false 2023 FY 0001385662 false 422 743

 2024-02-26

 2023-10-01

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 cik1385662:InstitutionalFundsMember

 cik1385662:InstitutionalFundsMember

 cik1385662:InstitutionalFundsMember

 utr: MBbls

 utr: Mcf

 UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 WASHINGTON, D.C. 20549

 FORM 10-K

 x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 For the fiscal year ended December 31, 2023

 or

 o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 For the transition period from _____ to _____

 Commission File No. 000-53178

 Ridgewood Energy V Fund, LLC

 (Exact name of registrant as specified in its charter)

 Delaware

 (State or other jurisdiction of

 incorporation or organization)

 20-5941122

 (I.R.S. Employer

 Identification No.)

 14 Philips Parkway, Montvale, NJ 07645

 (Address of principal executive offices) (Zip code)

 ( 800) 942-5550

 (Registrant's telephone number, including
area code)

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

Securities registered pursuant to Section 12(g) of the Act:

 Shares of LLC Membership Interest

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

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

(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

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

is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.
See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company,"
and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 Large accelerated filer

 Accelerated filer

 Non-accelerated filer

 x

 Smaller reporting company

 Emerging growth company

 x

 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.

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.

 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.

 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).

is a shell company (as defined in Rule 12b-2 of the Act). Yes No x

 There is no market for the shares of LLC Membership
Interest in the Fund. As of February 26, 2024, there were 513.1226 shares of LLC Membership Interest outstanding.

2023 ANNUAL REPORT ON FORM 10-K

 PAGE

 ITEM 1

 BUSINESS

 ITEM 1A

 RISK FACTORS

 ITEM 1B

 UNRESOLVED STAFF COMMENTS

 ITEM 1C

 CYBERSECURITY

 ITEM 2

 PROPERTIES

 ITEM 3

 LEGAL PROCEEDINGS

 ITEM 4

 MINE SAFETY DISCLOSURES

 ITEM 5

 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 ITEM 6

 [RESERVED]

 ITEM 7

 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 ITEM 7A

 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 ITEM 8

 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 ITEM 9

 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 ITEM 9A

 CONTROLS AND PROCEDURES

 ITEM 9B

 OTHER INFORMATION

 ITEM 9C

 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 ITEM 10

 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 ITEM 11

 EXECUTIVE COMPENSATION

 ITEM 12

 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 ITEM 13

 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 ITEM 14

 PRINCIPAL ACCOUNTANT FEES AND SERVICES

 ITEM 15

 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 SIGNATURES

 FORWARD-LOOKING STATEMENTS

 Certain statements in this Annual Report on Form 10-K
("Annual Report") and the documents Ridgewood Energy V Fund, LLC (the "Fund") has incorporated by reference into
this Annual Report, other than purely historical information, including estimates, projections and statements relating to the Fund's
business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are
"forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Such forward-looking
statements are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results
to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements.
Forward-looking statements can generally be identified by words such as "believe," "project," "expect,"
"anticipate," "estimate," "intend," "strategy," "plan," "target,"
"pursue," "may," "will," "will likely result," and similar expressions and references
to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated
include the impact on the Fund's business and operations of any future widespread health emergencies or public health crises such
as pandemics and epidemics, weather conditions, such as hurricanes, changes in market and other conditions affecting the pricing, production
and demand of oil and natural gas, the cost and availability of equipment, the military 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.

 ITEM 1.

 BUSINESS

 Overview

 The Fund is a Delaware limited liability company
("LLC") formed on November 21, 2006 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 January 3, 2007, 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 May 16, 2007. The Fund raised $76.0 million and, after payment of $12.1 million in offering fees, commissions and investment fees,
the Fund had $63.9 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, which was waived by the Manager for the remaining life of the Fund during 2015. 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, 2023 and 2022 were $0.4 million and $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
and as a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which
it currently has a working interest, as discussed below under the heading "Properties" in this Item 1. "Business"
of this Annual Report.

 Investment Committee

 Ridgewood Energy maintains an investment committee
consisting of five employees of the Manager (the "Investment Committee"). The members of the Investment Committee provide
operational, financial, scientific and technical oil and gas expertise to the Fund. The Investment Committee's current activities
with respect to the Fund are principally related to the development and operation of properties in which it already has a working interest.

 Participation and Joint Operating Agreements

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

 Concentration of Production and Revenues

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

 Project Information

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

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

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

 Royalty Payments

 Generally, and depending on the lease, working
interest owners of an offshore oil and natural gas lease under the OCSLA pay a royalty of 12.5%, 16.67% or 18.75% to the U.S. Government
through the Office of Natural Resources Revenue ("ONRR"). Other than the ONRR royalties, the Fund does not have material royalty
burdens with the exception of the fixed percentage overriding royalty interests ("ORRI") of 11.81% in its net revenue interest
in the Beta Project's oil and natural gas production, which was conveyed on January 1, 2023 and is payable to the former lender
pursuant to the Fund's credit agreement applicable to the project.

 Deepwater Royalty Relief

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

 Total Productive Wells

 Gross

 Net

 Oil and natural gas

 0.14

 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, 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.

 Developed Acres

 Undeveloped Acres

 Gross

 Net

 Gross

 Net

 23,033

 Information regarding the Fund's Beta Project,
which is located in the offshore waters of the Gulf of Mexico, is provided in the following table. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations" of this Annual Report under the heading "Liquidity
Needs" for information regarding the funding of the Fund's capital commitments.

 Total Spent

 Total

 Working

 through

 Fund

 Project

 Interest

 December 31, 2023

 Budget

 Status

 Beta Project

 1.94%

 $

 19,597

 $

 22,277

 The Beta Project, a seven-well project, commenced production from its first two wells in 2016. Additional
 five wells commenced production in 2017, 2018 and 2019. During 2022, the project experienced shut-in from late-March 2022 to
 early-June 2022 for recompletion work. The Fund expects to spend $1.3 million for additional development costs and $1.4 million
 for asset retirement obligations.

 Marketing/Customers

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

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

 Seasonality

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

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

 Insurance

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

 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, 2023, the Fund had $1.7 million invested in a salvage fund. On a monthly basis, the Fund contributes to the salvage
fund a portion of its operating income to fund its asset retirement obligations as necessary. Such contributions to the salvage fund will
reduce the amount of cash distributions that could otherwise be made to investors by the Fund. Any portion of the salvage fund that remains
after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are
no restrictions on withdrawals from the salvage fund.

 Employees

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

 Offices

 The administrative office of both the Fund and
the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional
office space at 230 Royal Palm Way, Suite 102, Palm Beach, FL, 33480 and 1254 Enclave Parkway, Houston, TX 77077.

 Regulation

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

 Outer Continental Shelf
Lands Act

 Under the OCSLA, the United States federal government
has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered
to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding
process. Such activity is conducted by the BOEM. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental
Enforcement ("BSEE") pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety
and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may
apply to OCS vessels, rigs, platforms, vehicles and structures. BSEE regulates the design and operation of well control and other equipment
at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits,
among other requirements. BSEE adopted strict requirements for subsea drilling production equipment and had proposed new requirements
to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention
technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. BSEE has
also published a policy statement on safety culture with nine characteristics of a robust safety culture. In May 2019, BSEE adopted a
final rule revising standards for blowout prevention systems and other well controls pertaining to offshore activities (the "2019
Well Control Rule"). The 2019 Well Control Rule became effective July 15, 2019, however compliance with certain provisions was deferred
until 2021 or thereafter as specified in those provisions. The 2019 Well Control Rule imposes new requirements relating to, among other
things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. 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 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.

 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, however, the NTL 2016-N01 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. Upon review of the 2020 joint proposed rule and analysis
of public comments, the Interior elected to separate the BOEM and 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 to finalize the proposed appeal bonding requirements in this final
rule.

 On June 29, 2023, BOEM published a proposed rule,
that if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements to decommission offshore
wells and infrastructure once they are no longer in use. The proposed rule proposes a simplified test using only two criteria by which
BOEM would determine whether supplemental financial assurance should be required of OCS oil and gas lessees: (1) credit rating, and (2)
the ratio of the value of proved oil and gas reserves of the lease to the 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 $725.7 million (as of 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 $167.8 million in other damages for
each 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. On December 30, 2022, the EPA and the Department
the Army announced a final rule establishing a revised definition of WOTUS that restores the pre-2015 regulatory regime (the "2022
Definition"). The 2022 Definition is central to the 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 and the Department of the Army issued a final rulemaking revising the 2022 Definition in 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 Maritime
Organization 2020. In 2016, the International Maritime 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 that are responsible for monitoring the compliance
of the shipping community with this new regulation. The impact to the Fund from this 2020 regulation could be that heavier sour crudes,
such as from the Beta Project, could fall in value relative to lighter sweet crudes as a result of excess high sulfur fuel on the market
and subsequent refinery crude slate changes. However, the price of heavier sour crudes in the market continues to be supported by tightness
in supply for such crude, new refinery capacity consuming medium/high sulfur crudes and refinery optimization around high sulfur products.
As such, the Fund believes IMO 2020 will not in the future have a material impact on the Fund's operations or financial condition.
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, 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.

 Under the Fund's LLC Agreement, the Fund
has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. The Dodd-Frank
Act mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. The Fund is
not currently, and has not been during 2023, or at any time since 2012, a party to any derivative instruments or hedging programs.

 ITEM 1A.

 RISK FACTORS

 Not required.

 ITEM 1B.

 UNRESOLVED STAFF COMMENTS

 Not applicable.

 ITEM 1C. CYBERSECURITY

 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:

 Collaborative Approach: A comprehensive, cross-functional approach to identifying, preventing and mitigating
 cybersecurity threats and incidents, while also implementing controls and procedures that provide for the prompt escalation of certain
 cybersecurity incidents so that decisions regarding the public disclosure and reporting of such incidents can be made by senior management
 in a timely manner.

 Technical Safeguards: Technical safeguards designed to protect the Fund's information systems
 from cybersecurity threats, including firewalls, intrusion prevention and detection systems, anti-malware functionality and access controls,
 which are evaluated and improved through vulnerability assessments and cybersecurity threat intelligence.

 Incidence Response and Recovery Planning: An Incident Response Plan that dictates how the Manager prepares,
 identifies, contains, remediates, and recovers from various vulnerabilities, threats, and events, including cybersecurity events impacting
 the Fund.

 Third-Party Risk Management: A comprehensive, risk-based approach to identifying and overseeing cybersecurity
 risks presented by third parties, including vendors, service providers and other external users of the Manager's systems, as well
 as the systems of third-parties that could adversely impact the Fund and its investors in the event of a cybersecurity incident affecting
 those third-party systems.

 Education and Awareness: Security Awareness training is provided for all new and existing employees
 that reviews information concerning cyber risks and user responsibilities, and heightens awareness of cyber threats. Training is documented
 and reported to senior management when appropriate.

 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.

 ITEM 2.

 PROPERTIES

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

 Drilling Activity

 During the years ended December 31, 2023 and 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 thirty-five years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation
of exploration and development opportunities, and the oversight of drilling and production operations.

 The Fund's reserve estimates as of December
31, 2023 and 2022 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, 2023, the Fund had proved undeveloped reserves related to the Beta Project totaling 32 thousand barrels of oil, 3 thousand barrels
of natural gas liquid ("NGL") and 16 thousand mcf of natural gas. As of December 31, 2022, the Fund had proved undeveloped
reserves related to the Beta Project totaling 0.1 million barrels of oil, 3 thousand barrels of NGL and 20 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 additional recompletion operations to be completed in 2026 and 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, 2023 and 2022 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, 2023, the Fund had no delivery
obligations or delivery commitments under any existing contracts.

 ITEM 3.

 LEGAL PROCEEDINGS

 None.

 ITEM 4.

 MINE SAFETY DISCLOSURES

 None.

 ITEM 5.

 MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
 SECURITIES

 There is currently no established public trading
market for the Shares. As of January 31, 2024, there were 959 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, 2023 and 2022, the Fund paid distributions totaling $2.8 million and $5.0 million, respectively.

 ITEM 6.

 [RESERVED]

 ITEM 7.

 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 Overview of the Fund's Business

 The Fund was organized primarily to acquire interests
in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
The Fund's primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across
a portfolio of oil and natural gas projects. Distributions to shareholders, if any, are funded from available cash from operations, as
defined in the Fund's LLC Agreement, and the frequency and amount are within the Manager's discretion. The Fund's capital
has been fully invested and as a result, the Fund will not invest in any new projects and will limit its investment activities, if any,
to those projects in which it currently has a working interest.

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

 Market Conditions

 Although oil and natural gas commodity prices
during 2023 have been relatively steady compared to 2022, the outlook 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 price of oil, as well as access to investment
capital; (iii) governmental energy 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 directly manage
the global supply/demand balance for crude throughout coordinated output quotas; and (vi) fluctuations in the global purchasing power
of the 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 evolving Israel-Hamas conflict as well as acts of terrorism, will continue to dictate oil and natural
gas commodity prices. The impact of these matters on global financial and commodity markets and their corresponding effect on the Fund
remains uncertain.

 Commodity Price Changes

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

 Oil and natural gas commodity prices have been
subject to significant volatility during the past several years and the outlook continues to be volatile. Although volatile, the overall
trend for the crude oil market has been favorable during the year ended December 31, 2023, which positively impacted cash flow generated
by the Beta Project. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility.
The Fund will continue to closely manage and coordinate its capital spending estimates within its expected cash flows to provide for the
costs associated with the well recompletions for the Beta Project, as budgeted. See "Results of Operations" under this Item
7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information on the
average oil and natural gas prices received by the Fund during the years ended December 31, 2023 and 2022 and the effect of such average
prices on the Fund's results of operations.

 Market pricing for oil and natural gas is volatile
and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund
cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Factors
affecting market pricing for oil and natural gas include:

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

 weather conditions;

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

 actions by OPEC Plus, the Organization of the Petroleum Exporting Countries and other state-controlled oil
 companies;

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

 governmental regulations (inclusive of impacts of climate change), both domestic and foreign;

 domestic and foreign tax policy;

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

 the supply and price of foreign oil and gas;

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

 the discovery rate of new oil and gas reserves;

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

 available pipeline and other oil and gas transportation capacity;

 the ability of oil and gas companies to raise capital;

 the overall supply and demand for oil and gas; and

 the price and availability of alternate fuel sources.

 Critical Accounting Estimates

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

 Proved Reserves

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

 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, 2023 and 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.

 2023

 2022

 Revenue

 Oil and gas revenue

 $

 3,485

 $

 6,537

 Other revenue

 Total revenue

 3,700

 6,900

 Expenses

 Depletion and amortization

 1,893

 2,503

 Operating expenses

 General and administrative expenses

 Total expenses

 2,665

 3,496

 Income from operations

 1,035

 3,404

 Interest income

 $

 1,103

 $

 3,412

 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, 2023 and 2022.
NGL sales are included within gas sales.

 2023

 2022

 Number of wells producing

 Total number of production days

 2,509

 2,463

 Oil sales (in thousands of barrels)

 Average oil price per barrel

 $

 $

 Gas sales (in thousands of mcfs)

 Average gas price per mcf

 $

 3.28

 $

 6.68

 The increase in production days noted in the table
above was primarily attributable to one well in the Beta Project, which was shut-in in late-March 2022 due to recompletion work. The well
resumed production in 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, 2023 was $3.5 million, a decrease of $3.1 million from the year ended December 31, 2022. The
decrease was attributable to decreased sales volume totaling $2.1 million coupled with decreased oil and gas prices totaling $0.9 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, 2023 was $1.9 million, a decrease of $0.6 million from the year ended December
31, 2022. The decrease was attributable to a decrease in production volumes totaling $0.8 million and adjustments to the asset retirement
obligations related to fully depleted properties totaling $0.1 million, 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.

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

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

 2023

 2022

 Lease operating expense

 $

 $

 Transportation and processing expense

 Insurance expense

 Accretion expense

 Workover expense and other

 $

 $

 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 $0.5 million ($8.33 per barrel of oil equivalent or "BOE")
during the year ended December 31, 2023, compared to $0.7 million ($8.90 per BOE) during the year ended December 31, 2022.

 The decrease in production costs during the year
ended December 31, 2023 compared to the year ended December 31, 2022 was primarily attributable to decreased oil and natural gas production
as a result of natural decline in production from the 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.

 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 Income. Interest income
is comprised of interest earned on cash and cash equivalents and salvage fund.

 Capital Resources and Liquidity

 Operating Cash Flows

 Cash flows provided by operating activities during
the year ended December 31, 2023 were $3.0 million, related to revenue received of $3.9 million and interest income received of $0.1 million,
partially offset by operating expenses of $0.6 million, inclusive of the payment of $0.1 million related to the Fund's proportionate
share of the plug and abandonment for a fully depleted property pursuant to a bill of sale agreement executed on September 12, 2023 with
the well's operator, general and administrative expenses of $0.3 million and the settlement of asset retirement obligation of $0.1
million.

 Cash flows provided by operating activities during
the year ended December 31, 2022 were $5.8 million, primarily related to revenue received of $6.9 million, partially offset by operating
expenses of $0.7 million, general and administrative expenses of $0.2 million and the settlement of asset retirement obligations of $0.2
million.

 Investing Cash Flows

 Cash flows used in investing activities during
the year ended December 31, 2023 were $0.1 million, primarily related to investments in salvage fund of $0.2 million, partially offset
by proceeds from the salvage fund of $0.1 million.

 Cash flows used in investing activities during
the year ended December 31, 2022 were $0.6 million, related to capital expenditures for oil and gas properties of $0.4 million and investments
in salvage fund of $0.4 million, partially offset by proceeds from the salvage fund of $0.2 million.

 Financing Cash Flows

 Cash flows used in financing activities during
the year ended December 31, 2023 were $2.8 million, related to manager and shareholder distributions.

 Cash flows used in financing activities during
the year ended December 31, 2022 were $5.0 million, related to manager and shareholder 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 invested and as a result, the Fund will not invest in any new projects and will limit its investment activities, if any,
to those projects in which it currently has a working interest. Such investment activities, which include estimated capital spending on
planned well recompletions for the Beta Project, are expected to be funded from cash flows from operations and existing cash-on-hand and
not from equity, debt or off-balance sheet financing arrangements.

 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, 2023, the Fund's estimated
capital commitments related to its oil and gas properties were $3.2 million (which include asset retirement obligations for the Fund's
projects of $1.9 million), of which $0.5 million is expected to be spent during the year ending December 31, 2024. Future results of operations
and cash flows are dependent on the revenues from production and sale of oil and gas from the Beta Project. In addition, cash flow from
operations may be impacted by fluctuations in oil and natural gas commodity prices. Based upon its current cash position, salvage fund
and its current reserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations.
Reserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and
are subject to frequent revision.

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

 Overriding Royalty Interest

 Effective January 1, 2023, the fixed percentage
overriding royalty interest of 11.81% in the Fund's net revenue interest in the Beta Project's oil and natural gas production
became payable to the Fund's former lender, which was conveyed pursuant to the Fund's credit agreement applicable to the project.

 Contractual Obligations

 The Fund enters into participation and joint operating
agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration,
development and production activities. The Fund does not negotiate such contracts. No contractual obligations exist
as of December 31, 2023 and 2022, other than those discussed in "Capital Expenditures" above.

 Recent Accounting Pronouncements

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

 ITEM 7A.

 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 Not required.

 ITEM 8.

 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

 ITEM 9.

 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

 None.

 ITEM 9A.

 CONTROLS AND PROCEDURES

 Disclosure Controls and Procedures

 Under the supervision and with the participation
of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation
of the effectiveness of the design and operation of the Fund's disclosure controls and procedures as defined in Rule 13a-15(e) and
15d-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") as of December 31, 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, 2023. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations
of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on their assessment using those
criteria, management of the Fund concluded that, as of December 31, 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 has concluded that there have not been any changes in the Fund's internal control over financial reporting during
the quarter ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, the Fund's internal
control over financial reporting.

 ITEM 9B.

 OTHER INFORMATION

 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.

 ITEM 9C.

 DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

 Not applicable.

 ITEM 10.

 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 The Fund has engaged Ridgewood Energy as the Manager.
The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the
Fund and their ages as of December 31, 2023 are as follows:

 Name, Age and Position with Registrant

 Robert E. Swanson, 76

 Chief Executive Officer (1)

 Kenneth W. Lang, 69

 President (1)

 Kathleen P. McSherry, 58

 Chief Executive Officer and Executive
 Vice President, Chief Financial Officer and Assistant Secretary (2)

 Daniel V. Gulino, 63

 Senior Vice President - Legal and Secretary

 Maria E. Haggerty, 53

 Chief Compliance Officer and Vice President
 – Legal (3)

 (1) Effective
 February 22, 2024, Mr. Swanson and Mr. Lang retired from their roles as executive officers of the Fund.

 (2) Effective
 February 22, 2024, Ms. McSherry was appointed as the Chief Executive Officer of the Fund.

 (3) Effective
 February 22, 2024, Ms. Haggerty was appointed as an executive officer of the Fund.

 The officers in the above table have been officers
of the Fund since November 21, 2006, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the
Fund since June 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 its controlling shareholder since its 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
of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Mr. Lang is a graduate of the University of 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. Effective February 22, 2024, Mr. Lang retired from his role as an executive officer of the 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.

 Section 16(a) Beneficial Ownership Reporting

 Section 16(a) of the Exchange Act requires the
Fund's executive officers, and persons who own more than 10% of a registered class of the Fund's equity securities, to file
reports of ownership and changes in ownership with the SEC. Based on a review of the reports filed electronically with the SEC during
and with respect to the year ended December 31, 2023, the Fund believes that during the year ended December 31, 2023, all filing requirements
applicable to its officers and 10% beneficial owners were met on a timely basis. A Section 16(a) Form 5 was filed
within 45 days after the year ended December 31, 2023 for Robert E. Swanson to reflect a transfer of Mr. Swanson's ownership
of the Shares to a grantor trust that should have been reported on a Section 16(a) Form 4 during 2023.

 ITEM 11.

 EXECUTIVE COMPENSATION

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

 ITEM 12.

 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 Beneficial ownership is determined in accordance
with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is
based on 513.1226 shares outstanding as of January 31, 2024. The following table sets forth information with respect to beneficial ownership
of the Shares as of January 31, 2024 (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.

 Name of beneficial
 owner (1)

 Number
 of shares

 Percent

 Robert E. Swanson, Chief Executive Officer (2)

 0.6667

 *

 Executive officers as a group

 0.6667

 *

 * 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 held by
a trust.

 ITEM 13.

 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 Pursuant to the terms of the LLC Agreement, the
Manager is entitled to an annual management fee, equal to 2.5% of total shareholder contributions. During 2015, the Manager elected 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 for each of the years ended
December 31, 2023 and 2022, are included within general and administrative expenses.

 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, 2023 and
2022 were $0.4 million and $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 IV are entities that are managed by the Fund's
Manager. Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each
barrel of oil and mcf of natural gas produced through the Beta Project production facility. See Note 2 of "Notes to Financial Statements"
– "Related Parties" contained in Item 8. "Financial Statements and Supplementary Data" within this Annual
Report for more information regarding the PHA.

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

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

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

 ITEM 14.

 PRINCIPAL ACCOUNTANT FEES AND SERVICES

 The following table presents fees for services
rendered by Deloitte & Touche LLP during the years ended December 31, 2023 and 2022.

 2023

 2022

 Audit fees (1)

 $

 $

 (1)

 Fees for audit of annual financial statements,
 reviews of the related quarterly financial statements, and reviews of documents

 filed with the SEC.

 ITEM 15.

 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 (a) (1) Financial Statements

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

 (a) (2) Financial Statement
Schedules

 None.

 (a) (3)

 EXHIBIT

 NUMBER

 TITLE OF EXHIBIT

 METHOD OF FILING

 3.1

 Certificate of Formation
 of Ridgewood Energy V Fund, LLC dated November 21, 2006

 Incorporated by reference to the Fund's Form 10 filed on April 18, 2008

 3.2

 Limited Liability Company
 Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy V Fund, LLC dated January 3, 2007

 Incorporated by reference to the Fund's Form 10 filed on April 18, 2008

 Description of Shares

 Incorporated by reference to the Fund's Form 10-K filed on March 3, 2020

 31.1

 Certification of Kathleen P. McSherry, Chief Executive Officer and Executive Vice President, Chief Financial Officer and Assistant Secretary of the Fund, pursuant to Exchange Act Rule 13a-14(a)

 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Kathleen P. McSherry, Chief Executive Officer and Executive Vice President, Chief Financial Officer and Assistant Secretary of the Fund

 99.1

 Report of Netherland, Sewell & Associates, Inc.

 101.INS

 101.SCH

 101.CAL

 101.DEF

 101.LAB

 101.PRE

 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.

 Date: February 26, 2024

 By:

 /s/ KATHLEEN P. MCSHERRY

 Kathleen P. McSherry

 Chief Executive Officer and Executive
Vice President,

Chief Financial Officer and Assistant Secretary

 (Principal Executive Officer and Principal Financial

and Accounting
Officer)

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

 Signature

 Capacity

 Date

 /s/ KATHLEEN P. MCSHERRY

 Chief Executive Officer

 February 26, 2024

 Kathleen P. McSherry

 Executive Vice President, Chief Financial Officer and Assistant Secretary

(Principal
Executive Officer and Principal Financial and Accounting Officer)

 RIDGEWOOD ENERGY CORPORATION

 BY: /s/ MARIA E. HAGGERTY

 Chief Compliance Officer and Vice President -
Legal of the Manager

 February 26, 2024

 Maria E. Haggerty

 INDEX TO FINANCIAL STATEMENTS

 PAGE

 Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)

 Balance Sheets as of December 31, 2023 and 2022

 Statements of Operations for the years ended December 31, 2023 and 2022

 Statements of Changes in Members' Capital for the years ended December 31, 2023 and 2022

 Statements of Cash Flows for the years ended December 31, 2023 and 2022

 Notes to Financial Statements

 Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited

 F- 1

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM

 To the Shareholders and the Manager of Ridgewood
Energy V Fund, LLC

 Opinion on the Financial Statements

 We have audited the accompanying balance sheets
of Ridgewood Energy V Fund, LLC (the "Fund") as of December 31, 2023 and 2022, the related statements of operations, changes
in members' capital, and cash flows, for each of the two years in the period ended December 31, 2023, and the related notes (collectively
referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects,
the financial position of the Fund as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States
of America.

 Basis for Opinion

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

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

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

 Critical Audit Matter

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

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

 Critical Audit Matter Description

 As described in Note 1 to the financial statements,
oil and gas properties are accounted for using the successful efforts method. Depletion and amortization of the cost of proved oil and
gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized
costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The
sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and
costs to construct offshore platforms and associated asset retirement costs. Also, the Fund reviews the carrying value of its oil and
gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties
may not be recoverable. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of
the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows,
the carrying value of the oil and gas properties is impaired, and written down to fair value.

 F- 2

 Estimates of proved reserves are key components
of the Fund's most significant estimates involving its rate for recording depletion and amortization and estimated future cash flows
of oil and gas properties used to test for impairment. Annually, the Fund engages an independent petroleum engineering firm to perform
a comprehensive study of the Fund's proved properties to determine the quantities of reserves and the period over which such reserves
will be recoverable. The Fund's estimates of proved reserves are based on the quantities of oil and natural gas that geological
and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic
and operating conditions.

 The Fund's oil and gas properties, net balance
was $2.6 million as of December 31, 2023 and depletion and amortization expense recognized was $1.9 million for the period ended December
31, 2023. No impairment was recognized during 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.

 F- 3

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

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

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

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

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

 /s/ Deloitte & Touche LLP

 Morristown, New Jersey

 February 26, 2024

 We have served as the Fund's auditor since 2007.

 F- 4

 BALANCE SHEETS

 (in thousands, except share data)

 2023

 2022

 Assets

 Current assets:

 Cash and cash equivalents

 $

 $

 Salvage fund

 Production receivable

 Due from affiliate (Note 2)

 Other current assets

 Total current assets

 1,688

 1,352

 Salvage fund

 1,241

 1,573

 Oil and gas properties:

 Proved properties

 21,249

 21,115

 Less: accumulated depletion and amortization

 ( 18,620
)

 ( 16,702
)

 Total oil and gas properties, net

 2,629

 4,413

 Total assets

 $
 5,558

 $
 7,338

 Liabilities and Members' Capital

 Current liabilities:

 Due to operators

 $

 $

 Accrued expenses

 Asset retirement obligations

 Total current liabilities

 Due to operators

 -

 Asset retirement obligations

 1,140

 Total liabilities

 1,325

 1,395

 Commitments and contingencies (Note 3)

 Members' capital:

 Manager:

 ( 8,470
)

 ( 8,048
)

 Retained earnings

 10,294

 9,866

 Manager's total

 1,824

 1,818

 Shareholders:

 Capital contributions ( 850 shares authorized; 513.1226 issued and outstanding)

 76,006

 76,006

 Syndication costs

 ( 8,675
)

 ( 8,675
)

 ( 47,998
)

 ( 45,607
)

 Accumulated deficit

 ( 16,924
)

 ( 17,599
)

 Shareholders' total

 2,409

 4,125

 Total members' capital

 4,233

 5,943

 Total liabilities and members' capital

 $
 5,558

 $
 7,338

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

 F- 5

 STATEMENTS OF OPERATIONS

 (in thousands, except per share data)

 2023

 2022

 Revenue

 Oil and gas revenue

 $
 3,485

 $
 6,537

 Other revenue

 Total revenue

 3,700

 6,900

 Expenses

 Depletion and amortization

 1,893

 2,503

 Operating expenses

 General and administrative expenses

 Total expenses

 2,665

 3,496

 Income from operations

 1,035

 3,404

 Interest income

 $
 1,103

 $
 3,412

 Manager Interest

 $

 $

 Shareholder Interest

 $

 $
 2,547

 Net income per share

 $
 1,316

 $
 4,964

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

 F- 6

 STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

 (in thousands, except share data)

 # of Shares

 Manager

 Shareholders

 Total

 Balances, December 31, 2021

 -
 513.1226

 $
 1,696

 $
 5,791

 $
 7,487

 -

 ( 743
)

 ( 4,213
)

 ( 4,956
)

 -
 -

 2,547

 3,412

 Balances, December 31, 2022

 -
 513.1226

 $
 1,818

 $
 4,125

 $
 5,943

 -

 ( 422
)

 ( 2,391
)

 ( 2,813
)

 -
 -

 1,103

 Balances, December 31, 2023

 -
 513.1226

 $
 1,824

 $
 2,409

 $
 4,233

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

 F- 7

 STATEMENTS OF CASH FLOWS

 2023

 2022

 Cash flows from operating activities

 $
 1,103

 $
 3,412

 Adjustments to reconcile net income to net cash provided by operating activities:

 Depletion and amortization

 1,893

 2,503

 Accretion expense

 Changes in assets and liabilities:

 Decrease (increase) in production receivable

 ( 43
)

 Decrease in due from affiliate

 Decrease in other current assets

 (Decrease) increase in due to operators

 ( 58
)

 (Decrease) increase in accrued expenses

 ( 81
)

 Settlement of asset retirement obligation

 ( 71
)

 ( 227
)

 Net cash provided by operating activities

 3,038

 5,777

 Cash flows from investing activities

 Capital expenditures for oil and gas properties

 ( 18
)

 ( 443
)

 Proceeds from salvage fund

 Increase in salvage fund

 ( 229
)

 ( 423
)

 Net cash used in investing activities

 ( 126
)

 ( 639
)

 Cash flows from financing activities

 ( 2,813
)

 ( 4,956
)

 Net cash used in financing activities

 ( 2,813
)

 ( 4,956
)

 Net increase in cash and cash equivalents

 Cash and cash equivalents, beginning of year

 Cash and cash equivalents, end of year

 $

 $

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

 F- 8

 NOTES TO FINANCIAL STATEMENTS

 1. Organization and Summary of Significant
Accounting Policies

 Organization

 The Ridgewood Energy V Fund, LLC (the "Fund"),
a Delaware limited liability company, was formed on November 21, 2006 and operates pursuant to a limited liability company agreement (the
"LLC Agreement") dated as of January 3, 2007 by and among Ridgewood Energy Corporation (the "Manager") and the
shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization,
transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The
Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana
and Alabama in the Gulf of Mexico.

 The Manager has direct and exclusive control over
the management of the Fund's operations. The Manager performs, or arranges for the performance of, the management, advisory and
administrative services required for the Fund's operations. Such services include, without limitation, the administration of shareholder
accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of
the Fund's investments in projects. In addition, the Manager provides office space, equipment and facilities and other services
necessary for the Fund's operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories,
accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 2 and 3.

 Use of Estimates

 The preparation of financial statements in accordance
with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the
date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, management
reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of
proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates.

 Fair Value Measurements

 The Fund follows the accounting guidance for fair
value measurement for measuring fair value of assets and liabilities in its financial statements. The fair value measurement guidance
provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest
priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist
of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any,
market activity for the instrument; hence, these inputs have the lowest priority.

 The Fund's financial assets and liabilities
consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, due to operators
and accrued expenses. The carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature.
The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such
as oil and gas properties and asset retirement obligations, on a non-recurring basis.

 Cash and Cash Equivalents

 All highly liquid investments with maturities, when purchased, of three
months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in "Cash and cash equivalents"
on the balance sheet. As of December 31, 2023, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured
limits, which are $ 250 thousand per insured financial institution. As of December 31, 2023, the Fund's bank balances, including
salvage fund, exceeded federally insured limits by $ 2.4 million.

 Salvage Fund

 The Fund deposits cash in a separate interest-bearing
account, or salvage fund, to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning
its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. Interest earned on the
account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

 F- 9

 Oil and Gas Properties

 The Fund invests in oil and gas properties, which
are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms
of the applicable operating agreements with working interest owners. The Fund's portion of exploration, drilling, operating and
capital equipment expenditures is billed by operators.

 Acquisition, exploration and development costs
are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including
lease bonuses, brokers' fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related
production facilities are capitalized. The costs of exploratory wells are capitalized pending determination of whether proved reserves
have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund
receives adjustments to certain wells from their respective operators upon review and audit of the wells' costs. Annual lease rentals
and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts
are expensed as incurred.

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

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

 Accrued Expenses

 Accrued expenses consist of the following:

 Schedule of accrued expenses

 2023

 2022

 Accrued royalty

 $
 -

 $

 Accrued accounting and legal fees

 $

 $

 Asset Retirement Obligations

 For oil and gas properties, there are obligations
to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved
or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the
period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Fund's credit-adjusted
risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently
if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement
obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the
funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years
ended December 31, 2023 and 2022:

 Schedule of changes in asset retirement obligations

 2023

 2022

 Balance, beginning of year

 $
 1,190

 $
 1,164

 Liabilities settled/relieved

 ( 121
)

 ( 227
)

 Accretion expense

 Revision of estimates

 Balance, end of year

 $
 1,209

 $
 1,190

 On September 12, 2023, the Fund entered into a
bill of sale agreement with the operator of the Liberty Project to sell its proportionate ownership in the producer-owned platform facilities
and certain components of the subsea production systems of the project. The agreement relieved the Fund from all abandonment obligations
related to the equipment. As a result, the Fund relieved the remaining asset retirement obligation in the Liberty Project totaling $ 0.1
million.

 F- 10

 During the year ended December 31, 2022, the Fund
recorded depletion expense totaling $ 0.1 million related to adjustments to the asset retirement obligations for fully depleted properties.

 Syndication Costs

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

 Revenue Recognition

 Oil and gas revenues from contracts with customers
are recognized at the point when control of oil and natural gas is transferred to the customers in accordance with Accounting Standard
Codification Topic 606, Revenue from Contracts with Customers ("ASC 606"). The Fund's revenue recognition policies,
performance obligations and significant judgements in applying ASC 606 are described below.

 Oil and Gas Revenue

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

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

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

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

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

 Transaction Price Allocated to Remaining Performance
Obligations

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

 F- 11

 Contract Balances

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

 Other Revenue

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

 Prior Period Performance Obligations

 The Fund records oil and gas revenue in the month
production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to
60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the
purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates
and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue
and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant.
During the years ended December 31, 2023 and 2022, revenue recognized from performance obligations satisfied in previous periods was not
significant.

 Allowance for Credit Losses

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

 Impairment of Long-Lived Assets

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

 There were no impairments of oil and gas properties
during the years ended December 31, 2023 and 2022. Fluctuations in oil and natural
gas commodity prices may impact the fair value of the Fund's oil and gas properties. In addition, significant declines in oil and
natural gas commodity prices could reduce the quantities of reserves that are commercially recoverable, which could result in impairment.

 Depletion and Amortization

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

 F- 12

 Income Taxes

 No provision is made for income taxes in the financial
statements. The Fund is a limited liability company, and as such, the Fund's income or loss is passed through and included in the
tax returns of the Fund's shareholders. The Fund files U.S. Federal and State tax returns and the 2020 through 2022 tax returns
remain open for examination by tax authorities.

 Income and Expense Allocation

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

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

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

 Recent Accounting Pronouncements

 The Fund has considered recent accounting pronouncements
issued during the year ended December 31, 2023 and through the filing of this report, and the Fund has not identified new standards that
it believes will have an impact on the Fund's financial statements.

 2. Related Parties

 Pursuant to the terms of the LLC Agreement, the
Manager is entitled to an annual management fee, payable monthly, of 2.5 % of total capital contributions, net of cumulative dry-hole well
costs incurred by the Fund and fully depleted project investments. During 2015, the Manager waived its management fee for the remaining
life of the Fund. Upon the waiver of the management fee, the Fund began recording costs, totaling $ 20 thousand per quarter, representing
reimbursements to the Manager, related to services provided by the Manager for accounting and investor relations. Such costs, totaling
$ 80 thousand for each of the years ended December 31, 2023 and 2022, are included on the statements of operations within general and administrative
expenses.

 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, 2023 and
2022 were $ 0.4 million and $ 0.7 million, respectively.

 Beta Sales and Transport, LLC

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

 F- 13

 Production Handling, Gathering and Operating
Services Agreement

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

 During each of the years ended December 31, 2023
and 2022, the Fund earned $ 0.1 million, representing its proportionate share of the production handling fees earned from affiliates, which
are included within "Other revenue" on the Fund's statements of operations. As of December 31, 2023 and 2022, the Fund's
receivables of $ 8 thousand and $ 11 thousand, respectively, related to the Fund's proportionate share of revenue from affiliates
are included within "Due from affiliate" on the Fund's balance sheets. The receivables are settled by issuance of a
non-cash credit from the Beta Project operator to the Fund on behalf of the Claiborne Project working interest owners when the operator
performs the joint interest billing of the lease operating expenses due from the Fund. However, if applying the joint interest billing
credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to the Fund.

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

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

 3. Commitments and Contingencies

 Capital Commitments

 As of December 31, 2023, the Fund's estimated
capital commitments related to its oil and gas properties were $ 3.2 million (which include asset retirement obligations for the Fund's
projects of $ 1.9 million), of which $ 0.5 million is expected to be spent during the year ending December 31, 2024. Future results of operations
and cash flows are dependent on the revenues from production and sale of oil and natural gas from the Beta Project. Based upon its current
cash position, salvage fund and its current reserves estimates, the Fund expects cash flow from operations to be sufficient to cover its
commitments and ongoing operations. Reserves estimates are projections based on engineering data that cannot be measured with precision,
require substantial judgment, and are subject to frequent revision.

 Impact from market conditions

 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 price of oil, as well as access to investment capital; (iii) governmental energy
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 directly manage the global supply/demand balance
for crude throughout coordinated output quotas; and (vi) fluctuations in the global purchasing power of the 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 evolving Israel-Hamas conflict as well as acts of terrorism, will continue to dictate oil and natural gas commodity prices. The
impact of these matters on global financial and commodity markets and their corresponding effect on the Fund remains uncertain.

 F- 14

 Environmental and Governmental Regulations

 Many aspects of the oil and gas industry are subject
to federal, state and local environmental laws and regulations. The Manager and operators of the Fund's properties are continually
taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations. However, due to the significant
public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible
future legislation, rule changes, or governmental or private claims. As of December 31, 2023 and 2022, there were no known environmental
contingencies that required adjustment to, or disclosure in, the Fund's financial statements.

 Oil and gas industry legislation and administrative
regulations are periodically changed for a variety of political, economic, and other reasons. Any such future laws and regulations could
result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund's
operating results and cash flows. It is not possible at this time to predict whether such legislation or regulation, if proposed, will
be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund's business.

 BSEE and BOEM Supplemental Financial Assurance
Requirements

 On July 14, 2016, the Bureau of Ocean Energy Management
("BOEM") issued a Notice to Lessees ("NTL 2016-N01") that discontinued and materially replaced existing policies
and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and
natural gas leases and owners of pipeline rights-of-way, rights-of-use and easements on the Outer Continental Shelf ("Lessees").
Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient
financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional
security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver
system with one of self-insurance. The rule became effective as of September 12, 2016, however, the NTL 2016-N01 was not fully implemented.

 On
October 16, 2020, BOEM and the Bureau of Safety and Environmental Enforcement ("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. Upon review of the 2020 joint proposed rule and analysis of public comments, the Secretary of the U.S. Department of
the Interior elected to separate the BOEM and 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 Outer Continental Shelf ("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 to finalize the proposed appeal bonding
requirements in this final rule.

 On June 29, 2023, BOEM published a proposed rule,
that if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements to decommission offshore
wells and infrastructure once they are no longer in use. The proposed rule proposes a simplified test using only two criteria by which
BOEM would determine whether supplemental financial assurance should be required of OCS oil and gas lessees: (1) credit rating, and (2)
the ratio of the value of proved oil and gas reserves of the lease to the 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.

 F- 15

 Insurance Coverage

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

 F- 16

 Information about Oil and Gas Producing Activities

 Ridgewood Energy V Fund, LLC

 Supplementary Financial Information

 Information about Oil and Gas Producing Activities
- Unaudited

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

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

 Schedule of capitalized costs relating to oil and gas producing activities

 2023

 2022

 Proved properties

 $
 21,249

 $
 21,115

 Accumulated depletion and amortization

 ( 18,620
)

 ( 16,702
)

 Oil and gas properties, net

 $
 2,629

 $
 4,413

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

 Schedule of costs incurred in oil and gas property acquisition, exploration, and development

 Year ended December 31,

 2023

 2022

 Development costs

 $

 $

 $

 $

 F- 17

 Table III - Reserve Quantity Information

 Oil and gas reserves of the Fund have been estimated
by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2023 and 2022. These reserve disclosures
have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature
of recovery data, estimates of reserve information are subject to change as additional information becomes available.

 Schedule of reserve quantity information

 December 31, 2023

 December 31, 2022

 United States

 Oil (MBBL)

 NGL (MBBL)

 Gas (MMCF)

 Total (MBOE) (a)

 Oil (MBBL)

 NGL (MBBL)

 Gas (MMCF)

 Total (MBOE) (a)

 Proved developed and undeveloped reserves:

 Beginning of year

 146.5

 12.7

 75.8

 171.8

 212.1

 16.5

 86.0

 243.0

 Revisions of previous estimates (b)

 ( 5.6
)

 4.6

 11.4

 0.9

 ( 0.4
)

 4.0

 31.4

 8.7

 Production

 ( 43.6
)

 ( 5.9
)

 ( 30.8
)

 ( 54.6
)

 ( 65.2
)

 ( 7.8
)

 ( 41.6
)

 ( 79.9
)

 End of year

 97.3

 11.4

 56.4

 118.1

 146.5

 12.7

 75.8

 171.8

 Proved developed reserves:

 Beginning of year

 96.2

 9.3

 55.5

 114.7

 158.7

 12.2

 63.4

 181.5

 End of year

 65.4

 8.2

 40.6

 80.4

 96.2

 9.3

 55.5

 114.7

 Proved undeveloped reserves:

 Beginning of year

 50.3

 3.4

 20.3

 57.1

 53.4

 4.3

 22.6

 61.5

 End of year

 31.9

 3.2

 15.8

 37.7

 50.3

 3.4

 20.3

 57.1

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

 (b)
 Revisions of previous estimates were attributable to well performance. In addition, effective January 1, 2023, the fixed percentage overriding
royalty interest of 11.81% in the Fund's net revenue interest in the Beta Project's oil and natural gas production became
payable to the Fund's former lender, which was conveyed pursuant to the Fund's credit agreement applicable to the project.
The effect of this conveyance in the reserves was included within revision of previous estimates.

 F- 18

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

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

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

 2023

 2022

 Future cash inflows

 $
 7,400

 $
 14,092

 Future production costs

 ( 1,799
)

 ( 3,102
)

 Future development costs

 ( 2,825
)

 ( 3,299
)

 Future net cash flows

 2,776

 7,691

 10% annual discount for estimated timing of cash flows

 ( 28
)

 ( 1,016
)

 Standardized measure of discounted future net cash flows

 $
 2,748

 $
 6,675

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

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

 Schedule of changes in the standardized measure for discounted cash flows

 Year ended December 31,

 2023

 2022

 Net change in sales and transfer prices and in production costs related to future production

 $
 ( 2,086
)

 $
 4,186

 Sales and transfers of oil and gas produced during the period

 ( 3,031
)

 ( 5,826
)

 Changes in estimated future development costs

 ( 647
)

 Net change due to revisions in quantities estimates

 Accretion of discount

 Other

 Aggregate change in the standardized measure of discounted future net cash flows for the year

 $
 ( 3,927
)

 $
 ( 267
)

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