is exempt from complying with this rule.

Not required.

None.Governance

The Fund does not have its own board of directors or any board committees. The Fund relies upon the senior management oversight of the Manager reporting cybersecurity risks to the executive officers of the Fund. The Manager has a Cyber Risk Committee in place comprised of the CIO and other executive officers of the Fund that is responsible for reviewing and approving or rejecting escalated non-standard IT change requests. The CIO communicates regularly and serves as the Fund’s representation to address significant information technology activities and initiatives. The CIO has more than twenty years of experience as an information technology professional and has been CIO since 2007. The CIO has periodic calls with a third-party virtual Chief Information Security Officer on review of policy and procedures best practices and cybersecurity threats.

In 2023, there were no risks from cybersecurity threats that have materially affected or reasonably likely to material affect the Fund, its business strategy, results of operations or financial condition.

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

During the years ended December 31, 20212023 and 2020,2022, the Fund had no drilling activity for exploratory and developmental wells.

Unaudited Oil and Gas Reserve Quantities

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

The Manager’s primary technical person in charge of overseeing the Fund’s reserve estimates has a B.S. degree in Petroleum Engineering, a Master of Business Administration, and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With 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, 20212023 and 20202022 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.

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

Proved Undeveloped Reserves. As of December 31, 2021,2023, the Fund had proved undeveloped reserves related to the Beta Project totaling 4929 thousand barrels of oil, 43 thousand barrels of natural gas liquid (“NGL”) and 2114 thousand mcf of natural gas. As of December 31, 2020,2022, the Fund did not have anyhad proved undeveloped reserves.reserves related to the Beta Project totaling 46 thousand barrels of oil, 3 thousand barrels of NGL and 19 thousand mcf of natural gas. The Beta Project was determined to be a discovery in 2012 and commenced production in 2016. The decrease in total proved undeveloped reserves at December 31, 2023 was primarily attributable to a downward revision due to well performance.

The proved undeveloped reserves relating to the Beta Project, which were initially assigned at the end of the year 2021 and 2022, are associated with planned well recompletions. The Fund did not incur costs during the year ended December 31, 2023 to advance the development of its proved undeveloped reserves related to the Beta Project. The Fund expects theadditional recompletion operations to be completed in 20222026 and 2028.2027 related to the Beta Project.

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

Production and Prices

The information regarding the Fund’s production of oil and natural gas, and certain price and cost information during the years ended December 31, 20212023 and 20202022 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference. 

Delivery Commitments

As of December 31, 2021,2023, the Fund had no delivery obligations or delivery commitments under any existing contracts.

None.

None.

PART II

There is currently no established public trading market for the Shares. As of January 31, 2022,2024, there were 1,3931,421 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Distributions may be impacted by amounts of future capital required for the costs associated with the well recompletions for the Beta Project, as budgeted, as well as the funding of estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices. There is no requirement to distribute available cash and, as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 20212023 and 2020,2022, the Fund paid distributions totaling $0.4$2.6 million and $0.1$4.7 million, respectively.

Overview of the Fund’s Business

The Fund was organized primarily to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of oil and natural gas projects. Distributions to shareholders, if any, are funded from available cash from operations, as defined in the Fund’s LLC Agreement, and the frequency and amount are within the Manager’s discretion. The Fund’s capital has been fully allocated to its projects. 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.

The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. The Manager does not currently, nor is there any plan to, operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all development and producing operations, as appropriate. The Manager also participates in distributions. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.Fund’s Beta Project.

Market Conditions and COVID-19

The country is now two full years into the COVID-19 pandemic, and the outlook for the oil market, and the global economy in general, depends enormously on the country’s forward path out of it. During 2020, the outbreak of COVID-19 as a global pandemic and the lockdown measures and industrial slowdown around the world contributed to an economic downturn, significant drop in oil and natural gas demand and, together with the failure of an alliance between the Saudi Arabia-led Organization of Petroleum Exporting Countries (“OPEC”) and Russia to reach an agreement on oil production volumes resulted in an oil “price war,” caused oil prices to collapse to their lowest level in April 2020 as compared to the past several years . The period of lowAlthough oil and natural gas commodity prices during 2020 negatively impacted cash flow generated by2023 have been relatively steady compared to 2022, the Fund’s projects. On April 12, 2020, and throughout 2020, OPEC and Russia agreed and implemented oil production cuts to stabilize the oil market. Since then, the oil market has stabilized and strengthened with oil prices gradually rising throughout the rest of 2020.

During 2021, oil prices have continued to strengthen supported by a slow recovery in demand with the easing of lock-down measures and the rollout of COVID-19 vaccines, market-driven supply cutbacks in the upstream oil sector globally and the effective ongoing supply-side management by OPEC, which played an enormous role in stabilizing world oil markets over the past two years. OPEC and non-OPEC countries continue to signal effective cooperation at managing output to balance the market, even if demand growth stumbles going forward. Looking ahead, these factors indicate a more balanced market going into 2022. However, the COVID-19 pandemic and the new variants of the virus, specifically the Omicron variant, are still impacting countries, supply chains and commodities markets, in addition to the global financial markets. Different outcome of response to the new variants of the virus would have radically different impacts on global economic growth and the performance of financial markets as the market enters 2022. In addition, uncertainty still exists depending on actions taken by OPEC and non-OPEC countries in supporting a balanced global oil supply. 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 from the COVID-19 pandemic and global oil market.

The ultimate extent of the impact of the COVID-19 pandemic and resulting market disruption to the Fund’s operating results and cash flows continue to be unknown and unpredictable as it depends largely on future developments, including the duration and spread of COVID-19 and the related impact onoutlook for the oil and gas market in 2024 continues to be volatile. Oil prices are constantly adjusting to reflect changes in both the current status of, as well as expectations regarding the future of supply/demand balance, which is impacted by the following factors: (i) sentiments regarding current and future global economic activity, whether robust or tepid; (ii) upstream investment activity by the energy industry, which itself reflects the impactprice of oil, as well as access to investment capital; (iii) governmental actions designedenergy policy in the U.S. and abroad; (iv) the levels of crude oil in commercial storage and global strategic petroleum reserves, which buffer imbalances in daily supply and demand; (v) changing policy out of OPEC Plus aimed to preventdirectly manage the spreadglobal supply/demand balance for crude throughout coordinated output quotas; and (vi) fluctuations in the global purchasing power of COVID-19the U.S. Dollar, the value of which is inversely related to the price of oil. In addition, ongoing geopolitical conditions, including the ongoing Russia-Ukraine war and the development, availability, timely distribution and acceptanceevolving Israel-Hamas conflict as well as acts of effective treatments and vaccines worldwide. Ifterrorism, will continue to dictate oil and natural gas commodity pricesprices. The impact of these matters on global financial and the overall global economy, including financialcommodity markets therein, are further adversely impacted by the COVID-19 pandemic for a prolonged period,and their corresponding effect on 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.remains uncertain.

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 and result in non-cash charges to earnings due to impairment and higher depletion rates.

Oil and natural gas commodity prices have been subject to significant volatility during the past twoseveral years primarily attributableand the outlook continues to be volatile. Although volatile, the COVID-19 pandemic. Despite operating in a volatile commodity price environment,overall trend for the Fund achievedcrude oil market has been favorable during the milestone of full repayment of its debt related to the Beta Project well ahead of the debt’syear ended December 31, 2022 maturity date. Thus, having repaid the loan as of December 31, 2021, the Fund anticipates that more of the2023, which positively impacted cash flow generated fromby the Beta Project will be available for distribution.Project. The Fund also anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. The Fund will continue to closely manage and coordinate its capital spending estimates within its expected cash flows to provide for the costs associated with the well recompletions for the Beta Project, as budgeted. See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 20212023 and 20202022 and the effect of such average prices on the Fund’s results of operations. Although oil and natural gas commodity prices have significantly improved from historic lows in 2020, the Fund’s results of operations and liquidity may be materially adversely impacted if there is a significant decrease in pricing due to the COVID-19 pandemic.

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:

Critical Accounting Estimates

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

Proved Reserves

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

Asset Retirement Obligations

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

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and natural gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment.

Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 20212023 and 2020,2022, 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.

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, 20212023 and 2020.2022. NGL sales are included within gas sales.

The decreasesincrease in the number of wells producing and production days noted in the table above werewas primarily attributable to Main Pass 275, which reached the end of its productive life during second quarter 2021. The decreaseone well in gas sales volume was primarily related to the Beta Project, which is experiencing a natural declinewas shut-in in production coupled with the shut-in of production from one of the project’s wells since May 2021late-March 2022 due to recompletion work. The recompleted well returned toresumed production in late-September 2021. early-June 2022 and has been producing at an increased flow rate from new reservoir sands. The decreases in sales volumes noted in the table above were primarily related to natural declines in production from the other Beta Project’s wells.

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

Oil and Gas Revenue. Oil and gas revenue during the year ended December 31, 20212023 was $3.5$3.1 million, an increasea decrease of $1.6$2.9 million from the year ended December 31, 2020.2022.  The increasedecrease was primarily attributable to increaseddecreased sales volume totaling $2.0 million coupled with decreased oil and gas prices.prices totaling $0.8 million.

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

Other Revenue. Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities and other third parties. See Note 2 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information.

Depletion and Amortization. Depletion and amortization during the year ended December 31, 20212023 was $2.5$1.8 million, an increasea decrease of $0.6 million from the year ended December 31, 2020.2022. The increasedecrease was primarily attributable to a decrease in production volumes totaling $0.7 million and an adjustment to the asset retirement obligation related to a fully depleted property totaling $0.1 million during the year ended December 31, 2022, partially offset by an increase in the average depletion rate totaling $0.3 million. The increase in the average depletion rate was primarily attributable to the changes in reserves estimates provided annually by the Fund’s independent petroleum engineers coupled with the higher cost of reserves from the Beta Project primarily due to the recompletion costs incurred for one of the project’s wells during 2021.engineers.

See “Overview” above for certain factors that impact the depletion and amortization volume and rate variances. Reserves estimates may also be impacted by significant declines in oil and natural gas commodity prices due to the COVID-19 pandemic, which could result in higher depletion rates.

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

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

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, were $0.4 million ($6.987.75 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2021,2023, compared to $0.7$0.6 million ($12.438.04 per BOE) during the year ended December 31, 2020.2022.

The decreasesdecrease in production costs and production costs per BOE during the year ended December 31, 20212023 compared to the year ended December 31, 2020 were2022 was primarily attributable to the impact of the lease operating expense incurred during first quarter 2020 related to West Cameron 75, which the Fund was obligated to pay after withdrawal from the joint operating agreement in fourth quarter 2019 coupled with an adjustment to the lease operating expense recorded during second quarter 2021decreased oil and natural gas production as a result of natural decline in production from the final settlement agreement and release executed on May 26, 2021. Beta Project. Production costs per BOE were relatively consistent during the year ended December 31, 2023 compared to the year ended December 31, 2022.

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, was paid monthly to the Manager. Effective April 1, 2020, the Manager waived its management fee for the remaining life of the Fund.

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. Management reimbursement costs related to services provided by the Manager for accounting and investor relations are also included within general and administrative expenses.

Interest Expense, NetIncome. . Interest expense, netincome is comprised of interest expense and amortization of debt discounts related to the Fund’s long-term borrowings, and interest income earned on cash and cash equivalents and salvage fund. See Note 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 Fund’s credit agreement.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 20212023 were $2.8$2.9 million, related to revenue received of $3.8$3.5 million and interest income received of $0.1 million, partially offset by operating expenses of $0.5 million the payment of $0.2 million related to the Fund’s proportionate share of the plug and abandonment for a fully depleted property pursuant to the settlement agreement and release executed on May 26, 2021 with the well’s operator, general and administrative expenses of $0.2 million and interest payments of $0.1$0.3 million.

Cash flows provided by operating activities during the year ended December 31, 20202022 were $0.4$5.5 million, primarily related to revenue received of $2.0$6.3 million, partially offset by operating expenses of $0.9$0.6 million and general and administrative expenses of $0.2 million, the payment of $0.2 million related to the Fund’s proportionate share of a settlement for litigation between the Beta Project’s operator and a third-party, interest payments of $0.2 million and management fees of $0.1 million.

Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 20212023 were $0.7$0.2 million, primarily related to capital expenditures for oil and gas properties of $0.6 million and investments in salvage fund of $0.3 million, partially offset by proceeds from the salvage fund of $0.3 million.fund.

Cash flows used in investing activities during the year ended December 31, 20202022 were $0.2$0.6 million, primarily related to capital expenditures for oil and gas properties of $0.4 million and investments in salvage fund.fund of $0.2 million.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 20212023 were $1.9$2.6 million, related to the repayments of long-term borrowings of $1.5 million and manager and shareholder distributions of $0.4 million.distributions.

Cash flows used in financing activities during the year ended December 31, 20202022 were $0.6$4.7 million, related to the repayments of long-term borrowings of $0.5 million and manager and shareholder distributions of $0.1 million.distributions.

Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis.

Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering and through debt financing. The Fund’s capital has been fully 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.

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

Liquidity Needs

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

As of December 31, 2021,2023, the Fund’s estimated capital commitments related to its oil and gas properties were $2.0$2.7 million (which include asset retirement obligations for the Fund’s projects of $0.9$1.5 million), of which $0.4$0.2 million is expected to be spent during the year ending December 31, 2022.2024. Future results of operations and cash flows are dependent on planned recompletion costs of andthe revenues from production and sale of oil and gas from the Beta Project. In addition, cash flow from operations may be impacted by fluctuations in oil and natural gas commodity prices.

Based upon its current cash position, salvage fund and its current reserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations. Reserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager may temporarily suspend distributions to accommodate the Fund’s short-term commitments if needed.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. However, distributions may be impacted by amounts of future capital required for the costs associated with the well recompletions for the Beta Project, as budgeted, as well as the funding of estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices.

Credit Agreement

The Fund repaid the loan in full including accrued interest as of December 31, 2021. As of December 31, 2020, the Fund had outstanding borrowings of $1.5 million, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”). 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.

Overriding Royalty Interest

The Credit Agreement above provides for aEffective January 1, 2023, the fixed percentage of 13.34% overriding royalty interest toof 13.34% in the lenders, which will accrueFund’s net revenue interest in the Beta Project’s oil and becomenatural gas production became payable to the lenders as of January 1, 2023.Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project.

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators.  On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities.  The Fund does not negotiate such contracts.  No contractual obligations exist as of December 31, 20212023 and 2020,2022, other than those discussed in “Capital Expenditures” and “Liquidity Needs – Credit Agreement” above.

Recent Accounting Pronouncements

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

Not required.

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

None.

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, 2021.2023. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

Management's Report on Internal Control over Financial Reporting

Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)).  The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2021.2023.  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, 2021,2023, 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 havehas concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 20212023 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting. The Fund has not experienced any material impact to internal control over financial reporting due to the COVID-19 pandemic.

None.On February 22, 2024, Robert E. Swanson retired from his position as Chief Executive Officer and Principal Executive Officer (“CEO and PEO”) of the Fund, effective immediately. Mr. Swanson will continue to serve as Chairman Emeritus of Ridgewood Energy. The Manager of the Fund appointed Kathleen P. McSherry as the CEO and PEO of the Fund, effective as of February 22, 2024, following the retirement of Mr. Swanson. Ms. McSherry also serves and will continue to serve as the Principal Financial and Accounting Officer of the Fund.

Ms. McSherry’s biographical information is set forth in this Annual Report under Item 10. “Directors, Executive Officers and Corporate Governance” below, and such information is incorporated herein by reference. There are no family relationships between Ms. McSherry and any other officers of the Fund. There are no arrangements or understandings between Ms. McSherry and any other persons pursuant to which Ms. McSherry was selected to serve as the CEO and PEO of the Fund. There are no transactions since the beginning of fiscal 2022, nor are any currently proposed, between Ms. McSherry and the Fund that would be required to be disclosed under Item 404(a) of Regulation S-K.

On February 22, 2024, the Manager appointed Maria Haggerty, age 53, currently the Chief Compliance Officer and Vice President - Legal of Ridgewood Energy, as an executive officer of the Fund. Ms. Haggerty’s biographical information is set forth in this Annual Report under Item 10. “Directors, Executive Officers and Corporate Governance” below, and such information is incorporated herein by reference. There are no family relationships between Ms. Haggerty and any other officers of the Fund. There are no arrangements or understandings between Ms. Haggerty and any other persons pursuant to which Ms. Haggerty was selected to serve as an executive officer of the Fund. There are no transactions since the beginning of fiscal 2022, nor are any currently proposed, between Ms. Haggerty and the Fund that would be required to be disclosed under Item 404(a) of Regulation S-K.

On February 22, 2024, Kenneth W. Lang retired from his role as an executive officer of the Fund.

During the fourth quarter 2023, no officer of the Fund adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

Not applicable.

PART III

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, 20212023 are as follows:

The officers in the above table have been officers of the Fund since December 19, 2005, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009.2009, and Ms. Haggerty, who was appointed as an officer of the Fund on February 22, 2024. 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 serves as Chairman Emeritus of Ridgewood Energy and has served as the Chief Executive Officer andits controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee.inception.  Mr. Swanson is also the Chairman of the Investment Committee of Ridgewood Private Equity Partners, LLC,, an affiliate of Ridgewood Energy.  Mr. Swanson is an inactive member of the New York and New Jersey State Bars.  He is a graduate of Amherst College and Fordham University Law School. Effective February 22, 2024, Mr. Swanson retired from his role as CEO and PEO of the Fund.

Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Effective February 1, 2020, Mr. Lang relinquishedis a graduate of the roleUniversity of Chief Operating Officer of Ridgewood Energy.Houston. 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,Effective February 22, 2024, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduatefrom his role as an executive officer of the University of Houston.Fund.

Kathleen P. McSherry has served as the Executive Vice President, Chief Financial Officer and Assistant Secretary of Ridgewood Energy since 2001. Ms. McSherry holds a Bachelor of Science degree in Accounting from Kean University. The Manager of the Fund appointed Ms. McSherry as the CEO and PEO of the Fund, effective as of February 22, 2024, following the retirement of Mr. Swanson. Ms. McSherry also serves and will continue to serve as the Principal Financial and Accounting Officer of the Fund.

Daniel V. Gulino is Senior Vice President - Legal and Secretary for Ridgewood Energy and has served in that capacity for Ridgewood Energy since 2003. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars.  Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.

Maria E. Haggerty is the Chief Compliance Officer and Vice-President – Legal of Ridgewood Energy. Ms. Haggerty joined Ridgewood Energy’s legal department in 2005 and has served as Chief Compliance Officer since 2008. She has more than 20 years of legal experience during which time she has focused on private placements, debt structuring, derivative transactions, and other business matters. Prior to joining Ridgewood Energy, Ms. Haggerty was Counsel with the New York office of Bryan Cave LLP. Ms. Haggerty is a member of the New York and New Jersey state bars. She received her J.D. from Pace University School of Law and her B.A. from Marist College.

Board of Directors and Board Committees

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

Code of Ethics

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

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 839.5395 shares outstanding as of January 31, 2022.2024. The following table sets forth information with respect to beneficial ownership of the Shares as of January 31, 20222024 (no person owns more than 5% of the Shares). Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all Shares shown as beneficially owned by them. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

* Represents less than one percent.

⁽¹⁾ The address of all beneficial owners is 14 Philips Parkway, Montvale, NJ 07645

⁽²⁾Includes shares owned by Mr. Swanson’s family members.

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 an annual management fee, equal to 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Effective April 1,shareholder contributions. During 2020, the Manager waivedelected to waive its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs related to services provided by the Manager for accounting and investor relations. Such costs, totaling $80 thousand and $60 thousand, respectively, for each of the years ended December 31, 20212023 and 2020,2022, are included within general and administrative expenses. Management fees during the year ended December 31, 2020 were $0.1 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 20212023 and 20202022 were $0.1$0.4 million and $14 thousand,$0.7 million, respectively.

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

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, by the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). On September 23, 2020, a third-party working interest owner of the Claiborne Project executed a consent letter to assign the rights to the services under the PHA to Ridgewood Rattlesnake, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund III, L.P. (“Institutional Fund III”). On May 12, 2022, a third-party working interest owner executed an assignment and bill of sale agreement to assign the rights to the services under the PHA to Ridgewood Institutional IV Prospective Leases, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund IV, L.P. (“Institutional Fund IV”). Institutional Fund II, Institutional Fund III and Institutional Fund IIIIV 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.

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

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

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

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 20212023 and 2020.2022.

PART IV

(a) (1)     Financial Statements

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

(a) (2)     Financial Statement Schedules

None.

(a) (3)

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.

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.

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 $5.8$2.4 million as of December 31, 20212023 and depletion and amortization expense recognized was $2.5$1.8 million for the period ended December 31, 2021.2023. No impairment was recognized during 2021.2023.

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

How the Critical Audit Matter Was Addressed in the Audit

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

•

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

o

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

o

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

o

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

o

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

•

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

•

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