UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549


FORM 10-K


☒

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

OF THE SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended December 31 2017

, 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. 000-53591


Ridgewood Energy X Fund, LLC
(Exact name of registrant as specified in its charter)

Ridgewood Energy X Fund, LLC
(Exact name of registrant as specified in its charter)

Delaware 

26-0870318

(State or other jurisdiction of

incorporation or organization)
 
(I.R.S. Employer

Identification No.)

14 Philips Parkway, Montvale, NJ  07645
(Address of principal executive offices) (Zip code)
(800) 942-5550
(Registrant’s telephone number, including area code)

14 Philips Parkway, Montvale, NJ07645
(Address of principal executive offices) (Zip code)
(800) 942-5550
(Registrant’s telephone number, including area code)

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

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


Shares of LLC Membership Interest


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes  ☐oNo☒


x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     Yes  ☐oNo☒


x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes☒x   No  ☐


o

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


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

o

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


Large accelerated filer☐ ¨Accelerated filer☐ ¨

Non-accelerated filer

(Do not check if a smaller reporting company)

☐ 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. ☐


¨

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

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). ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes  ☐oNo☒


x

There is no market for the shares of LLC Membership Interest in the Fund. As of March 9, 2018February 26, 2024, there were 477.8874 shares of LLC Membership Interest outstanding.

 

RIDGEWOOD ENERGY X FUND, LLC
2017
2023 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

   PAGE
   
PART I   
 ITEM 1
BUSINESS
2
ITEM 1ARISK FACTORS11

ITEM 1B

UNRESOLVED STAFF COMMENTS

11
 ITEM 1A1C
RISK FACTORSCYBERSECURITY
10 11
 ITEM 1B2
UNRESOLVED STAFF COMMENTSPROPERTIES
10 12
 ITEM 23
PROPERTIESLEGAL PROCEEDINGS
10 13
 ITEM 3
LEGAL PROCEEDINGS
11 
ITEM 4
MINE SAFETY DISCLOSURES
11 13
PART II   
 

ITEM 5

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

12 14
 ITEM 6
SELECTED FINANCIAL DATA[RESERVED]
12 14
 ITEM 7
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
12 14
 ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
17 20
 ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
18 20
 ITEM 9
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
18 20
ITEM 9ACONTROLS AND PROCEDURES20

ITEM 9B

OTHER INFORMATION

21
 ITEM 9A9C
CONTROLS AND PROCEDURESDISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
18 21
ITEM 9B
OTHER INFORMATION
18 
PART III   
 ITEM 10
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
19 22
 ITEM 11
EXECUTIVE COMPENSATION
20 23
 ITEM 12
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
20 23
 ITEM 13
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
20 23
 ITEM 14
PRINCIPAL ACCOUNTINGACCOUNTANT FEES AND SERVICES
21 24
PART IV   
 ITEM 15

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

22 25
    
  
SIGNATURES
23 26

Table of Contents
Table of Contents

FORWARD-LOOKING STATEMENTS


Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy X Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections and statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 that1995. Such forward-looking statements are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include the impact on the Fund’s business and operations of any future widespread health emergencies or public health crises such as pandemics and epidemics, weather conditions, such as hurricanes, changes in market and other conditions affecting the pricing, production and demand of oil and natural gas, the cost and availability of equipment, the military 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”.Operations.” Examples of forward-looking statements made herein include statements regarding projects, investments, insurance, capital expenditures and liquidity. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

1
Table of Contents
PART I

1
Table of Contents

PART I

ITEM 1.BUSINESS

Overview


The Fund is a Delaware limited liability company (“LLC”) formed on August 30, 2007 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 2, 2008, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In January 2015, pursuant to the limited liability company agreement (the “LLC Agreement”), Ridgewood Energy Corporation, as manager of the Fund converted all then outstanding Investor GP Shares to Limited Liability Shares.  There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s LLC Agreement and applicable federal and state securities laws. The private placement offering was terminated on April 30, 2008. The Fund raised $94.7 million and after payment of $15.4 million in offering fees, commissions and investment fees, the Fund had $79.3 million for investments and operating expenses.


Manager


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


As compensation for its services, the Manager is entitled to receive an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund.Fund and fully depleted project investments. The Manager is entitled to receive the management fee from the Fund regardless of the Fund’s profitability in that year. Management fees during each of the years ended December 31, 20172023 and 20162022 were $1.1$0.7 million. Additionally, the Manager is entitled to receive a 15% interest inof the cash distributions from operations made by the Fund. Distributions paid to the Manager during each of the years ended December 31, 20172023 and 20162022 were $0.4 million and $0.1 million, respectively.


million.

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.

2
Table of Contents

Business Strategy


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

2

Table of Contents

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


Investment Committee

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


Participation and Joint Operating Agreements

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


Project Information


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


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


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


Royalty Payments

Generally, and depending on the lease, working interest owners of an offshore oil and natural gas lease under the OCSLA pay a royalty of 12.5%, 16.67% or 18.75% to the U.S. Government through the Office of Natural Resources Revenue (“ONRR”). Other than the ONRR royalties, the Fund does not have material royalty burdens.


Deep Gas Royalty Relief
On January 26, 2004, the BOEM promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the “Royalty Relief Rule”). The Fund does not currently have any projects that are eligible for royalty relief under the Royalty Relief Rule.  The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the OCS nor does it apply if the price of natural gas exceeds $11.80 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation.
3

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep Waterthe Deepwater Royalty Relief Act of 1995 (the “Deepwater Royalty Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Royalty Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Fund currently has three projects,one project, the Diller Liberty and Marmalard projects,Project, which areis eligible for royalty relief under the Deepwater Royalty Relief Act. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $37.93$46.19 per barrel and $49.25$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 $4.74$5.77 per mmbtu and $8.21$10.00 per mmbtu) adjusted annually for inflation.

3

Table of Contents

Properties


Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned ana working interest as of December 31, 2017.2023. 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  6   0.09 

   Total Productive Wells 
   Gross   Net 
Oil and natural gas  5   0.04 

Acreage Data

The following table sets forth the Fund’s working interests in developed oil and natural gas acreage as of December 31, 2023. The Fund did not have undeveloped oil and natural gas acreage as of December 31, 2017.2023. 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 
 Gross   Net 
 17,280   148 

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Developed Acres Undeveloped Acres 
Gross Net Gross Net 
 23,040  440  28,800  253 

Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for information regarding the funding of the Fund’s capital commitments.


    Total Spent  Total  
   Working through  Fund  
Project Interest December 31, 2017  Budget Status
    (in thousands)  
Producing Properties            
Diller Project  0.88% $2,768  $3,689 The Diller Project is expected to include the development of two wells.  Well #1 commenced production in 2015.  Well #2 is expected to commence production in 2019. Well #1, which  was shut-in during late-2016 due to well hydrate remediation work, resumed production in mid-January 2017. The Fund expects to spend $0.7 million for additional development costs and $0.2 million for asset retirement obligations.
Liberty Project  5.0% $7,510  $8,171 The Liberty Project, a single-well project, commenced production in 2010.  After being shut-in during early-2016 due to third-party facilities' repair and maintenance activities, the well resumed production in early-May 2016.  The well was shut-in again in late-June 2017 due to gas dehydration unit work, resuming production in late-September 2017. The operator is currently flowing the well's current zone together with the behind-pipe zone at no cost to the Fund.  The Fund expects to spend $0.7 million for asset retirement obligations.
Marmalard Project  0.88% $5,548  $8,242 The Marmalard Project is expected to include the development of six wells.  Four wells commenced production in 2015.  Additional wells are expected to commence production in 2021.  Two wells, which were shut-in during early-December 2017 awaiting replacement of well jumpers, are expected to resume production in second quarter 2018.  The Fund expects to spend $2.2 million for additional development costs and $0.5 million for asset retirement obligations.

     Total Spent  Total   
  Working  through  Fund   
Project Interest  December 31, 2023  Budget  Status
     (in thousands)   
Diller Project  0.88% $3,742  $4,040  The Diller Project includes the development of two wells.  Well #1 and Well #2 commenced production in 2015 and 2019, respectively. One well in the Diller Project, which was shut-in since April 2023 due to a mechanical issue, did not resume production. The operator of the project filed a cessation of production notice with the BOEM with last production date of September 3, 2023. The Fund expects to spend $0.3 million for asset retirement obligations.
Marmalard Project  0.84% $6,876  $9,685  The Marmalard Project is expected to include the development of six wells.  Four wells commenced production in 2015. Well #5 began drilling in late-September 2023 and commenced production in January 2024.  The well is currently shut-in as a result of the cross flow between zones. The operator of the project is currently investigating the next steps to restore production from the well.  Well #6 is expected to commence production in 2025.  The Fund expects to spend $2.0 million for additional development costs and $0.8 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 DH Sales and Transport, LLC (“DH 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 Diller and Marmalard projects. DuringIn 2016, as amended in April 2018 and September 2021, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third partythird-party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2017, the Fund had threehas two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations. The Fund’s current producing projects are near existing transportation infrastructure and pipelines.

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

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Seasonality


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


However, notwithstanding the ability of the Fund’s projects to produce year-round, the Fund’s properties are located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any significant damage, shut-ins, or production stoppages due to hurricane activity in 2017.


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 properties are operated by LLOGMurphy Exploration Offshore, L.L.C.


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

& Production Company – USA.

Insurance


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


Salvage Fund


The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for its proportionate share of the cost of dismantling and removal of production platforms and facilities and plugging and abandoning the wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2017,2023, the Fund has $3.4had $1.3 million invested in a salvage fund. Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.

Competition

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

Employees


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


Offices


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

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Regulation


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


Outer Continental Shelf Lands Act


Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOEM. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. BSEE regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE adopted strict requirements for subsea drilling production equipment and had proposed new requirements to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. BSEE has also published a policy statement on safety culture with nine characteristics of a robust safety culture. In April 2016,May 2019, BSEE adopted a final rule establishing updatedrevising standards for blowout prevention systems and other well controls pertaining to offshore activities (the “Well“2019 Well Control Rule”). The 2019 Well Control Rule became effective July 28, 2016,15, 2019, however compliance with certain provisions iswas deferred until 20182021 or thereafter as specified.specified in those provisions. The 2019 Well Control Rule imposes new requirements relating to, among other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. The 2019 Well Control Rule applies directly to operators as opposed to non-operators. On September 12, 2022, BSEE has alsoannounced 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 policy statement onfinal rule revising regulations relating to oil and natural gas production safety culture with nine characteristics of a robustsystems, subsurface safety culture. In April 2017,devices and safety device testing (referred to as “Subpart H”); the “Presidential Order Implementing an America-First Offshore Energy Strategy”rule was issued, which, among other things, directed the BSEE to review the Well Control Rule.effective December 27, 2018. Given the fact that compliance with the 2019 Well Control Rule and Subpart H is the responsibility of the operators and the exploration and development of each well is different, the future costs associated with compliance that will be incurred by non-operators, such as the Fund, cannot be determined or estimated. On December 4, 2020, BOEM published a Record of Decision (“ROD”) for the final programmatic environmental impact statement for geological and geophysical survey activities in the Gulf of Mexico and adjacent state waters. The ROD provides for additional mitigation measures for application for future BOEM issued permits or authorizations toward further minimizing impacts of such geological and geophysical survey activities on marine resources. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, which civil penalties were increased and adjusted for inflation on March 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 Notice to Lessees on Supplemental Bonding


Financial Assurance Requirements

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

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On October 16, 2020, BOEM and BSEE published a proposed new rule at 85 FR 65904 on January 6, 2017,Risk, Management, Financial Assurance and Loss Prevention, addressing the BOEM announced that itstreamlining 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 suspending the implementation timeline for six months in certain circumstances.  On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of itssignificantly 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 NTL.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 as well as other industry participants, are working withis not able to evaluate the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, if enforced without changeproposed new rule on its operations or amendment, may requirefinancial condition until a final rule is issued or some other definitive action is taken by the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using oneInterior or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.


BOEM.

Sales and Transportation of Oil and Natural Gas


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

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Environmental Matters and Regulation


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


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


Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and was enacted in response to the numerous tanker spills that occurred in the 1980s, including the Exxon Valdez spill, that occurred in the 1980s.spill. Among other things, the OPA clarifies the federal response authority to, and increasesdefines penalties for, such spills. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA, andwith regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $633.85$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 $133.65$167.8 million in other damages for each incident.incident (as of April 14, 2023). These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. A failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on the Fund’s operations or financial condition.

Clean Water Act. Generally, the Clean Water Act, as well as analogous state requirements, imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal or delegated state if applicable, agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. On December 11, 2018, the Environmental Protection Agency (“EPA”) and Department of the Army (“Army”) proposed a revised definition of “waters of the United States” (“WOTUS”), clarifying the limits of federal authority under the Clean Water Act. The scope of this authority, as defined under a 2015 rule, was challenged in several federal district court actions and therefore was repealed by the EPA and the Army on September 12, 2019. The repeal, which became effective on December 23, 2019, restored the previous regulation to how it existed prior to finalization of the 2015 Rule. The 2020 Navigable Waters Protection Rule (“NWPR”) was then promulgated, with a replacement definition of WOTUS, and went into effect on June 22, 2020. A recent executive order revoked a prior executive order related to WOTUS and directed agencies to review certain actions, including the NWPR. On June 9, 2021, the Department of the Army and EPA announced their intent to initiate a new rulemaking process that would both restore a pre-2015 Clean Water Rule and develop a new rule to establish a new WOTUS definition, and then sought feedback from stakeholders. On September 3, 2021, following a court order vacating the NWPR, the Department of the Army and EPA announced that they had halted implementation of the NWPR and would interpret WOTUS consistent with the pre-2015 regulatory regime. On November 18, 2021, the EPA and the Department of the Army announced the signing of a proposed rule to revise the definition of WOTUS. On December 7, 2021, the proposed rule was published in the Federal Register with a 60-day public comment period that closed on February 7, 2022. On December 30, 2022, the EPA and the Department the Army announced a final rule establishing a revised definition of WOTUS that restores the pre-2015 regulatory regime (the “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.

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


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 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.

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


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


On February 3, 2017,

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


Currently, under theFund’s LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. The Dodd-Frank Act mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums.  In addition, as required by the Dodd-Frank Act, the CFTC has set “speculative position limits” (which are limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts.  These requirements under the Dodd-Frank Act could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties.  If as a result of the legislation and regulations, the Fund alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance.  The Fund is not currently, and has not been during 2017,2023, or at any time since 2012, a party to any derivative instruments or hedging programs.
The Dodd-Frank Act also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals.  Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013. On June 27, 2016, the SEC adopted amended resource extraction disclosure rules pursuant to Section 1504 of the Dodd-Frank Act. However, on February 14, 2017, a bill was passed by the United States Congress eliminating the SEC resource extraction disclosure rules. The SEC had one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act. The Fund cannot predict whether the SEC will issue replacement rules or, if it does, whether such rules will remain in effect.

ITEM 1A.RISK FACTORS

Not required.

ITEM 1B.UNRESOLVED STAFF COMMENTS

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.


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UNRESOLVED STAFF COMMENTS

None.

·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 properties that is contained in Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties,” is incorporated herein by reference.


Drilling Activity

During the years ended December 31, 2017 and 2016, the

The Fund had no drilling activity for exploratory orwells during the years ended December 31, 2023 and 2022. The following table sets forth the Fund’s developmental wells.


well drilling activity during the years ended December 31, 2023 and 2022. Gross well is the total number of well in which the Fund has a working interest. Net well is the sum of the Fund’s fractional working interests owned in the gross well. The well, which will produce both oil and natural gas, is located in the offshore waters of the Gulf of Mexico.

  2023  2022 
  Gross  Net  Gross  Net 
Development wells:                
In-progress  1   0.01   -   - 
Development well total  1   0.01   -   - 

Unaudited Oil and Gas Reserve Quantities

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


a third-party independent petroleum engineering firm.

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


The Fund’s reserve estimates as of December 31, 20172023 and 20162022 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.

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


Proved Undeveloped Reserves. As of December 31, 20172023, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 10 thousand barrels of oil, 7 thousand barrels of natural gas liquid (“NGL”) and 2016,0.1 million mcf of natural gas. As of December 31, 2022, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.1 million barrels of oil, 0.1 million48 thousand barrels of natural gas liquid (“NGL”)NGL and 0.50.4 million mcf of natural gas. The Marmalard Project was determined to be a discovery in 2012 and commenced production in 2015.


The decrease in total proved undeveloped reserves at December 31, 2023 was primarily due to: (a) conversion into proved developed reserves, (b) downward revision due to well performance and change in development plans, partially offset by (c) addition of new proved undeveloped reserves from planned recompletions.

The proved undeveloped reserves relating to the Marmalard Project, which were initially assigned at the end of year 2015 and 2023, are associated with future recompletes. During the year ended December 31, 2017,2023, the Fund did not incurincurred costs to advance the development of its proved undeveloped reserves of $1.1 million, related to the Marmalard Project. As a result, proved undeveloped reserves of 0.1 million barrels of oil, 15 thousand barrels of NGL and 0.1 million mcf of natural gas were converted to proved developed reserves at the end of year 2023. The Fund expects additional future operations to be completed in 2029 and 2033 related to the Marmalard Project. The Fund currently expects to develop the proved undeveloped reserves relatingthat have been reported since 2015 are expected to be reclassified to proved developed reserves in 2030 after the Marmalard Project overexisting zone has depleted and the next several years.  rig recompletion is completed to access the zone.

Information regarding estimated future development costs relating to the Marmalard Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”,“Properties,” is incorporated herein by reference. Estimated future development costs include capital spending on planned well recompletions and major development projects, some of which will take several years to complete. Proved undeveloped reserves relatedcomplete due to major development projects will be reclassified to proved developed reserves whenlong life sequential production commences.


and host facility capacity restraints.

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, 20172023 and 20162022 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview”Overview” and “Results of Operations – Operating Expenses”Expenses” is incorporated herein by reference. 


Delivery Commitments

As of December 31, 2017,2023, the Fund had no delivery obligations or delivery commitments under any existing contracts.

ITEM 3.LEGAL PROCEEDINGS

None.

ITEM 4.MINE SAFETY DISCLOSURES

None.


13
Table of ContentsITEM 3. 
LEGAL PROCEEDINGS

None.

ITEM 4. 
MINE SAFETY DISCLOSURES

None.

PART II


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


There is currently no established public trading market for the Shares. As of January 31, 2018,2024, there were 1,3341,390 shareholders of record of the Fund.


Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Due to the future capital required to develop the Diller and Marmalard projects, distributionsDistributions may be impacted by amounts reserved to provideof future capital required for theirthe ongoing development costs andof the Fund’s producing projects, as budgeted, as well as the funding of their 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, 20172023 and 2016,2022, the Fund paid distributions totaling $3.0$2.8 million and $0.9$2.9 million, respectively.


ITEM 6.SELECTED FINANCIAL DATA[RESERVED]

Not required.

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

Overview of the Fund’s Business

The Fund was organized primarily to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of oil and natural gas projects. Distributions to shareholders, if any, are madefunded from available cash from operations, as defined in accordance with the Fund’s LLC Agreement. TheAgreement, and the frequency and amount of such distributions are within the Manager’s discretion, subject to available cash flow from operations.discretion. The Fund’s remaining capital has been fully allocated to its projects. Asinvested and as a result, the Fund will not invest in any new projects.


projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.

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


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. DeclinesSignificant declines in oil and natural gas commodity prices not only reduce revenues and profits but could also reduce the quantities of reserves that are commercially recoverable.  Significant declines in prices couldrecoverable and result in non-cash charges to earnings due to impairment.impairment and higher depletion rates.

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Oil and natural gas commodity prices have been subject to significant fluctuationsvolatility during the past several years.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 Fund’s projects. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. The Fund continueswill continue to conserveclosely manage and coordinate its capital spending estimates within its expected cash flows to provide for the additionalfuture development costs for the Diller and Marmalardof its producing projects, as budgeted. See “Results“Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 20172023 and 2016.  If oil2022 and natural gasthe effect of such average prices decline, even if only for a short period of time,on the Fund’s results of operations and liquidity will be adversely impacted.

operations.

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


·worldwide economic, political and social conditions impacting the global supply and demand for oil and natural gas, which may be driven by various risks, including war (such as the invasion of Ukraine by Russia 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;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 followingis a discussion of the accounting policies and estimates the Fund believes have had or are most significant.reasonably likely to have a material impact on the Fund’s financial position or results of operations.

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Accounting for Acquisition, Exploration and Development Costs
Acquisition, exploration and development costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized.  Costs of drilling and equipping productive wells and related production facilities are capitalized. Annual lease rentals and exploration expenses are expensed as incurred.

Proved Reserves

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

Asset Retirement Obligations

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


Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties annually and when management determines thatfor impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable.  Impairments are determinedRecoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the assetoil and gas properties is impaired, and written down to fair value. Fair value which is determined using estimated future net discounted cash flows from the asset.valuation techniques that include both market and income approaches and use Level 3 inputs.  The fair value determinations require considerable judgment and are sensitive to change.  Different pricing assumptions, reserve estimates of oil and natural gas reserves and future development costs or discount rates could result in a different calculatedsignificant impact on the amount of impairment.  Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of future net discounted cash flows from proved oil and natural gas reserves could change in the near term.

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Results of Operations


The following table summarizes the Fund’s results of operations during the years ended December 31, 20172023 and 2016,2022, 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 ReportReport.

  Year ended December 31, 
  2023  2022 
  (in thousands) 
Revenue      
Oil and gas revenue $3,573  $4,550 
Expenses        
Depletion and amortization  349   359 
Operating expenses  545   561 
Management fees to affiliate  713   719 
General and administrative expenses  174   143 
Total expenses  1,781   1,782 
Income from operations  1,792   2,768 
Other income        
Dividend income  23   23 
Interest income  195   30 
Total other income  218   53 
Net income $2,010  $2,821 

Overview.


    Year ended December 31, 
  2017  2016 
    (in thousands) 
Revenue      
Oil and gas revenue $6,818  $5,045 
Expenses        
Depletion and amortization  1,346   2,017 
Management fees to affiliate  1,066   1,083 
Operating expenses  1,732   2,819 
General and administrative expenses  181   154 
Total expenses  4,325   6,073 
Income (loss) from operations  2,493   (1,028)
Other income (loss)        
Loss on investment in Delta House  -   (114)
Dividend income  26   191 
Interest income  15   9 
Total other income  41   86 
Net income (loss) $2,534  $(942)
Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 20172023 and 2016.2022. NGL sales are included within gas sales.

  Year ended December 31, 
  2017  2016 
Number of wells producing  6   6 
Total number of production days  1,872   1,779 
Oil sales (in thousands of barrels)  113   106 
Average oil price per barrel $52  $41 
Gas sales (in thousands of mcfs)  302   251 
Average gas price per mcf $3.21  $2.36 

  Year ended December 31, 
  2023  2022 
Number of wells producing  6   6 
Total number of production days  1,892   1,795 
Oil sales (in thousands of barrels)  43   41 
Average oil price per barrel $77  $97 
Gas sales (in thousands of mcfs)  89   79 
Average gas price per mcf $2.86  $7.12 

The production related increases noted in the table above table were primarily relatedattributable to one well in the Marmalard Project, which was shut-in for the majority of first quarter 2022 due to a mechanical issue. The well returned to production in early-March 2022. These increases were partially offset by one well in the Diller Project, which was shut-in during late-2016, coupled with the Liberty Project, which was shut-in during early-2016.  In addition, the increase in gas sales was also attributableearly-April 2023 due to the Marmalard Project, whicha mechanical issue. The well did not produce NGLs during the second half of 2016, while awaiting third-party facilities’ repair and maintenance activities. These increases were partially offset by two wells in the Marmalard Project, which were shut-in during early-December 2017, while awaiting replacement of well jumpers.  resume production.

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


information.

Oil and Gas Revenue. Generally, the Fund sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. In the first type of agreement, or a netback agreement, the Fund receives a price, net of transportation expense incurred by the purchaser, and the Fund records revenue at the net price received. In the second type of agreement, the Fund pays transportation expense directly, and transportation expense is included within operating expenses in the statements of operations.


Oil and gas revenue during the year ended December 31, 20172023 was $6.8$3.6 million, an increasea decrease of $1.8$1.0 million from the year ended December 31, 2016.2022. The increasedecrease was attributable to increaseddecreased oil and gas prices totaling $1.4$1.2 million, coupled withpartially offset by increased sales volume totaling $0.4$0.2 million.

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


Depletion and Amortization. Depletion and amortization during the year ended December 31, 20172023 was $1.3$0.3 million, a decrease of $0.7 million$10 thousand from the year ended December 31, 2016.2022. The decrease was attributable to a decrease in the average depletion rate totaling $0.5 million coupled with an adjustment$17 thousand and adjustments to the asset retirement obligationobligations related to a fully depleted propertyproperties totaling $0.3 million,$13 thousand, partially offset by an increase in production volumes totaling $0.2 million.$20 thousand. The decrease in the average depletion rate was primarily attributable to the lower cost of reserves from the Marmalard Project.�� Depletion and amortization rates were also impacted by changes in reservereserves estimates provided annually by the Fund’s independent petroleum engineers.

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


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

  Year ended December 31, 
  2023  2022 
  (in thousands) 
Lease operating expense $317  $317 
Transportation and processing expense  100   163 
Workover expense  61   14 
Insurance expense  43   40 
Accretion expense and other  24   27 
  $545  $561 

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

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, were $0.5 million ($8.01 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2023, compared to $0.5 million ($9.56 per BOE) during the year ended December 31, 2022.

Production costs were relatively consistent during the year ended December 31, 2023 compared to the year ended December 31, 2022.

The decrease in production costs per BOE during the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily attributable to the Diller and Marmalard projects as a result of the termination of the fixed lateral fees effective August 2022 through the end of the projects' productive lives. The fixed lateral fees, which were contractually payable for the use of the facility terminated in August 2022, seven years from the date all anchor producers had delivered first production to the Delta House production facility. In addition, one well in the Marmalard Project was shut-in for the majority of first quarter 2022 due to a mechanical issue.

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

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


Operating Expenses.  Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.
  Year ended December 31, 
  2017  2016 
  (in thousands) 
Lease operating expense $1,065  $2,268 
Transportation and processing expense  397   322 
Workover expense  145   121 
Accretion expense  65   64 
Insurance expense  56   56 
Other  4   (12)
  $1,732  $2,819 
Lease operating expense and transportation and processing expense relates to the Fund’s producing properties.  Workover expense, which represents costs to restore or stimulate production of existing reserves, primarily relates to the Diller and Marmalard projects.  Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties. Insurance expense represents premiums related to the Fund’s properties, which vary depending upon the number of wells producing or drilling.

The average production cost, which includes lease operating expense, transportation and processing expense and insurance expense, was $9.31 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2017 compared to $17.87 per BOE during the year ended December 31, 2016.  The decrease was primarily attributable to the Diller and Marmalard projects, which had lower cost per BOE in 2017 as a result of a reduction in production handling fees from $15.50 per BOE to $4.50 per BOE effective December 2016. The production handling fees for the Diller and Marmalard projects decline over time as certain production hurdles are met in accordance with their production handling agreement relating to the Delta House production facility.

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.


Loss on Investment in Delta House. During the year ended December 31, 2016, the Fund recognized a loss on investment of $0.1 million related to its investment in Delta House.  There were no such amounts recorded during the year ended December 31, 2017. 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 more information regarding the Investment in Delta House.

Dividend Income.  Dividend income is related to the Fund’s investment in Delta House.


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, 20172023 were $3.4$2.4 million, primarily related to revenue received of $6.5$3.7 million and interest income received of $0.2 million, partially offset by management fees of $0.7 million, operating expenses of $1.7$0.6 million, management feesinclusive of $1.1the payment of $0.1 million related to the settlementFund’s proportionate share of an asset retirement obligationthe plug and abandonment for two fully depleted properties pursuant to a bill of $0.2 millionsale agreement executed on September 12, 2023 with the wells’ operator, and general and administrative expenses of $0.2 million.

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Cash flows provided by operating activities during the year ended December 31, 20162022 were $0.5$3.1 million, primarily related to revenue received of $4.9 million and dividend income received of $0.2$4.4 million, partially offset by management fees of $0.7 million, operating expenses of $2.9 million, management fees of $1.1 million, the settlement of an asset retirement obligation of $0.5$0.6 million and general and administrative expenses of $0.1 million.


Investing Cash Flows

Cash flows provided byused in investing activities during the year ended December 31, 20172023 were $0.2$1.5 million, primarily related to capital expenditures for oil and gas properties of $1.2 million, inclusive of advances, and investments in salvage fund of $0.4 million, partially offset by proceeds from the salvage fund.


fund of $0.1 million.

Cash flows provided byused in investing activities during the year ended December 31, 20162022 were $0.8 million, primarily$21 thousand, related to proceeds frominvestments in salvage fund of $0.4 million coupled with$26 thousand and capital expenditures for oil and gas properties of $9 thousand, partially offset by proceeds from the salesalvage fund of investment in Delta House of $0.3 million.


$14 thousand.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 20172023 were $3.0$2.8 million, related to manager and shareholder distributions.


Cash flows used in financing activities during the year ended December 31, 20162022 were $0.9$2.9 million, related to manager and shareholder distributions.

Estimated

Capital Expenditures


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


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

Such investment activities, which include estimated capital spending on planned well recompletions and ongoing development of the Fund’s producing projects, 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, 2017,2023, the Fund’s estimated capital commitments related to its oil and gas properties were $4.4$3.2 million (which include asset retirement obligations for the Fund’s projects of $1.5$1.2 million), of which $0.9$0.1 million is expected to be spent during the year ending December 31, 2018, primarily related to2024. Future results of operations and cash flows are dependent on the settlementrevenues from production and sale of asset retirement obligations for certain ofoil and gas from the Fund’s producing projects. In addition, cash flow from operations may be impacted by fluctuations in oil and natural gas commodity prices. Based upon its current cash position, salvage fund and its current reservereserves estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations. ReserveReserves estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.


The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive all or a portion of the management fee at its own discretion.


Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. Due to the future capital required to develop the Diller and Marmalard projects,However, distributions may be impacted by amounts reserved to provideof future capital required for theirthe ongoing development costs andof the Fund’s producing projects, as budgeted, as well as the funding theirof estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices.

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Off-Balance Sheet Arrangements

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

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, 20172023 and 2016,2022, other than those discussed in “Estimated Capital“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 recent accounting pronouncements.


financial statements.

ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302302(b) of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits and Financial Statement Schedules” and filed as part of this report.


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

None.

None.

ITEM 9A.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2017.2023. 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)15d-15(f)).  The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.


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


Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2017.2023.  In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2017,2023, 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.

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Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund havehas concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 20172023 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.


ITEM 9B.OTHER INFORMATION

None.
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.

PART III

21
Table of Contents

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages as of December 31, 20172023 are as follows:

Name, Age and Position with Registrant

 

Robert E. Swanson, 70

76

Chief Executive Officer

(1)

 

Kenneth W. Lang, 63

69

President and Chief Operating Officer

(1)

 

Kathleen P. McSherry, 52

58

Chief Executive Officer and Executive Vice President, and Chief Financial Officer

and Assistant Secretary (2)

 
Robert L. Gold, 59
  Executive

Daniel V. Gulino, 63

Senior Vice President

- Legal and Secretary

 
Daniel V. Gulino, 57
  Senior

Maria E. Haggerty, 53

Chief Compliance Officer and Vice President General Counsel– Legal (3)

(1)Effective February 22, 2024, Mr. Swanson and SecretaryMr. 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 August 30, 2007, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009.2009, and Ms. Haggerty, who was appointed as an officer of the Fund on February 22, 2024. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:


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


Effective February 22, 2024, Mr. Swanson retired from his role as CEO and PEO of the Fund.

Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. 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. After twenty-four years of service to BP,Effective February 22, 2024, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests.  Mr. Lang is a graduatefrom his role as an executive officer of the University of Houston.


Fund.

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


Robert L. Gold has served as a senior officer of Ridgewood Energy since 1987 and is a member The Manager of the Investment Committee.  Mr. Gold has also servedFund appointed Ms. McSherry as the PresidentCEO and Chief ExecutivePEO 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 Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.Fund.

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Table of Contents

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


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: General Counsel.


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

Legal Department.

ITEM 11.EXECUTIVE COMPENSATION

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


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


Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 477.8874 shares outstanding as of January 31, 2018.2024. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.


ITEM 13.13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pursuant to the terms of the LLC Agreement, the Manager renders management, advisory and administrative services to the Fund. For such services, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.Fund and fully depleted project investments. In addition, the Manager is permitted to reduce the management fee with capital in reserve for future capital expenditures.  In first quarter 2020, the Fund reduced its management fee with capital in reserve for future capital expenditures until such time the capital is attributed to a project.  Management fees during each of the years ended December 31, 20172023 and 20162022 were $1.1$0.7 million.


The Manager is also entitled to receive a 15% interest inof the cash distributions from operations made by the Fund. Distributions paid to the Manager during each of the years ended December 31, 20172023 and 2016 2022 were $0.4 million and $0.1 million, respectively.million.

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Table of Contents

DH 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 Diller and Marmalard projects.  DuringIn 2016, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interestsas amended in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third party purchasers.  Pursuant to the master agreement, DH 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 DH 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 Diller and Marmalard projects. 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 Diller and Marmalard projects.


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

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

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

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 2017 and 2016.

  Year ended December 31, 
  2017  2016 
  (in thousands) 
Audit fees (1)
 $89  $88 

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

ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1)     Financial Statements

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

(a) (2)     Financial Statement Schedules

None.

(a) (3)    

EXHIBIT
NUMBER
TITLE OF EXHIBIT
METHOD OF FILING
3.1
Certificate of Formation of Ridgewood Energy X Fund, LLC dated August 30, 2007
Incorporated by reference to the Fund's Form 10 filed on March 5, 2009
3.2
Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy X Fund, LLC dated April 13, 2011
Incorporated by reference to the Fund's Form 10Q filed on May 3, 2011
31.1
Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
Filed herewith
31.2
Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
Filed herewith
32
Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund
Filed herewith
99.1
Report of Netherland, Sewell & Associates, Inc.
Filed herewith
101.INSXBRL Instance DocumentFiled herewith
101.SCHXBRL Taxonomy Extension SchemaFiled herewith
101.CALXBRL Taxonomy Extension Calculation LinkbaseFiled  herewith
101.DEFXBRL Taxonomy Extension Definition Linkbase DocumentFiled herewith
101.LABXBRL Taxonomy Extension Label LinkbaseFiled herewith
101.PREXBRL Taxonomy Extension Presentation LinkbaseFiled herewith

SIGNATURES

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

RIDGEWOOD ENERGY X FUND, LLC
Date:  March 9, 2018By:/s/ ROBERT E. SWANSON
Robert E. Swanson
Chief Executive Officer
(Principal Executive Officer)

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

Signature
Capacity
Date
/s/ ROBERT E. SWANSONChief Executive OfficerMarch 9, 2018
Robert E. Swanson  (Principal Executive Officer)
/s/ KATHLEEN P. MCSHERRYExecutive Vice President and Chief Financial OfficerMarch 9, 2018
Kathleen P. McSherry  (Principal Financial and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION 
BY:  /s/ ROBERT E. SWANSONChief Executive Officer of the ManagerMarch 9, 2018
Robert E. Swanson
INDEX TO FINANCIAL STATEMENTSPAGE
Report of Independent Registered Public Accounting Firm
F-2 
Balance Sheets as of December 31, 2017 and 2016
F-3 
Statements of Operations for the years ended December 31, 2017 and 2016
F-4 
Statements of Changes in Members' Capital for the years ended December 31, 2017 and 2016
F-5 
Statements of Cash Flows for the years ended December 31, 2017 and 2016
F-6 
Notes to Financial Statements
F-7 
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited
F-12 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Manager of Ridgewood Energy X Fund, LLC:

Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ridgewood Energy X Fund, LLC (the "Fund") as of December 31, 2017 and 2016, the related statements of operations, changes in members’ capital, and cash flows, for each of the two years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on the Fund's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (Untied States) (PCAOB) and are required to be independent with respect to the Fund in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Fund’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 /s/ Deloitte & Touche LLP

Parsippany, New Jersey
March 9, 2018
We have served as the Fund's auditor since 2008.

RIDGEWOOD ENERGY X FUND, LLC
BALANCE SHEETS
(in thousands, except share data)
     December 31, 
  2017  2016 
Assets      
Current assets:      
Cash and cash equivalents $7,944  $7,337 
Salvage fund  833   664 
Production receivable  728   419 
Other current assets  45   108 
Total current assets  9,550   8,528 
Salvage fund  2,609   2,881 
Investment in Delta House  119   119 
Oil and gas properties:        
Proved properties  16,452   17,031 
Less:  accumulated depletion and amortization  (12,241)  (10,541)
Total oil and gas properties, net  4,211   6,490 
Total assets $16,489  $18,018 
         
Liabilities And Members' Capital        
Current liabilities:        
Due to operators $274  $348 
Accrued expenses  68   82 
Asset retirement obligations  833   664 
Total current liabilities  1,175   1,094 
Asset retirement obligations  209   1,373 
Total liabilities  1,384   2,467 
Commitments and contingencies (Note 3)        
Members' capital:        
Manager:        
Distributions  (5,513)  (5,066)
Retained earnings  4,682   4,106 
Manager's total  (831)  (960)
Shareholders:        
Capital contributions (500 shares authorized;        
477.8874 issued and outstanding)  94,698   94,698 
Syndication costs  (11,080)  (11,080)
Distributions  (33,417)  (30,884)
Accumulated deficit  (34,265)  (36,223)
Shareholders' total  15,936   16,511 
Total members' capital  15,105   15,551 
Total liabilities and members' capital $16,489  $18,018 
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
    Year ended December 31, 
  2017  2016 
Revenue      
Oil and gas revenue $6,818  $5,045 
Expenses        
Depletion and amortization  1,346   2,017 
Management fees to affiliate (Note 2)  1,066   1,083 
Operating expenses  1,732   2,819 
General and administrative expenses  181   154 
Total expenses  4,325   6,073 
Income (loss) from operations  2,493   (1,028)
Other income (loss)        
Loss on investment in Delta House  -   (114)
Dividend income  26   191 
Interest income  15   9 
Total other income  41   86 
Net income (loss) $2,534  $(942)
         
Manager Interest        
Net income $576  $163 
         
Shareholder Interest        
Net income (loss) $1,958  $(1,105)
Net income (loss) per share $4,098  $(2,312)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(in thousands, except share data)

   # of Shares  Manager  Shareholders  Total 
Balances, December 31, 2015  477.8874  $(993) $18,354  $17,361 
Distributions  -   (130)  (738)  (868)
Net income (loss)  -   163   (1,105)  (942)
Balances, December 31, 2016  477.8874   (960)  16,511   15,551 
Distributions  -   (447)  (2,533)  (2,980)
Net income  -   576   1,958   2,534 
Balances, December 31, 2017  477.8874  $(831) $15,936  $15,105 
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
     Year ended December 31, 
  2017  2016 
       
Cash flows from operating activities      
Net income (loss) $2,534  $(942)
Adjustments to reconcile net income (loss) to net cash        
   provided by operating activities:        
Depletion and amortization  1,346   2,017 
Accretion expense  65   64 
Loss on investment in Delta House  -   114 
Changes in assets and liabilities:        
Increase in production receivable  (309)  (129)
Decrease (increase) in other current assets  63   (107)
Decrease in due to operators  (74)  (8)
(Decrease) increase in accrued expenses  (14)  16 
Settlement of asset retirement obligation  (205)  (521)
Net cash provided by operating activities  3,406   504 
         
Cash flows from investing activities        
Credits for oil and gas properties  78   36 
Proceeds from sale of investment in Delta House  -   339 
Decrease in salvage fund  103   376 
Net cash provided by investing activities  181   751 
         
Cash flows from financing activities        
Distributions  (2,980)  (868)
Net cash used in financing activities  (2,980)  (868)
         
Net increase in cash and cash equivalents  607   387 
Cash and cash equivalents, beginning of year  7,337   6,950 
Cash and cash equivalents, end of year $7,944  $7,337 
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
NOTES TO FINANCIAL STATEMENTS
1.   Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 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 Fund 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 Fund 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, the Manager 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 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.

Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents.  These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2017, 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, 2017, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

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

Investment in Delta House
The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by LLOG Exploration Offshore, L.L.C. The Fund accounts for its investment in Delta House using the cost method of accounting for investments as it does not have the ability to exercise significant influence over such investment.  Under the cost method, the Fund recognizes an investment in the equity of an investee at cost.   The Fund reviews its cost method investment for impairment at each reporting period and when an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment. Losses on cost method investments including impairments that are deemed to be other than temporary are classified as non-operating losses in the Fund’s statements of operations. During the year ended December 31, 2017, there were no such events or changes in circumstances that indicate that the Fund’s investment in Delta House is impaired.
As of December 31, 2016, the Fund invested a total of $0.6 million in Delta House and had received cash from its investment totaling $0.6 million, of which $0.3 million relates to dividends received and $0.3 million relates to cash proceeds from the sale of approximately 74% of its investment pursuant to a unit purchase agreement with D-Day Offshore Holdings, LLC dated October 31, 2016. Certain other funds managed by the Manager were also parties to this unit purchase agreement. The Fund adjusted the carrying value of its investment in Delta House to fair value, which was determined based on the third-party sale and recorded a $0.1 million loss on investment during the year ended December 31, 2016. The loss was included on the Fund’s statement of operations within “Loss on investment in Delta House”. There was no such amount recorded during the year ended December 31, 2017.  Inputs used to estimate fair value of the investment in Delta House are categorized as Level 3 in the fair value hierarchy.

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

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

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

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

Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  Bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2017 and 2016.
  2017  2016 
  (in thousands) 
Balance, beginning of year $2,037  $2,525 
Liabilities settled  (205)  (521)
Accretion expense  65   64 
Revision of estimates  (855)  (31)
Balance, end of year $1,042  $2,037 
During the year ended December 31, 2017, the Fund recorded credits to depletion expense totaling $0.3 million, which related to an adjustment to the asset retirement obligation for a fully depleted property. As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.
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 and Imbalances
Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Fund uses the sales method of accounting for gas production imbalances.  The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties.  These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production.  The Fund’s recorded liability, if any, would be reflected in other liabilities.  No receivables are recorded for those wells where the Fund has taken less than its share of production.

Impairment of Long-Lived Assets
The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset.  The fair value determinations require considerable judgment and are sensitive to change.  Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.  Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of future net discounted cash flows from proved oil and natural gas reserves could change in the near term.

Fluctuations in oil and natural gas prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

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

Income Taxes
No provision is made for income taxes in the financial statements.  The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.  The Fund files U.S. Federal and State tax returns and the 2014 through 2016 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.

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

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

Recent Accounting Pronouncements
In January 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that requires, among other things, companies to measure investments in other entities, except those accounted for under the equity method, at fair value and recognize any changes in fair value in net income unless an election is made to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. This pronouncement was effective for the Fund in the first quarter of 2018. Early adoption was not permitted. The Fund adopted the accounting guidance on January 1, 2018 and it did not have an impact on its financial statements.
In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance.  The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Under the new accounting guidance, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with its current revenue recognition model.  The Fund adopted the new accounting guidance using the modified retrospective method on January 1, 2018.  Although the Fund did not identify changes to its revenue recognition that resulted in a material cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance will result in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue recognition accounting guidance.

2.   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 and related well costs incurred by the Fund.  In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Therefore, the management fee may be temporarily waived to accommodate the Fund’s short-term capital commitments. Management fees during each of the years ended December 31, 2017 and 2016 were $1.1 million.

The Manager is also entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager during the years ended December 31, 2017 and 2016 were $0.4 million and $0.1 million, respectively.

DH Sales and Transport, LLC (“DH 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 Diller and Marmalard projects. In 2016,September 2021, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third-party purchasers.  Pursuant to the master agreement, DH 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 DH 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 Diller and Marmalard projects. 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 Diller and Marmalard projects.

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


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

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

ITEM 14.PRINCIPAL 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.

  Year ended December 31, 
  2023  2022 
  (in thousands) 
Audit fees (1) $79  $79 

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

24

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PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1)     Financial Statements

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

(a) (2)     Financial Statement Schedules

None.

(a) (3)    

EXHIBIT

NUMBER

TITLE OF EXHIBIT

METHOD OF FILING

3.1Certificate of Formation of Ridgewood Energy X Fund, LLC dated August 30, 2007Incorporated by reference to the Fund's Form 10 filed on March 5, 2009

3.2

Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy X Fund, LLC dated April 13, 2011Incorporated by reference to the Fund's Form 10-Q filed on May 3, 2011
4Description of SharesIncorporated by reference to the Fund’s Form 10-K filed on March 3, 2020
31.1Certification 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)Filed herewith
32Certification 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 FundFiled herewith
99.1Report of Netherland, Sewell & Associates, Inc.Filed herewith
101.INSInline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL documentFiled herewith
101.SCHInline XBRL Taxonomy Extension SchemaFiled herewith
101.CALInline XBRL Taxonomy Extension Calculation LinkbaseFiled herewith
101.DEFInline XBRL Taxonomy Extension Definition Linkbase DocumentFiled herewith
101.LABInline XBRL Taxonomy Extension Label LinkbaseFiled herewith

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase

Filed herewith

104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)Filed herewith

25
3.   Commitments
Table of Contents

SIGNATURES

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

RIDGEWOOD ENERGY X FUND, LLC
Date:  February 26, 2024By:/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 Contingenciesin the capacities and on the dates indicated.

SignatureCapacityDate
/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. HAGGERTYChief Compliance Officer and Vice President - LegalFebruary 26, 2024
Maria E. Haggerty   of the Manager

26

Table of Contents

INDEX TO FINANCIAL STATEMENTSPAGE
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)F-2
Balance Sheets as of December 31, 2023 and 2022F-5
Statements of Operations for the years ended December 31, 2023 and 2022F-6
Statements of Changes in Members' Capital for the years ended December 31, 2023 and 2022F-7
Statements of Cash Flows for the years ended December 31, 2023 and 2022F-8
Notes to Financial StatementsF-9
Supplementary Financial Information - Information about Oil and Gas Producing Activities - UnauditedF-16

F-1
Capital Commitments
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Ridgewood Energy X 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. Also, the Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value.

F-2
Table of Contents

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

The Fund’s oil and gas properties, net balance was $3.0 million as of December 31, 2023 and depletion and amortization expense recognized was $0.3 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:

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

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

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

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

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

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

F-3
Table of Contents

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

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

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

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

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

/s/ Deloitte & Touche LLP

Morristown, New Jersey

February 26, 2024

We have served as the Fund's auditor since 2008. 

F-4
Table of Contents

RIDGEWOOD ENERGY X FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

         
  December 31, 
  2023  2022 
Assets      
Current assets:      
Cash and cash equivalents $6,969  $8,831 
Salvage fund  -   100 
Production receivable  272   392 
Other current assets  12   20 
Total current assets  7,253   9,343 
Salvage fund  1,301   909 
Investment in Delta House  119   119 
Oil and gas properties:        
Advances to operators for capital expenditures  103   - 
Proved properties  10,750   9,508 
Less: accumulated depletion and amortization  (7,896)  (7,541)
Total oil and gas properties, net  2,957   1,967 
Total assets $11,630  $12,338 
         
Liabilities and Members' Capital        
Current liabilities:        
Due to operators $70  $102 
Accrued expenses  47   61 
Asset retirement obligations  -   100 
Total current liabilities  117   263 
Due to operators  47   - 
Asset retirement obligations  489   350 
Total liabilities  653   613 
Commitments and contingencies (Note 3)        
Members' capital:        
Manager:        
Distributions  (8,107)  (7,694)
Retained earnings  7,152   6,826 
Manager's total  (955)  (868)
Shareholders:        
Capital contributions (500 shares authorized; 477.8874 issued and outstanding)  94,698   94,698 
Syndication costs  (11,080)  (11,080)
Distributions  (48,117)  (45,772)
Accumulated deficit  (23,569)  (25,253)
Shareholders' total  11,932   12,593 
Total members' capital  10,977   11,725 
Total liabilities and members' capital $11,630  $12,338 

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

F-5
Table of Contents

RIDGEWOOD ENERGY X FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

         
  Year ended December 31, 
  2023  2022 
Revenue      
Oil and gas revenue $3,573  $4,550 
Expenses        
Depletion and amortization  349   359 
Operating expenses  545   561 
Management fees to affiliate (Note 2)  713   719 
General and administrative expenses  174   143 
Total expenses  1,781   1,782 
Income from operations  1,792   2,768 
Other income        
Dividend income  23   23 
Interest income  195   30 
Total other income  218   53 
Net income $2,010  $2,821 
         
Manager Interest        
Net income $326  $473 
         
Shareholder Interest        
Net income $1,684  $2,348 
Net income per share $3,524  $4,913 

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

F-6
Table of Contents

RIDGEWOOD ENERGY X FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

                 
  # of Shares  Manager  Shareholders  Total 
Balances, December 31, 2021  -477.8874  $(899) $12,750  $11,851 
Distributions  --   (442)  (2,505)  (2,947)
Net income  --   473   2,348   2,821 
Balances, December 31, 2022  -477.8874  $(868) $12,593  $11,725 
Distributions  --   (413)  (2,345)  (2,758)
Net income  --   326   1,684   2,010 
Balances, December 31, 2023  -477.8874  $(955) $11,932  $10,977 

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

F-7
Table of Contents

RIDGEWOOD ENERGY X FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

         
  Year ended December 31, 
  2023  2022 
       
Cash flows from operating activities      
Net income $2,010  $2,821 
Adjustments to reconcile net income to net cash provided by operating activities:        
Depletion and amortization  349   359 
Accretion expense  24   11 
Changes in assets and liabilities:        
Decrease (increase) in production receivable  120   (110)
Decrease in other current assets  8   - 
Decrease in due to operators  (85)  (4)
Decrease in accrued expenses  (14)  (2)
Credit from (settlement of) asset retirement obligations  7   (14)
Net cash provided by operating activities  2,419   3,061 
         
Cash flows from investing activities        
Advance payments to operators for capital expenditures for oil and gas properties  (103)  - 
Capital expenditures for oil and gas properties  (1,128)  (9)
Proceeds from salvage fund  93   14 
Increase in salvage fund  (385)  (26)
Net cash used in investing activities  (1,523)  (21)
         
Cash flows from financing activities        
Distributions  (2,758)  (2,947)
Net cash used in financing activities  (2,758)  (2,947)
         
Net (decrease) increase in cash and cash equivalents  (1,862)  93 
Cash and cash equivalents, beginning of year  8,831   8,738 
Cash and cash equivalents, end of year $6,969  $8,831 

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

F-8
Table of Contents

RIDGEWOOD ENERGY X FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 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, production receivable, other current assets, salvage fund, investment in Delta House, due to operators and accrued expenses. Except for investment in Delta House, the carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. The Fund’s investment in Delta House is valued using the measurement alternative for investment in other entities (see Investment in Delta House below for additional information). 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, 2017,2023, 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 $8.2 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
Table of Contents

Investment in Delta House

The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by Murphy Exploration & Production Company - USA. The investment in Delta House is valued using the measurement alternative to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. At each reporting period, the Fund reviews its investment in Delta House to evaluate whether the investment is impaired. During the years ended December 31, 2023 and 2022, there were no impairments of the Fund’s investment in Delta House.

Oil and Gas Properties

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

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

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

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

Asset Retirement Obligations

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

Schedule of changes in asset retirement obligations        
  Year ended December 31, 
  2023  2022 
  (in thousands) 
Balance, beginning of year $450  $351 
Liabilities incurred  34   - 
Liabilities settled/relieved  (93)  (14)
Accretion expense  24   11 
Revision of estimates  74   102 
Balance, end of year $489  $450 

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On September 12, 2023, the Fund entered into a bill of sale agreement with the operator of the Liberty and Carrera projects 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 obligations in the Liberty and Carrera projects totaling $0.1 million.

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.

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Transaction Price Allocated to Remaining Performance Obligations

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

Contract Balances

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

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.

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.

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Distributions

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

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

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements issued during the year ended December 31, 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 receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments, however, the Manager is permitted to waive all or a portion of the management fee at its own discretion. Therefore, all or a portion of the management fee may be temporarily waived to accommodate the Fund’s short-term commitments. In addition, the Manager is permitted to reduce the management fee with capital in reserve for future capital expenditures.  In first quarter 2020, the Fund reduced its management fee with capital in reserve for future capital expenditures until such time the capital is attributed to a project.  Management fees during each of the years ended December 31, 2023 and 2022 were $0.7 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during each of the years ended December 31, 2023 and 2022 were $0.4 million.

The Fund utilizes DH Sales and Transport, LLC (“DH 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 Diller and Marmalard projects.  In 2016, as amended in April 2018 and September 2021, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreement, DH 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 DH 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 Diller and Marmalard projects. 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 Diller and Marmalard projects.

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 $4.4$3.2 million (which include asset retirement obligations for the Fund’s projects of $1.5$1.2 million), of which $0.9$0.1 million is expected to be spent during the year ending December 31, 2018, primarily related to2024. Future results of operations and cash flows are dependent on the settlementrevenues from production and sale of asset retirement obligations for certain ofoil and natural gas from the Fund’s producing projects.

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

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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.

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, 20172023 and 2016,2022, 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 Notice to Lessees on Supplemental Bonding

Financial Assurance Requirements

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and natural gas leases and owners of pipeline rights-of-way, rights-of userights-of-use and easements on the Outer Continental Shelf (“Lessees”).  Generally, the new NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance.  The new rule became effective as of September 12, 2016;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 January 6, 2017,Risk, Management, Financial Assurance and Loss Prevention, addressing the BOEM announced that itstreamlining 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 suspending the implementation timeline for six months in certain circumstances.  On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of itssignificantly 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 NTL.proposed rule below.

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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 as well as other industry participants, are working withis not able to evaluate the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured.  The impact of the NTL, if enforced without changeproposed new rule on its operations or amendment, may requirefinancial condition until a final rule is issued or some other definitive action is taken by the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using oneInterior or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.


BOEM.

Insurance Coverage

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

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Information about Oil and Gas Producing Activities

Ridgewood Energy X Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities – Unaudited

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


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


  December 31, 
  2017  2016 
  (in thousands) 
Proved properties $16,452  $17,031 
Accumulated depletion and amortization  (12,241)  (10,541)
Oil and gas properties, net $4,211  $6,490 



Schedule of capitalized costs relating to oil and gas producing activities        
  December 31, 
  2023  2022 
  (in thousands) 
Advances to operators for capital expenditures $103  $- 
Proved properties  10,750   9,508 
Accumulated depletion and amortization  (7,896)  (7,541)
Oil and gas properties, net $2,957  $1,967 

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 
  (in thousands) 
Development costs $1,235  $128 
  $1,235  $128 

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  Year ended December 31, 
  2017  2016 
  (in thousands) 
Exploration costs $4  $20 
Development costs  (1,027)  (4)
  $(1,023) $16 

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, 20172023 and 2016.2022. 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.


   December 31, 2017  December 31, 2016 
   United States 
   Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Total (BOE) (a)  Oil (BBLS)  NGL (BBLS)  Gas (MCF)  Total (BOE) (a) 
                         
Proved developed and undeveloped reserves:                   
Beginning of year  483,090   182,521   1,478,981   912,108   583,481   108,454   1,237,695   898,218 
Revisions of previous estimates (b)
  38,300   (34,736)  88,347   18,289   5,860   83,909   434,552   162,194 
Production  (112,539)  (18,594)  (193,386)  (163,365)  (106,251)  (9,842)  (193,266)  (148,304)
End of year  408,851   129,191   1,373,942   767,032   483,090   182,521   1,478,981   912,108 
                                 
Proved developed reserves:                                
Beginning of year  367,710   115,471   988,551   647,940   374,821   63,311   788,355   569,525 
End of year  312,171   78,241   831,622   529,015   367,710   115,471   988,551   647,940 
                                 
Proved undeveloped reserves:                                
Beginning of year  115,380   67,050   490,430   264,168   208,660   45,143   449,340   328,693 
End of year  96,680   50,950   542,320   238,017   115,380   67,050   490,430   264,168 

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  318.2   109.6   808.3   562.5   335.9   124.9   973.7   623.1 
Revisions of previous estimates (b)  (46.6)  (45.7)  (297.8)  (141.9)  23.4   (9.3)  (121.5)  (6.2)
Production  (42.7)  (6.4)  (51.5)  (57.7)  (41.1)  (6.0)  (43.9)  (54.4)
End of year  228.9   57.5   459.0   362.9   318.2   109.6   808.3   562.5 
                                 
Proved developed reserves:                             
Beginning of year  228.1   62.1   457.9   366.5   176.2   55.0   432.1   303.3 
End of year  218.8   50.5   403.1   336.5   228.1   62.1   457.9   366.5 
                                 
Proved undeveloped reserves:                             
Beginning of year  90.1   47.5   350.4   196.0   159.7   69.9   541.6   319.8 
End of year  10.1   7.0   55.9   26.4   90.1   47.5   350.4   196.0 

(a)(a)
BOE refers to barrel of oil equivalent. 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.

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


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



  December 31, 
  2017  2016 
  (in thousands) 
Future cash inflows $22,706  $23,263 
Future production costs  (7,260)  (9,266)
Future development costs  (3,650)  (5,581)
Future net cash flows  11,796   8,416 
10% annual discount for estimated timing of cash flows  (2,906)  (1,230)
Standardized measure of discounted future net cash flows $8,890  $7,186 



Schedule of standardized measure of discounted future net cash flows relating to proved oil and gas reserves        
  December 31, 
  2023  2022 
  (in thousands) 
Future cash inflows $19,437  $38,791 
Future production costs  (4,711)  (8,373)
Future development costs  (2,107)  (3,973)
Future net cash flows  12,619   26,445 
10% annual discount for estimated timing of cash flows  (2,492)  (7,482)
Standardized measure of discounted future net cash flows $10,127  $18,963 

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.


  Year ended December 31, 
  2017  2016 
  (in thousands) 
Net change in sales and transfer prices and in production costs
 related to future production
 $5,415  $(4,683)
Sales and transfers of oil and gas produced during the period  (5,300)  (2,399)
Changes in estimated future development costs  1,931   1,569 
Net change due to revisions in quantities estimates  278   2,125 
Accretion of discount  719   939 
Other  (1,339)  242 
Aggregate change in the standardized measure of discounted future net
cash flows for the year		 $1,704  $(2,207)

Schedule of changes in the standardized measure for discounted cash flows        
  Year ended December 31, 
  2023  2022 
  (in thousands) 
Net change in sales and transfer prices and in production costs related to future production $(4,703) $10,677 
Sales and transfers of oil and gas produced during the period  (3,113)  (4,030)
Changes in estimated future development costs  1,866   (949)
Net change due to revisions in quantities estimates  (4,622)  (241)
Accretion of discount  1,896   1,088 
Other  (160)  1,542 
Aggregate change in the standardized measure of discounted future net cash flows for the year $(8,836) $8,087 

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

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