UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20192020

or

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-52583

Ridgewood Energy U Fund, LLC

(Exact name of registrant as specified in its charter)

14 Philips Parkway, Montvale, NJ 07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

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

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

Shares of LLC Membership Interest

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

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.o

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

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

There is no market for the shares of LLC Membership Interest in the Fund. As of March 3, 2020,2, 2021, there were 486.4825 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY U FUND, LLC
20192020 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy U 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 the ongoing novel coronavirus (“COVID-19”) pandemic and any other future widespread health emergencies or public health crises such as pandemics and epidemics, weather conditions, such as hurricanes, changes in market and other conditions affecting the pricing, production and demand of oil and natural gas, the cost and availability of equipment, and changes in domestic and foreign governmental regulations, as well as other risks and uncertainties discussed in this Annual Report in Item 1. “Business” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Examples of forward-looking statements made herein include statements regarding projects, investments, insurance, capital expenditures and liquidity. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on August 28, 2006 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on October 1, 2006, selling whole and fractional shares of LLC membership interests (“Shares”), primarily at $150 thousand per whole Share. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on January 19, 2007. The Fund raised $72.4 million and after payment of $11.8 million in offering fees, commissions and investment fees, the Fund had $60.6 million for investments and operating expenses.

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. Historically, when the Fund sought project investments, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects. 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 1% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. The Manager is entitled to receive the management fee from the Fund regardless of the Fund’s profitability in that year. Management fees during each of the years ended December 31, 20192020 and 20182019 were $0.2 million. Additionally, the Manager is entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2020 and 2019 and 2018 were $0.4$0.2 million and $0.5$0.4 million, respectively.

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

Business Strategy

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

The Fund’s capital has been fully invested in projects. 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 sixfive employees of the Manager (the “Investment Committee”). The members of the Investment Committee provide operational, financial, scientific and technical oil and gas expertise to the Fund. One member of the Investment Committee is based out of the Manager’s Palm Beach, Florida office, one member is based out of the Manager’s Montvale, New Jersey office and fourthree 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.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Royalty Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Royalty Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Fund currently has one project, the Diller Project, which is eligible for royalty relief under the Deepwater Royalty Relief Act. The Marmalard Project no longer qualifies for royalty relief as the project reached the royalty suspension volumes during 2018. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $39.52$39.87 per barrel and $51.32$51.78 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 $4.94$4.98 per mmbtu and $8.55$8.63 per mmbtu) adjusted annually for inflation.

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned a working interest as of December 31, 2019.2020. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, each of which produces both oil and natural gas, are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

Acreage Data

The following table sets forth the Fund’s working interests in developed and undeveloped oil and natural gas acreage as of December 31, 2019.2020. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and natural gas leases that have varying terms. All of the Fund’s oil and natural gas acreage is located in the offshore waters of the Gulf of Mexico.

Information regarding the Fund’s current projects, all 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.

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

Seasonality

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

However, notwithstanding the ability of the Fund’s 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. TheAlthough the Fund did not experience any significant damage, the Gulf of Mexico suffered the most active hurricane season on record during the second half of 2020, which forced recurring and prolonged production shut-ins or production stoppages due to hurricane activity in 2019.across the industry and the Fund’s projects per safety protocols.

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 Murphy Exploration & Production Company – USA.

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

Insurance

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

Salvage Fund

The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for its proportionate share of the cost of dismantling and removal of production platforms and facilities and plugging and abandoning the wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2019,2020, the Fund had $1.7$1.6 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. In addition, the Manager maintains an additional office lease that is used for administrative purposes for the Fund and other funds managed by the Manager.

Regulation

Oil and natural gas exploration, development, production and transportation activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to regulations. 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 May 2019, BSEE adopted a final rule revising standards for blowout prevention systems and other well controls pertaining to offshore activities (the “2019 Well Control Rule”). The 2019 Well Control Rule became effective July 15, 2019, however compliance with certain provisions was deferred until 2021 or thereafter as specified in those provisions. The 2019 Well Control Rule imposes new requirements relating to, among, other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. The 2019 Well Control Rule applies directly to operators as opposed to non-operators. On September 28, 2018, the BSEE published a final rule revising regulations relating to oil and natural gas production safety systems, subsurface safety devices and safety device testing (referred to as “Subpart H”); the rule was effective December 27, 2018. Given the fact that compliance with the 2019 Well Control Rule and Subpart H is the responsibility of the operators and the exploration and development of each well is different, the future costs associated with compliance that will be incurred by non-operators, such as the Fund, cannot be determined or estimated. On December 4, 2020, BOEM published a Record of Decision (“ROD”) for the final programmatic environmental impact statement for geological and geophysical survey activities in the Gulf of Mexico and adjacent state waters. The ROD provides for additional mitigation measures for application for future BOEM issued permits or authorizations toward further minimizing impacts of such geological and geophysical survey activities on marine resources. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, which civil penalties were increased and adjusted for inflation on March 2, 2018,4, 2020, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activities can result from either governmental or citizen prosecution. 

Effective January 20, 2021, the Secretary of the Interior issued Order No. 3395 under the authority of Section 2 of Reorganization Plan No. 3 of 1950 (64 Stat. 1262) consistent with 200 DM 1 for the purpose of implementing a targeted and time-limited elevation of relevant decisions at the Department of the Interior for review. One item under review is temporarily suspending the issuance of any onshore or offshore fossil fuel authorization, including but not limited to a lease, amendment to a lease, affirmative extension of a lease, contract, or other agreement, or permit to drill. This does not limit existing operations under valid leases. Order No. 3395 remains in effect for 60 days, or until any of its provisions are amended, superseded, or revoked. As the Fund does not expect to drill new wells on its existing leases in the near-term, the Fund does not believe Order No. 3395 will have an immediate impact on the Fund’s operations or financial condition.

On January 27, 2021, President Biden issued an executive order that directs the Department of the Interior, to the extent consistent with applicable law, to pause the issuance of new leases for one year pending a review of the climate-change effects associated with drilling on federal land and waters. As the Fund does not expect to invest in any new projects and thus require the approval of new leases, the Fund does not believe the executive order will have a material impact on the Fund’s operations or financial condition.

BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the OCS (“Lessees”).  Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-N01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of the review of NTL 2016-N01. As of December 31, 2019,2020, the BOEM has not lifted its suspension of the implementation of NTL 2016-N01.  The impact of NTL 2016-N01, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially 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.

On October 16, 2020, BOEM and BSEE published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with OCS obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. The Manager of the Fund submitted comments to the proposed rule supporting much of the proposal. The 60-day public comment period closed on December 15, 2020. To date, however, Interior has not issued a final rule. The Fund is not able to evaluate the impact of the proposed new rule on its operations or financial condition until the final rule is issued.

Sales and Transportation of Oil and Natural Gas

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

Environmental Matters and Regulation

The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water, the handling and managing of waste materials, and the protection of aquatic species and habitats. While most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operators on the Fund’s behalf, the Fund shares the liability along with its other working interest owners for environmental damage 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 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 defines penalties for, such spills. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA, and regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $672.51 million (effective as of November 12, 2019), while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $137.66 million in other damages for each incident. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. A failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on the Fund’s operations or financial condition.

Clean Water Act. Generally, the Clean Water Act, as well as analogous state requirements, imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal or delegated state agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. On December 11, 2018, the Environmental Protection Agency (“EPA”) and Department of the Army (“Army”) proposed a revised definition of “waters of the United States”, 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 Department of 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 currentOn April 21, 2020, the EPA and the Army published the proposed revision will be the subject of a 60-day public comment period, once publishedNavigable Waters Protection Rule in the Federal Register.Register to finalize a revised definition of “waters of the United States” that was consistent with the Presidential direction in Executive Order 13778 under the previous administration. On June 22, 2020, the Navigable Waters Protection Rule became effective and is now being implemented by EPA and the Army. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

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

International Marine Organization 2020. In 2016, the International Marine Organization (“IMO”), a United Nations (“UN”) Agency, instituted a reduction in the sulfur specifications for global marine fuels from 3.5% to 0.5% effective January 1, 2020 in order to reduce the emissions of sulfur to the atmosphere. Shipping companies have the option to buy low sulfur fuel or install scrubbers to lower sulfur emissions to comply with the new regulation. UN member states (174 countries) are responsible for monitoring the compliance of the shipping community with this new regulation. The impact to the Fund from this new 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.

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 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 theResource 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 theComprehensive 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. The Fund’s operations may be subject to analogous and comparable state laws and regulations, in addition to these federal statutes and regulations.

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

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

On February 3, 2017, the “Presidential Executive Order on Core Principles for Regulating the United States Financial System” (the “Order”) was issued to review the Dodd-Frank Act.  A series of reports were issued by the U.S. Department of the Treasury in 2017 pursuant to the Order generally recommending the harmonization, balancing and streamlining of rules and regulations relating to, among other things, the over-the-counter derivatives market. The Fund cannot predict at this time what regulations or portions of the law relating to the over-the-counter derivatives market, if any, will be changed as a result of the Order. Any changes in the law or regulation as a result of the Order could result in a repeal, amendment to or delayed implementation of the Dodd-Frank Act.

Currently, under the 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 2019,2020, 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. No replacement rules were proposed or issued by the SEC. On December 18, 2019, the SEC voted to re-propose new resource extraction disclosure rules pursuant to Section 1504. On December 16, 2020, the SEC voted to adopt the final resource extraction disclosure rules. The final rule, as adopted, will require domestic or foreign reporting issuer to disclose payments made by the issuer or a subsidiary or entity controlled by the issuer to the U.S. federal government or a foreign government if the issuer engages in the commercial development of oil, natural gas, or minerals. The Fund, as a smaller reporting company, is exempt from complying with the final rule, which is effective March 16, 2021.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

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

The following table sets forth the Fund’s drilling activity during the years ended December 31, 20192020 and 2018.2019. Gross wells are the total number of wells in which the Fund has a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, which produce both oil and natural gas, are located in the offshore waters of the Gulf of Mexico. During the years ended December 31, 20192020 and 2018,2019, the Fund had no drilling activity for exploratory wells.

Unaudited Oil and Gas Reserve Quantities

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

The Manager’s primary technical person in charge of overseeing the Fund’s reserve estimates has a B.S. degree in Petroleum Engineering, a Master of Business Administration, and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over thirty 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, 20192020 and 20182019 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.

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

Proved Undeveloped Reserves.As of December 31, 2020, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.1 million barrels of oil, 43 thousand barrels of natural gas liquid (“NGL”) and 0.3 million mcf of natural gas. As of December 31, 2019, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.1 million barrels of oil, 0.1 million barrels of natural gas liquid (“NGL”)NGL and 0.6 million mcf of natural gas. As of December 31, 2018, the Fund had proved undeveloped reserves related to the Diller andThe Marmalard projects totaling 0.2 million barrels of oil, 0.1 million barrels of NGL and 0.8 million mcf of natural gas. The Diller and Marmalard projects wereProject was determined to be discoveriesa discovery in 2012 and commenced production in 2015. The proved undeveloped reserves relating to the Marmalard Project have been undeveloped since their initial booking in 2015. These proved undeveloped reserves will be reclassified to proved developed reserves when the capacity limits at host facility begin to decline, thus allowing for additional production.

During the year ended December 31, 2019, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $0.8 million, related to the Diller Project. The Fund did not incur costs during the year ended December 31, 20192020 to advance the development of its proved undeveloped reserves related to the Marmalard Project. Information regarding estimated future development costs relating to the Diller and Marmalard projects,Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete due to long life sequential production 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, 20192020 and 20182019 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference. 

Delivery Commitments

As of December 31, 2019,2020, the Fund had no delivery obligations or delivery commitments under any existing contracts.

ITEM 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, 2020,29, 2021, there were 983987 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Distributions may be impacted by amounts of future capital required for the ongoing development of the Diller and Marmalard projects and funding 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, 20192020 and 2018,2019, the Fund paid distributions totaling $1.2 million and $2.5 million, and $3.5 million, respectively.

ITEM 6.  SELECTED FINANCIAL DATA

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 funded from available cash from operations, as defined in the Fund’s LLC Agreement, and the frequency and amount are within the Manager’s discretion. The Fund’s capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.

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

Recent Developments

In March 2020, the World Health Organization categorized the outbreak of COVID-19 as a global pandemic, which resulted in a significant drop in oil demand caused by lockdown measures and industrial slowdown around the world. In addition, in March 2020, the failure of an alliance between the Saudi Arabia-led Organization of Petroleum Exporting Countries (“OPEC”) and Russia to reach an agreement on oil production volumes resulted in an oil “price war” and caused oil prices to collapse. On April 12, 2020, OPEC and Russia agreed to reduce production by approximately 9.7 million barrels per day in May and June 2020. Despite this agreement, oil prices decreased to their lowest level in April 2020 as compared to the past several years as a result of the initial oil price war and significant decreases in oil demand caused by world-wide government-ordered lock-downs. Since then, the oil market has stabilized and strengthened with oil prices gradually rising. On June 6, 2020, OPEC and Russia agreed to extend the production cut of approximately 9.7 million barrels per day through the end of July 2020 and maintain a production cut of 7.7 million barrels per day from August 2020 through the end of 2020. On December 3, 2020, OPEC and Russia agreed to reduce the production cut to 7.2 million barrels per day beginning in January 2021 and will then meet monthly to assess market conditions and decide on further production adjustments for the following month, with further monthly adjustments being no more than 0.5 million barrels per day. During the January 2021 meeting, OPEC and Russia agreed to reduce the production cut to 7.125 and 7.05 million barrels per day for February 2021 and March 2021, respectively.

Although the ultimate extent of the impact of the COVID-19 pandemic and resulting market disruption to the Fund’s operating results and cash flows is unknown, the period of low oil and natural gas commodity prices negatively impacted cash flow generated by the Fund’s projects.  However, because the Fund owns its oil and gas properties with no debt and these projects are long-lived assets that are expected to produce over many years with relatively low operating costs, the Fund believes that it is positioned to weather this period of uncertainty and volatility from the COVID-19 pandemic. However, if oil and natural gas commodity prices and the overall economy continue to be impacted by the COVID-19 pandemic, the Fund, its operators and other working interest partners’ financial performance results may be adversely impacted, which could significantly affect the Fund’s liquidity and expected operating results.

Commodity Price Changes

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

Oil and natural gas commodity prices have been subject to significant fluctuations during the past several years. During the first half of 2020, oil and natural gas commodity prices experienced significant volatility primarily attributable to the COVID-19 pandemic. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. The Fund will continue to closely manage and coordinate its capital spending estimates within its expected cash flows to provide for future development costs of its producing projects, as budgeted. See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 20192020 and 20182019 and the effect of such average prices on the Fund’s results of operations. If oil and natural gas commodity prices decline, even if only for a short period of time,continue to be impacted by the COVID-19 pandemic, the Fund’s results of operations and liquidity will be adversely impacted.

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

Critical Accounting Estimates

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

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 reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, oil and natural gas commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues and net cash flows to change.

Asset Retirement Obligations

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

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of the assetsits 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 assetsoil 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 a valuation techniquetechniques that considersinclude both market and income approaches and usesuse 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.

Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 20192020 and 2018,2019, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.

Overview.  The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 20192020 and 2018.2019. NGL sales are included within gas sales.

The increase in production days was primarily related to two wellsnoted in the Marmalard Project, which were shut-in during first half of 2018 due to replacement of well jumpers. The decrease in gas productiontable above was primarily related to the other two wellscommencement of production of an additional well in the MarmalardDiller Project one well was periodically shut-in during 2019fourth quarter 2019. The decreases in oil and gas sales volumes were primarily attributable to the cumulative production shut-ins across the Fund’s producing projects resulting from mechanical remediation downtime, production shut-ins due to the low-price environment coupled with storm-related safety shut-ins as a mechanical issue and one well experienced a decline inresult of active storm systems passing through the production rate.Gulf of Mexico. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

Oil and Gas Revenue. Oil and gas revenue during the year ended December 31, 20192020 was $4.7$2.8 million, a decrease of $0.6$1.9 million from the year ended December 31, 2018.2019. The decrease was primarily attributable to decreased oil and gas prices.prices totaling $1.4 million coupled with decreased sales volume totaling $0.6 million.

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

Depletion and AmortizationAmortization. . Depletion and amortization during the year ended December 31, 20192020 was $0.8$0.6 million, a decrease of $0.2 million from the year ended December 31, 2018.2019. The decrease was primarily attributable to a decrease in production volumes totaling $0.1 million coupled with an adjustment to the average depletionasset retirement obligation related to a fully depleted property totaling $0.1 million, which was recorded in 2019. Depletion and amortization rate as a result ofwas also impacted by changes in reservereserves estimates provided annually by the Fund’s independent petroleum engineers.

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

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

Lease operating expense and transportation and processing expense relate to the Fund’s producing projects. Workover expense represents costs to restore or stimulate production of existing reserves. During the year ended December 31, 2019, workover expense related to remediation work for mechanical issues in the Marmalard Project. Insurance expense represents premiums related to the Fund’s projects, which vary depending upon the number of wells producing or drilling. Accretion expense relates to the asset retirement obligations established for the Fund’s oil and gas properties. Workover expense represents costs to restore or stimulate production of existing reserves. During the year ended December 31, 2019, workover expense related to remediation work for mechanical issues in the Marmalard Project.

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, was $1.2were $0.9 million ($12.1410.47 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2019,2020, compared to $1.2 million ($11.8012.14 per BOE) during the year ended December 31, 2018. Production2019.

The decreases in production costs and production costs per BOE were relatively consistent during the year ended December 31, 20192020 compared to the year ended December 31, 2018. 2019 were primarily attributable to the Diller and Marmalard projects as a result of a reduction in production handling fees from $4.50 per BOE to $1.50 per BOE effective June 2020 through the end of the wells’ productive lives coupled with decreased oil and natural gas production. The production handling fees for the Diller and Marmalard projects declined over time as certain production hurdles were met in accordance with their production handling agreement relating to the Delta House production facility.

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

Management Fees to Affiliate. An annual management fee, totaling 1% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments, is paid monthly to the Manager. All or a portion of such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term commitments.

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

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, 2020 were $1.5 million, primarily related to revenue received of $3.0 million, partially offset by operating expenses of $1.0 million, management fees of $0.2 million, general and administrative expenses of $0.1 million and the settlement of asset retirement obligations of $0.1 million.

Cash flows provided by operating activities during the year ended December 31, 2019 were $2.6 million, primarily related to revenue received of $4.6 million, partially offset by operating expenses of $1.6 million, management fees of $0.2 million, general and administrative expenses of $0.2 million and the settlement of asset retirement obligations of $0.1 million.

Investing Cash Flows

Cash flows provided by operatingused in investing activities during the year ended December 31, 20182020 were $3.5$0.1 million, primarily related to revenue received of $5.5 million, partially offset by operating expenses of $1.4 million, management fees of $0.2 million, generalcapital expenditures for oil and administrative expenses of $0.2 million and the settlement of asset retirement obligations of $0.2 million.gas properties.

Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 2019 were $0.6 million, primarily related to capital expenditures for oil and gas properties.

Cash flows provided by investing activities during the year ended December 31, 2018 were $42 thousand, related to proceeds from salvage fund of $0.3 million, partially offset by capital expenditures for oil and gas properties of $0.3 million.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 20192020 were $2.5$1.2 million, related to manager and shareholder distributions.

Cash flows used in financing activities during the year ended December 31, 20182019 were $3.5$2.5 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��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 capital has been fully allocated to its projects. 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.

Liquidity Needs

The Fund’s primary short-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, 2019,2020, the Fund’s estimated capital commitments related to its oil and gas properties were $4.2$3.8 million (which include asset retirement obligations for the Fund’s projects of $1.8 million), of which $0.3$0.1 million is expected to be spent during the year ending December 31, 2020. 2021. Future results of operations and cash flows are dependent on the ongoing development and the related production of oil and gas revenues from the Fund’s producing projects.

Based upon its current cash position, salvage fund and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments and ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will temporarily waive all or a portion of the management fee to accommodate the Fund’s short-term commitments if needed.

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

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. However, distributions may be impacted by amounts of future capital required for the ongoing development of the Diller and Marmalard projects and funding their estimated asset retirement obligations. Distributions may also be impacted by fluctuations in oil and natural gas commodity prices.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 20192020 and 20182019 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, 20192020 and 2018,2019, other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

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

ITEM 7A.      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

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

None.

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, 2019.2020. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

Management's Report on Internal Control over Financial Reporting

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

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

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2019.2020.  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”) inInternal Control — Integrated Framework (2013).Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2019,2020, the Fund’s internal control over financial reporting is effective.

This Annual Report does not include an attestation report of the Fund’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Fund’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Fund, as a non-accelerated filer, to provide only management’s report in this Annual Report.

Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 20192020 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting. The Fund has not experienced any material impact to internal control over financial reporting due to the COVID-19 pandemic.

None.

PART III

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages as of December 31, 20192020 are as follows:

The officers in the above table have been officers of the Fund since August 28, 2006, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. Effective February 28, 2021, Mr. Gold retired from his role as an executive officer of the Fund. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

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

Kenneth W. Langhas served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Effective February 1, 2020, Mr. Lang will relinquishrelinquished the role of Chief Operating Officer of Ridgewood Energy. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President – Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.

Kathleen P. McSherry has served as the Executive Vice President and Chief Financial Officer 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 officerthe Executive Vice President of Ridgewood Energy since 1987 and is a member of the Investment Committee. Effective February 28, 2021, Mr. Gold retired from his role as Executive Vice President of Ridgewood Energy and as a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.

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

Board of Directors and Board Committees

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

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.

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 486.4825 shares outstanding as of January 31, 2020.29, 2021. The following table sets forth information with respect to beneficial ownership of the Shares as of January 31, 202029, 2021 (no person owns more than 5% of the Shares). Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all Shares shown as beneficially owned by them. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

* Represents less than one percent.

⁽¹⁾ Effective February 28, 2021, Robert L. Gold retired from his role as Executive Vice President of Ridgewood Energy.

ITEM 13.        CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Pursuant to the terms of the LLC Agreement, the Manager renders management, advisory and administrative services to the Fund. For such services, the Manager is entitled to receive an annual management fee, payable monthly, of 1% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 20192020 and 20182019 were $0.2 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2020 and 2019 and 2018 were $0.4$0.2 million and $0.5$0.4 million, respectively.

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, as amended in April 2018, 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 partythird-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations and are allocable to the Fund based on the Fund’s working interest ownership in the 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.

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

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 20192020 and 2018.2019.

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)    

SIGNATURES

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

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholdersshareholders and the Manager of Ridgewood Energy U Fund, LLC

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Ridgewood Energy U Fund, LLC (the "Fund") as of December 31, 20192020 and 2018,2019, the related statements of operations, changes in members’ capital, and cash flows, for each of the two years in the period ended December 31, 2019,2020, 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, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019,2020, 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’sFund's internal control over financial reporting. Accordingly, we express no such opinion.

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

Critical Audit Matter

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

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

Critical Audit Matter Description

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

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

The Fund’s oil and gas properties net balance was $2.8 million as of December 31, 2020 and depletion and amortization expense recognized was $0.6 million for the period ended December 31, 2020. No impairment was recognized during 2020.

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:

/s/ Deloitte & Touche LLP

Parsippany, New Jersey

March 3, 20202, 2021  

We have served as the Fund's auditor since 2006.

RIDGEWOOD ENERGY U FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

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

RIDGEWOOD ENERGY U FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)