UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

or

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-51924

Ridgewood Energy O Fund, LLC

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) 76-0774429 (I.R.S. Employer Identification No.)

14 Philips Parkway, Montvale, NJ 07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

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

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

Shares of LLC Membership Interest

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

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	x	Smaller reporting company Emerging growth company	x o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x

There is no market for the shares of LLC Membership Interest in the Fund. As of March 3, 2020, there were 870.6486 shares of LLC Membership Interest outstanding. 

RIDGEWOOD ENERGY O FUND, LLC
2019 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS

			PAGE
PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	11
	ITEM 1B	UNRESOLVED STAFF COMMENTS	11
	ITEM 2	PROPERTIES	11
	ITEM 3	LEGAL PROCEEDINGS	12
	ITEM 4	MINE SAFETY DISCLOSURES	12
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	13
	ITEM 6	SELECTED FINANCIAL DATA	13
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	19
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	19
	ITEM 9A	CONTROLS AND PROCEDURES	20
	ITEM 9B	OTHER INFORMATION	20
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	20
	ITEM 11	EXECUTIVE COMPENSATION	22
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	22
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	22
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	23
PART IV
	ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	24
		SIGNATURES	26

FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy O 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 that 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 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.

1

PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on December 21, 2004 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Fund initiated its private placement offering on February 16, 2005, 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 August 31, 2005. The Fund raised $129.0 million and, after payment of $20.6 million in offering fees, commissions and investment fees, the Fund had $108.4 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 2.5% 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, 2019 and 2018 were $1.1 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, 2019 and 2018 were $0.9 million and $0.2 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.

2

Investment Committee

Ridgewood Energy maintains an investment committee consisting of six 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 four 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 with the exception of the overriding royalty interests (“ORRI”) payable to the lender under and as required by the Fund’s credit agreement applicable to the Beta Project. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

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 three projects, the Beta, Diller and Liberty projects, which are 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 per barrel and $51.32 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 per mmbtu and $8.55 per mmbtu) adjusted annually for inflation.

3

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

	Total Productive Wells
	Gross	Net
Oil and natural gas	15	0.47

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. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and natural gas leases that have varying terms. All of the Fund’s oil and natural gas acreage is located in the offshore waters of the Gulf of Mexico. 

Developed Acres		Undeveloped Acres
Gross	Net	Gross	Net
51,833	1,161	11,884	110

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.

4

			Total Spent		Total
	Working		through		Fund
Project	Interest		December 31, 2019		Budget		Status
			(in thousands)
Beta Project		2.93%	$	27,856	$	30,421	The Beta Project is expected to include the development of seven wells.  Wells #1 and #2 commenced production in 2016.  Wells #3  and #4 commenced production in 2017. Wells #5 and #6 commenced production in first quarter 2018 and third quarter 2018, respectively. Well #7 commenced production in first quarter 2019. The Fund expects to spend $1.3 million for additional development costs and $1.3 million for asset retirement obligations.
Diller Project		0.88%	$	3,761	$	4,667	The Diller Project is expected to include the development of three wells.  Well #1 commenced production in 2015.  Well #2, which completed drilling in third quarter 2018, commenced production in late-November 2019. Well #3 is expected to commence production in third quarter 2021. The Fund expects to spend $0.6 million for additional development costs and $0.3 million for asset retirement obligations.
Liberty Project		5.0%	$	5,578	$	6,239	The Liberty Project, a single-well project, commenced production in 2010.  The Fund expects to spend $0.7 million for asset retirement obligations.
Marmalard Project		0.84%	$	5,621	$	7,899	The Marmalard Project is expected to include the development of six wells.  Four wells commenced production in 2015.  Additional wells are expected to commence production in 2022.  Two wells, which were shut-in during early-December 2017 due to replacement of well jumpers, resumed production in third quarter 2018.  One well, which had been shut-in since late-February 2019 due to remediation work for downhole mechanical issues, resumed production in third quarter 2019. The Fund expects to spend $1.8 million for additional development costs and $0.5 million for asset retirement obligations.
South Pelto 9		16.67%	$	5,026	$	5,244	South Pelto 9, a single-well project, commenced production in 2007 and is producing at nominal rates. This well has been shut-in since July 2019 due to repair and maintenance work at the third-party facility through which it produces.  The Fund expects to spend $0.2 million for asset retirement obligations.

5

Beta Project – Partial Sale of Working Interest

On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 5.0% working interest in the Beta Project and sold a 2.07% working interest to the Buyers for a total purchase price of $18.6 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $17.6 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $0.2 million, which was recorded as an adjustment to the purchase price.

The net carrying value of the working interest sold as of the closing date was approximately $13.1 million and the related asset retirement obligation was approximately $0.2 million. A gain to the Fund of $4.6 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized by the Fund to repay a portion of the long-term debt outstanding under its credit agreement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs – Credit Agreement” for information regarding the Fund’s credit agreement.

Marketing/Customers

The Manager, on behalf of the Fund, markets the Fund’s oil and natural gas to third parties consistent with industry practice. The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”) and DH Sales and Transport, LLC (“DH S&T”), wholly-owned subsidiaries of the Manager, as aggregators to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta, Diller and Marmalard projects. In 2016, as amended in April 2018 for DH S&T, the Fund entered into master agreements with Beta S&T and DH S&T pursuant to which Beta S&T and DH S&T are obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta, 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 three 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. The Fund did not experience any significant damage, shut-ins, or production stoppages due to hurricane activity in 2019.

6

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 Fieldwood Energy LLC, LLOG Exploration Offshore, L.L.C., Murphy Exploration & Production Company – USA and Walter Oil & Gas Corporation.

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

Insurance

The Manager has obtained what it believes to be adequate insurance for the funds that it manages to cover the risks associated with the funds’ passive investments, including those of the Fund. Although the Fund is not an operator, the Manager has, nonetheless, obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to its projects. In addition, the Manager’s practice is to obtain insurance as a package that is intended to cover most, if not all, of the 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, the Fund had $3.4 million invested in a salvage fund. On a monthly basis, the Fund contributes to the salvage fund a portion of the operating income from the Beta Project to fund its asset retirement obligations. Such contributions to the salvage fund will reduce the amount of cash distributions that could otherwise be made to investors by the Fund. Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.

Competition

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

Employees

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

Offices

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

7

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. 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, 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. 

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, 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.

8

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, including the Exxon Valdez spill, that occurred in the 1980s. 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 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 current proposed revision will be the subject of a 60-day public comment period, once published in the Federal Register. 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.

9

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. 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, such as from the Beta Project, could fall in value relative to lighter sweet crudes as a result of excess high sulfur fuel on the market and subsequent refinery crude slate changes. However, the price of heavier sour crudes in the market continues to be supported by tightness in supply for such crude, new refinery capacity consuming medium/high sulfur crudes and refinery optimization around high sulfur products. As such, the Fund believes IMO 2020 will not in the future have a material impact on the Fund’s operations or financial condition.

Climate Change. The oil and gas industry is subject to federal and state greenhouse gas monitoring, reporting and emissions control requirements. The current state of international climate initiatives and federal and state actions presents challenges to assessing the impact to the Fund’s operations in relation to future international agreements, federal and state legislation, and other new requirements. Future restrictions on emissions of greenhouse gases could have an impact on future operations.

Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act of 1976, as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment. 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.

10

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, 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.

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, 2019 and 2018. 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, 2019 and 2018, the Fund had no drilling activity for exploratory wells.

	2019				2018
	Gross		Net		Gross		Net
Development wells:
Productive		2		0.04		2		0.06
In-progress		-		-		2		0.04
Development well total		2		0.04		4		0.10

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 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.

11

The Fund’s reserve estimates as of December 31, 2019 and 2018 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, 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”) and 0.6 million mcf of natural gas. As of December 31, 2018, the Fund had proved undeveloped reserves related to the Diller and 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 were determined to be discoveries 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, 2019 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, 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, 2019 and 2018 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, the Fund had no delivery obligations or delivery commitments under any existing contracts.

ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

12

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, there were 1,705 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 of estimated asset retirement obligations as well as amounts reserved to provide for the borrowing repayments for the Fund’s credit agreement applicable to the Beta Project, as described in Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report. 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, 2019 and 2018, the Fund paid distributions totaling $5.8 million and $1.6 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.

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. 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, 2019 and 2018 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, the Fund’s results of operations and liquidity will be adversely impacted.

13

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:

· weather conditions;

· economic conditions, including demand for petroleum-based products;

· actions by OPEC, the Organization of Petroleum Exporting Countries;

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

· governmental regulations, both domestic and foreign;

· domestic and foreign tax policy;

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

· the supply and price of foreign oil and gas;

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

· the discovery rate of new oil and gas reserves;

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

· available pipeline and other oil and gas transportation capacity;

· the ability of oil and gas companies to raise capital;

· the overall supply and demand for oil and gas; and

· the price and availability of alternate fuel sources.

Critical Accounting Estimates

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

14

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 whenever events and circumstances indicate that the recorded carrying value of the assets may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.

Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 2019 and 2018, 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.

	Year ended December 31,
	2019			2018
	(in thousands)
Revenue
Oil and gas revenue	$	11,788		$	16,882
Other revenue		417			90
Total revenue		12,205			16,972
Expenses
Depletion and amortization		4,152			8,090
Operating expenses		3,161			2,825
Management fees to affiliate		1,129			1,131
General and administrative expenses		215			240
Other general expense		293			-
Total expenses		8,950			12,286
Gain on sale of oil and gas properties		-			4,588
Income from operations		3,255			9,274
Other income (loss)
Gain on debt extinguishment		-			2,156
Other income		-			100
Dividend income		36			17
Interest expense, net		(338	)		(1,463	)
Total other (loss) income		(302	)		810
Net income	$	2,953		$	10,084

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, 2019 and 2018. NGL sales are included within gas sales.

15

	Year ended December 31,
	2019		2018
Number of wells producing		15		15
Total number of production days		4,477		3,487
Oil sales (in thousands of barrels)		186		239
Average oil price per barrel	$	59	$	64
Gas sales (in thousands of mcfs)		340		466
Average gas price per mcf	$	2.51	$	3.57

The increase in production days was primarily related to the commencement of production of two wells in the Beta Project, one well during third quarter 2018 and one well during first quarter 2019. The decreases in oil and gas sales volumes were primarily related to the Beta, Liberty and Marmalard projects. The decrease in the Beta Project production was primarily related to the partial sale of working interest in the project during third quarter 2018 coupled with periodic shut-ins during first half 2019 due to certain drilling and completion operations performed at the project’s production facility. The Liberty Project experienced a decrease in production primarily as a result of shut-ins during 2019 due to mechanical work. The decrease in the Marmalard Project production was primarily attributable to two wells in the project, one well was periodically shut-in during 2019 due to a mechanical issue and one well experienced a decline in the production rate. 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, 2019 was $11.8 million, a decrease of $5.1 million from the year ended December 31, 2018. The decrease was attributable to decreased sales volume totaling $3.8 million coupled with decreased oil and gas prices totaling $1.3 million.

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

Other Revenue. Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. See Note 3 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information.

Depletion and Amortization. Depletion and amortization during the year ended December 31, 2019 was $4.2 million, a decrease of $3.9 million from the year ended December 31, 2018. The decrease was attributable to a decrease in the average depletion rate totaling $2.1 million coupled with a decrease in production volumes totaling $1.9 million, partially offset by an adjustment to the asset retirement obligation related to a fully depleted property totaling $0.1 million recorded in 2018. The decrease in the average depletion rate was primarily attributable to changes in reserve estimates provided annually by the Fund’s independent petroleum engineers. Depletion and amortization was also impacted by the partial sale of working interest in the Beta Project during third quarter 2018.

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

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

	Year ended December 31,
	2019		2018
	(in thousands)
Lease operating expense	$	1,635	$	1,892
Workover expense		830		93
Transportation and processing expense		427		448
Insurance expense		214		298
Accretion expense and other		55		94
	$	3,161	$	2,825

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 primarily 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.

16

Production costs, which include lease operating expense, transportation and processing expense and insurance expense, were $2.3 million ($9.38 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2019, compared to $2.6 million ($8.33 per BOE) during the year ended December 31, 2018. The decrease in production costs was primarily attributable to the partial sale of working interest in the Beta Project during third quarter 2018. The increase in production costs per BOE was primarily attributable to certain fixed costs associated with the Marmalard Project, which was shut-in periodically during first half of 2019 due to mechanical issues. See “Overview” above for factors that impact oil and natural gas production.

Management Fees to Affiliate. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments, is paid monthly to the Manager.

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.

Other General Expense.  During the year ended December 31, 2019, the Fund recorded other general expense of $0.3 million representing its proportionate share of a settlement for a litigation between the Beta Project’s operator and a third-party. Although the Fund was not party to the litigation, the Fund is responsible for its proportionate share of the costs of the litigation as well as any settlement made or judgement imposed upon the operator of the Beta Project if the claim is based upon or arises from operations on the Beta Project.  See Note 5 of “Notes to Financial Statements” – “Commitments and Contingencies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for information regarding this expense.  There was no such amount recorded during the year ended December 31, 2018.

Gain on Sale of Oil and Gas Properties. During the year ended December 31, 2018, the Fund recorded a gain on sale of oil and gas properties of $4.6 million related to the sale of a portion of the Fund’s working interest in the Beta Project. See Item 1. “Business” of this Annual Report under the heading “Beta Project – Partial Sale of Working Interest” for additional information regarding the sale. There was no such amount recorded during the year ended December 31, 2019.

Gain on Debt Extinguishment. During the year ended December 31, 2018, the Fund recorded a gain on debt extinguishment of $2.2 million related to accounting for the fourth amendment to the credit agreement. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Fund’s credit agreement. There was no such amount recorded during the year ended December 31, 2019.

Other Income.  During the year ended December 31, 2018, the Fund recorded other income of $0.1 million related to a fee received upon execution of the Fund’s production handling, gathering and operating services agreement with an affiliated entity and other third parties. There were no such amounts recorded during the year ended December 31, 2019.

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

Interest Expense, Net. Interest expense, net is comprised of interest expense and amortization of debt discounts related to the Fund’s long-term borrowings, and interest income earned on cash and cash equivalents and salvage fund. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Fund’s credit agreement.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 2019 were $7.8 million, primarily related to revenue received of $12.3 million, partially offset by operating expenses of $2.9 million, management fees of $1.1 million, interest payments of $0.4 million and general and administrative expenses of $0.2 million.

Cash flows provided by operating activities during the year ended December 31, 2018 were $9.8 million, primarily related to revenue received of $17.6 million, partially offset by interest payments of $3.5 million, operating expenses of $2.9 million, management fees of $1.1 million, general and administrative expenses of $0.2 million and the settlement of asset retirement obligations of $0.1 million.

17

Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 2019 were $0.8 million, related to capital expenditures for oil and gas properties of $1.3 million and investments in salvage fund of $0.3 million, partially offset by the reimbursement received from operator for capital expenditures of $0.8 million relating to a portion of the cost of the Beta Project platform slot that was utilized by the other third-party working interest owners for the Beta Project’s 8th well. The Fund, as well as other funds managed by the Manager that invested in the Beta Project, elected not to participate in the drilling of the 8th well proposed by the Beta Project operator.

Cash flows provided by investing activities during the year ended December 31, 2018 were $11.9 million, related to proceeds from sale of oil and gas properties of $17.4 million, partially offset by capital expenditures for oil and gas properties of $5.2 million and investments in salvage fund of $0.4 million.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 2019 were $8.3 million, related to manager and shareholder distributions of $5.8 million and the repayments of long-term borrowings of $2.4 million.

Cash flows used in financing activities during the year ended December 31, 2018 were $20.5 million, related to the repayments of long-term borrowings of $18.9 million and manager and shareholder distributions of $1.6 million.

Estimated Capital Expenditures

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

Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering and through debt financing. 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, capital expenditures for its oil and gas properties and borrowing repayments. Such needs are funded utilizing operating income and existing cash on-hand.

As of December 31, 2019, the Fund’s estimated capital commitments related to its oil and gas properties were $7.3 million (which include asset retirement obligations for the Fund’s projects of $3.7 million), of which $0.4 million is expected to be spent during the year ending December 31, 2020. 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 and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments 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.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year.

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 of estimated asset retirement obligations as well as amounts reserved to provide for the borrowing repayments for the Credit Agreement (defined below).

Credit Agreement

As of December 31, 2019 and 2018, the Fund had outstanding borrowings of $2.8 million and $5.2 million, respectively, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”).

18

Borrowings under the Credit Agreement bear interest at 8.75% compounded monthly. Principal and interest payments are based on the fixed percentage of the Fund’s Net Revenue, as defined in the Credit Agreement. Beginning on April 1, 2019 and each April 1^st thereafter, the Fund’s fixed percentage is the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually beginning April 1, 2019 and every April 1^st thereafter, and is based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineer’s proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan of December 31, 2022. As of April 1, 2019, the Fund’s fixed percentage was determined to be 30%. The loan may be prepaid by the Fund without premium or penalty. The Credit Agreement also provides for a fixed percentage of 12.56% overriding royalty interest to the lenders, which will become payable to the lenders in January 2023, and requires mandatory prepayment of excess cash flows received by the Fund from certain insurance reimbursements, platform related revenues, production handling fees and any additional revenues received with respect to the use of the Beta Project other than any revenues included in the calculation of Net Revenue, as well as proceeds from a sale or transfer of any interest in the Beta Project as permitted under the Credit Agreement.

The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warranties and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the lenders under the Credit Agreement may accelerate the maturity of the loan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund is in compliance with all covenants under the Credit Agreement as of December 31, 2019 and 2018.

See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

None.

19

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. 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.  In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2019, 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, 2019 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages as of December 31, 2019 are as follows:

 Name, Age and Position with Registrant

Robert E. Swanson, 72

  Chief Executive Officer

Kenneth W. Lang, 65

  President and Chief Operating Officer

Kathleen P. McSherry, 54

  Executive Vice President and Chief Financial Officer

Robert L. Gold, 61

  Executive Vice President

Daniel V. Gulino, 59

  Senior Vice President, General Counsel and Secretary

20

The officers in the above table have been officers of the Fund since December 21, 2004, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:

Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC, 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. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Effective February 1, 2020, Mr. Lang will relinquish 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 officer of Ridgewood Energy since 1987 and is a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.

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

Board of Directors and Board Committees

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

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.

21

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 870.6486 shares outstanding as of January 31, 2020. The following table sets forth information with respect to beneficial ownership of the Shares as of January 31, 2020 (no person owns more than 5% of the Shares). Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all Shares shown as beneficially owned by them. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.

Name of beneficial owner	Number of shares	Percent
Robert E. Swanson, Chief Executive Officer	2.0	*
Executive officers as a group	2.0	*

* Represents less than one percent.

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

Pursuant to the terms of the LLC Agreement, the Manager renders management, advisory and administrative services to the Fund. For such services, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 2019 and 2018 were $1.1 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2019 and 2018 were $0.9 million and $0.2 million, respectively.

Beta S&T and DH S&T, wholly-owned subsidiaries of the Manager, act as aggregators to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta, Diller and Marmalard projects. In 2016, as amended in April 2018 for DH S&T, the Fund entered into master agreements with Beta S&T and DH S&T pursuant to which Beta S&T and DH S&T are obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta, Diller and Marmalard projects and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreements, Beta S&T and DH S&T are pass-through entities such that they receive no benefit or compensation for the services provided under the master agreements or under any other agreements they enter into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T and DH S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against them as a result of or arising from any act or omission, breach and claims for losses or damages arising out of their dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta, Diller and Marmalard projects. The revenues and expenses from the sale of oil and natural gas to third-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations and are allocable to the Fund based on the Fund’s working interest ownership in the Beta, Diller and Marmalard projects.

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas produced through the Beta Project production facility. See Note 3 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the PHA.

22

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

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

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP during the years ended December 31, 2019 and 2018.

	Year ended December 31,
	2019		2018
	(in thousands)
Audit fees (1)	$	86	$	87

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

23

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1)     Financial Statements

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

(a) (2)    Financial Statement Schedules

None.

(a) (3)

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING
3.1	Certificate of Formation of Ridgewood Energy O Fund, LLC dated December 21, 2004	Incorporated by reference to the Fund's Form 10 filed on April 21, 2006
3.2	Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy O Fund, LLC dated February 16, 2005	Incorporated by reference to the Fund's Form 10 filed on April 21, 2006
4	Description of Shares	Filed herewith
10.1	Credit Agreement dated as of November 27, 2012 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund's Form 8-K filed on December 3, 2012
10.2	First Amendment to Credit Agreement dated September 30, 2016 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund's Form 10-K filed on February 27, 2017
10.3	Second Amendment to Credit Agreement and Reaffirmation of Waiver dated September 15, 2017 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund's Form 10-Q filed on November 7, 2017
10.4	Third Amendment to Credit Agreement dated June 1, 2018 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund’s Form 8-K filed on June 7, 2018

24

10.5	Fourth Amendment to Credit Agreement dated August 10, 2018 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto	Incorporated by reference to the Fund’s Form 10-Q filed on August 14, 2018
10.6	Purchase and Sale Agreement dated August 10, 2018 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, as Sellers and each individually a Seller and Walter Oil & Gas Corporation and Gordy Oil Company as Buyers and each individually a Buyer	Incorporated by reference to the Fund’s Form 10-Q filed on August 14, 2018
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	Filed herewith
31.2	Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	Filed herewith
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund	Filed herewith
99.1	Report of Netherland, Sewell & Associates, Inc.	Filed herewith
101.INS	XBRL Instance Document	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Filed herewith
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.LAB	XBRL Taxonomy Extension Label Linkbase	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Filed herewith

25

SIGNATURES

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

	RIDGEWOOD ENERGY O FUND, LLC
Date:  March 3, 2020	By:	/s/ ROBERT E. SWANSON
		Robert E. Swanson Chief Executive Officer (Principal Executive Officer)

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

Signature	Capacity	Date
/s/ ROBERT E. SWANSON	Chief Executive Officer	March 3, 2020
Robert E. Swanson	(Principal Executive Officer)
/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer	March 3, 2020
Kathleen P. McSherry	(Principal Financial and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
BY:  /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	March 3, 2020
Robert E. Swanson

26

INDEX TO FINANCIAL STATEMENTS	PAGE
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2019 and 2018	F-3
Statements of Operations for the years ended December 31, 2019 and 2018	F-4
Statements of Changes in Members' Capital for the years ended December 31, 2019 and 2018	F-5
Statements of Cash Flows for the years ended December 31, 2019 and 2018	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-16

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Ridgewood Energy O Fund, LLC (the “Fund”) as of December 31, 2019 and 2018, 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, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

/s/ Deloitte & Touche LLP

Parsippany, New Jersey

March 3, 2020

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

F-2

RIDGEWOOD ENERGY O FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2019			2018
Assets
Current assets:
Cash and cash equivalents	$	3,303		$	4,611
Salvage fund		138			19
Production receivable		1,329			1,081
Due from affiliate (Note 3)		24			90
Other current assets		75			271
Total current assets		4,869			6,072
Salvage fund		3,305			3,122
Investment in Delta House		119			119
Oil and gas properties:
Proved properties		50,897			51,117
Less:  accumulated depletion and amortization		(31,818	)		(27,668	)
Total oil and gas properties, net		19,079			23,449
Total assets	$	27,372		$	32,762
Liabilities and Members' Capital
Current liabilities:
Due to operators	$	1,122		$	1,580
Accrued expenses		50			50
Current portion of long-term borrowings		1,663			1,746
Asset retirement obligations		138			19
Other current liabilities		293			-
Total current liabilities		3,266			3,395
Long-term borrowings		1,122			3,475
Asset retirement obligations		2,269			2,303
Total liabilities		6,657			9,173
Commitments and contingencies (Note 5)
Members' capital:
Manager:
Distributions		(6,652	)		(5,778	)
Retained earnings		8,678			7,567
Manager's total		2,026			1,789
Shareholders:
Capital contributions (935 shares authorized;
870.6486 issued and outstanding)		128,990			128,990
Syndication costs		(14,742	)		(14,742	)
Distributions		(39,867	)		(34,914	)
Accumulated deficit		(55,692	)		(57,534	)
Shareholders' total		18,689			21,800
Total members' capital		20,715			23,589
Total liabilities and members' capital	$	27,372		$	32,762

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

F-3

RIDGEWOOD ENERGY O FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2019			2018
Revenue
Oil and gas revenue	$	11,788		$	16,882
Other revenue		417			90
Total revenue		12,205			16,972
Expenses
Depletion and amortization		4,152			8,090
Operating expenses		3,161			2,825
Management fees to affiliate (Note 3)		1,129			1,131
General and administrative expenses		215			240
Other general expense		293			-
Total expenses		8,950			12,286
Gain on sale of oil and gas properties		-			4,588
Income from operations		3,255			9,274
Other income (loss)
Gain on debt extinguishment		-			2,156
Other income		-			100
Dividend income		36			17
Interest expense, net		(338	)		(1,463	)
Total other (loss) income		(302	)		810
Net income	$	2,953		$	10,084
Manager Interest
Net income	$	1,111		$	1,919
Shareholder Interest
Net income	$	1,842		$	8,165
Net income per share	$	2,115		$	9,378

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

F-4

RIDGEWOOD ENERGY O FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS’ CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2017		870.6486	$	112		$	15,001		$	15,113
Distributions		-		(242	)		(1,366	)		(1,608	)
Net income		-		1,919			8,165			10,084
Balances, December 31, 2018		870.6486	$	1,789		$	21,800		$	23,589
Distributions		-		(874	)		(4,953	)		(5,827	)
Net income		-		1,111			1,842			2,953
Balances, December 31, 2019		870.6486	$	2,026		$	18,689		$	20,715

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

F-5

RIDGEWOOD ENERGY O FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2019			2018
Cash flows from operating activities
Net income	$	2,953		$	10,084
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion and amortization		4,152			8,090
Gain on sale of oil and gas properties		-			(4,588	)
Accretion expense		54			72
Gain on debt extinguishment		-			(2,156	)
Amortization of debt discounts		6			2
Changes in assets and liabilities:
(Increase) decrease in production receivable		(248	)		690
Decrease (increase) in due from affiliate		66			(90	)
Decrease (increase) in other current assets		196			(140	)
Increase (decrease) in due to operators		312			(22	)
Decrease in accrued expenses		-			(1,994	)
Increase (decrease) in other current liabilities		293			(100	)
Settlement of asset retirement obligations		(22	)		(64	)
Net cash provided by operating activities		7,762			9,784
Cash flows from investing activities
Capital expenditures for oil and gas properties		(1,323	)		(5,192	)
Reimbursement from operator for capital expenditures		824			-
Proceeds from sale of oil and gas properties		-			17,429
Increase in salvage fund		(302	)		(373	)
Net cash (used in) provided by investing activities		(801	)		11,864
Cash flows from financing activities
Repayments of long-term borrowings		(2,442	)		(18,886	)
Distributions		(5,827	)		(1,608	)
Net cash used in financing activities		(8,269	)		(20,494	)
Net (decrease) increase in cash and cash equivalents		(1,308	)		1,154
Cash and cash equivalents, beginning of year		4,611			3,457
Cash and cash equivalents, end of year	$	3,303		$	4,611
Supplemental disclosure of cash flow information
Cash paid for interest	$	370		$	3,470
Supplemental disclosure of non-cash investing activities
Due to operators for accrued capital expenditures for oil and gas properties	$	175		$	945

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

F-6

RIDGEWOOD ENERGY O FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy O Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on December 21, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of February 16, 2005 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for the Fund’s operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 3, 4 and 5.

Use of Estimates

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

Fair Value Measurements

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

The Fund’s financial assets and liabilities consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, investment in Delta House, due to operators, accrued expenses, other current liabilities and long-term debt. Except for investment in Delta House and long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. The Fund’s investment in Delta House is valued using the measurement alternative for investment in other entities (see Investment in Delta House below for additional information). The Fund’s long-term debt is valued using an income approach and classified as Level 3 in the fair value hierarchy. The fair value of long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis.

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2019, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2019, the Fund’s bank balances, including salvage fund, were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

F-7

Salvage Fund

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

Investment in Delta House 

The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by Murphy Exploration & Production Company - USA. The investment in Delta House is valued using the measurement alternative to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. At each reporting period, the Fund reviews its investment in Delta House to evaluate whether the investment is impaired. Losses on investments, including impairments, are classified as non-operating losses in the Fund’s statements of operations. During the years ended December 31, 2019 and 2018, there were no impairments of the Fund’s investment in Delta House.

Oil and Gas Properties

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

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

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

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

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred based on expected future cash outflows required to satisfy the obligation discounted at the Fund’s credit-adjusted risk-free rate. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2019 and 2018:

	December 31,
	2019			2018
	(in thousands)
Balance, beginning of year	$	2,322		$	2,499
Liabilities incurred		-			56
Liabilities settled/relieved		(22	)		(294	)
Accretion expense		54			72
Revision of estimates		53			(11	)
Balance, end of year	$	2,407		$	2,322

F-8

During the year ended December 31, 2018, the Fund recorded credits to depletion expense totaling $0.1 million, which related to an adjustment to the asset retirement obligation for a fully depleted property.

Syndication Costs

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

Revenue Recognition

The Fund recognizes oil and gas revenue from contracts with customers at the point when control of oil and natural gas is transferred to the customer at an amount that reflects the consideration the Fund expects to be entitled to in accordance with Accounting Standard Codification 606 Revenue from Contracts with Customers (“ASC 606”). The Fund’s revenue recognition policies, performance obligations and significant judgements in applying ASC 606 are described below.

Oil and Gas Revenue

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

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

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

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

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

Transaction Price Allocated to Remaining Performance Obligations

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

F-9

Contract Balances

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

Other Revenue

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

Prior Period Performance Obligations

The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. During the years ended December 31, 2019 and 2018, revenue recognized from performance obligations satisfied in previous periods was not significant.

Impairment of Long-Lived Assets

The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.

There were no impairments of oil and gas properties during the years ended December 31, 2019 and 2018. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

Depletion and Amortization

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

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2016 through 2018 tax returns remain open for examination by tax authorities.

Income and Expense Allocation

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

F-10

Distributions

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

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

Recent Accounting Pronouncements

In August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund will adopt this accounting guidance effective January 1, 2020. The adoption of this accounting guidance is not expected to have a material impact on the Fund’s financial statements.

In June 2016, the FASB issued accounting guidance on measurement of credit losses, which introduces, among other things, a new expected loss impairment model that applies to most financial assets measured at amortized cost and certain other instruments including trade and other receivables and other financial assets. Under the new accounting guidance, entities are required to estimate expected credit loss over the life of financial assets and record an allowance against the asset’s amortized cost basis to present the financial asset at the amount expected to be collected. The estimate of expected credit losses will require entities to incorporate considerations of historical information, current information and reasonable and supportable forecasts. The accounting guidance and the most recent update issued in February 2020 are effective for the Fund in the first quarter of 2023 with early adoption permitted. The Fund early adopted this accounting guidance and related updates on January 1, 2020 and the adoption did not have a material impact on the Fund’s financial statements.

In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance was effective for the Fund beginning January 1, 2019. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.

2. Oil and Gas Properties

The Fund, as well as other funds managed by the Manager, that invested in the Beta Project elected not to participate in the drilling of the 8th well proposed by Walter Oil and Gas Corporation. As a result, the Fund was due reimbursement for a portion of the cost relating to the slot on the Beta Project platform that was utilized by the other third-party working interest owners for the 8th well. On July 17, 2019, the Fund and the other third-party working interest owners in the Beta Project agreed to a reimbursement to the Fund of $0.8 million, which was recorded as a reduction to oil and gas properties on the Fund’s balance sheet as of December 31, 2019 and presented as “Reimbursement from operator for capital expenditures” in the investing section of the Fund’s statement of cash flows for the year ended December 31, 2019. The amount received was utilized by the Fund to repay a portion of the long-term debt outstanding under the Credit Agreement as defined below in Note 4.

On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 5.0% working interest in the Beta Project and sold a 2.07% working interest to the Buyers for a total purchase price of $18.6 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $17.6 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $0.2 million, which was recorded as an adjustment to the purchase price.

F-11

The net carrying value of the working interest sold as of the closing date was approximately $13.1 million and the related asset retirement obligation was approximately $0.2 million. A gain to the Fund of $4.6 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized by the Fund to repay a portion of the long-term debt outstanding under the Credit Agreement as defined below in Note 4.

3. Related Parties

Pursuant to the terms of the LLC Agreement, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole well costs incurred by the Fund and fully depleted project investments. Management fees during each of the years ended December 31, 2019 and 2018 were $1.1 million.

The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2019 and 2018 were $0.9 million and $0.2 million, respectively.

Transport Entities

The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”) and DH Sales and Transport, LLC (“DH S&T”), wholly-owned subsidiaries of the Manager, as aggregators to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta, Diller and Marmalard projects.  In 2016, as amended in April 2018 for DH S&T, the Fund entered into master agreements with Beta S&T and DH S&T pursuant to which Beta S&T and DH S&T are obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta, Diller and Marmalard projects and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreements, Beta S&T and DH S&T are pass-through entities such that they receive no benefit or compensation for the services provided under the master agreements or under any other agreements they enter into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T and DH S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against them as a result of or arising from any act or omission, breach and claims for losses or damages arising out of their dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta, Diller and Marmalard projects. The revenues and expenses from the sale of oil and natural gas to third-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations and are allocable to the Fund based on the Fund’s working interest ownership in the Beta, Diller and Marmalard projects.

Production Handling, Gathering and Operating Services Agreement

The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third-party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018, November 30, 2018 and December 1, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility.

During fourth quarter 2018, the Beta Project Owners commenced their production and handling services for the oil and natural gas produced from the Claiborne Project. During each of the years ended December 31, 2019 and 2018, the Fund earned $0.1 million, representing its proportionate share of the production handling fees earned from Institutional Fund II, which is included within “Other revenue” on the Fund’s statements of operations. As of December 31, 2019 and 2018, the Fund’s receivables of $24 thousand and $0.1 million, respectively, related to the Fund’s proportionate share of revenue from Institutional Fund II are included within “Due from affiliate” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund on behalf of the Claiborne Project working interest owners when the operator performs the joint interest billing of the lease operating expenses due from the Fund. The revenue received from the PHA is utilized by the Fund to repay a portion of the long-term debt outstanding under its Credit Agreement (defined below) until the loan is repaid in full, in no event later than December 31, 2022. During the year ended December 31, 2018, the Fund recorded other income of $0.1 million related to a fee received upon execution of the PHA. There were no such amounts recorded during the year ended December 31, 2019.

F-12

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.

4. Credit Agreement – Beta Project Financing

As of December 31, 2019 and 2018, the Fund had outstanding borrowings of $2.8 million and $5.2 million, respectively, under its credit agreement dated November 27, 2012, as amended on September 30, 2016, September 15, 2017, June 1, 2018 and August 10, 2018 (the “Credit Agreement”). As of December 31, 2019, the estimated fair value of the debt was $2.8 million.

Borrowings under the Credit Agreement bear interest at 8.75% compounded monthly. Principal and interest payments are based on the fixed percentage of the Fund’s Net Revenue, as defined in the Credit Agreement. Beginning on April 1, 2019 and each April 1^st thereafter, the Fund’s fixed percentage is the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually beginning April 1, 2019 and each April 1^st thereafter, and is based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineer’s proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan of December 31, 2022. As of April 1, 2019, the Fund’s fixed percentage was determined to be 30%. The loan may be prepaid by the Fund without premium or penalty. Pursuant to the Credit Agreement, the Fund also agreed to convey a fixed percentage of 12.56% overriding royalty interest in its working interest in the Beta Project to the lenders, which will become payable to the lenders on January 1, 2023.

As of December 31, 2019 and 2018, the unamortized debt discounts related to the loan of $16 thousand and $22 thousand, respectively, were presented as a reduction of “Long-term borrowings” on the Fund’s balance sheets. Amortization expense during the years ended December 31, 2019 and 2018 of $6 thousand and $2 thousand, respectively, was included on the Fund’s statements of operations within “Interest expense, net”. As of December 31, 2019 and 2018, there were no accrued interest costs outstanding. Interest costs incurred during the years ended December 31, 2019 and 2018 of $0.4 million and $1.5 million, respectively, were included on the Fund’s statements of operations within “Interest expense, net”.

As of December 31, 2019, the estimated principal repayments of debt are as follows: $1.7 million in 2020 and $1.1 million in 2021. The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2019 and 2018.

During third quarter 2018, the Fund determined that the terms of the fourth amendment to the Credit Agreement dated August 10, 2018 met the conditions of debt extinguishment pursuant to Accounting Standard Codification 470-50 Debt: Modification and Extinguishments guidance in a non-troubled debt restructuring. As a result, the Fund recorded a gain on debt extinguishment of $2.2 million, which was recorded within “Other income (loss)” in its statements of operations. The gain on debt extinguishment primarily represents non-cash gains associated with the change in the fair value of ORRI conveyed to the lenders totaling $2.1 million and the difference between the fair value of the new debt and the carrying amount of the old debt totaling $24 thousand.

5. Commitments and Contingencies

Capital Commitments

As of December 31, 2019, the Fund’s estimated capital commitments related to its oil and gas properties were $7.3 million (which include asset retirement obligations for the Fund’s projects of $3.7 million), of which $0.4 million is expected to be spent during the year ending December 31, 2020. 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.

F-13

Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments 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.

Other Contingencies

The operator was subject to litigation with a third-party, relating to change order requests for the Beta Project platform.    The Fund was not a named party to the lawsuit filed and was not a party to the litigation; however, under the operating agreement (“OA”) the Fund is responsible for its proportionate share of costs of the litigation as well as any settlements made or judgement imposed upon the operator if the claim is based upon or arises from operations on the Beta project. Under the OA, the settlement required the Fund’s approval.  In February 2020, the Fund approved its proportionate share of the proposed settlement amount. The Fund determined that the approval of the proposed settlement represented the culmination of conditions existing as of December 31, 2019, and as a result, the Fund recorded its proportionate share of the settlement totaling $0.3 million within “Other general expense” on its statements of operations during the year ended December 31, 2019.

Environmental and Governmental Regulations

Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2019 and 2018, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

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

BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL 2016-N01”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, NTL 2016-N01 (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security, and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however, 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 2016-01, 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, 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.

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Insurance Coverage

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

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Ridgewood Energy O Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities - Unaudited

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

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

	December 31,
	2019			2018
	(in thousands)
Proved properties	$	50,897		$	51,117
Accumulated depletion and amortization		(31,818	)		(27,668	)
Oil and gas properties, net	$	19,079		$	23,449

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

	Year ended December 31,
	2019			2018
	(in thousands)
Exploration costs	$	1		$	23
Development costs		(219	)		4,930
	$	(218	)	$	4,953

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Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2019 and 2018. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available. 

	December 31, 2019												December 31, 2018
	United States
	Oil (MBBL)			NGL (MBBL)			Gas (MMCF)			Total (MBOE) (a)			Oil (MBBL)			NGL (MBBL)			Gas (MMCF)			Total (MBOE) (a)
Proved developed and undeveloped reserves:
Beginning of year		988.6			225.7			1,925.0			1,535.1			1,050.8			178.4			1,680.7			1,509.3
Extensions and discoveries (b)		-			-			-			-			53.5			2.0			20.5			58.9
Revisions of previous estimates (c)		49.0			(28.7	)		(249.5	)		(21.3	)		354.5			93.0			614.8			550.0
Production		(185.4	)		(23.3	)		(195.8	)		(241.3	)		(238.0	)		(31.1	)		(281.7	)		(316.1	)
Sale of minerals in place (d)		-			-			-			-			(232.2	)		(16.6	)		(109.3	)		(267.0	)
End of year		852.2			173.7			1,479.7			1,272.5			988.6			225.7			1,925.0			1,535.1
Proved developed reserves:
Beginning of year		830.9			142.4			1,172.5			1,168.7			799.0			115.5			1,064.1			1,091.8
End of year		755.7			110.7			916.4			1,019.1			830.9			142.4			1,172.5			1,168.7
Proved undeveloped reserves:
Beginning of year		157.7			83.3			752.5			366.4			251.8			62.9			616.6			417.5
End of year		96.5			63.0			563.3			253.4			157.7			83.3			752.5			366.4

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

(b) Extensions and discoveries as of December 31, 2018 were attributable to extensions for the Diller Project.

(c) Revisions of previous estimates were attributable to well performance.

(d) On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties.

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

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

	December 31,
	2019			2018
	(in thousands)
Future cash inflows	$	53,081		$	73,778
Future production costs		(13,031	)		(12,553	)
Future development costs		(6,569	)		(7,302	)
Future net cash flows		33,481			53,923
10% annual discount for estimated timing of cash flows		(6,729	)		(13,148	)
Standardized measure of discounted future net cash flows	$	26,752		$	40,775

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

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

	Year ended December 31,
	2019			2018
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	(8,291	)	$	17,586
Sales and transfers of oil and gas produced during the period		(9,512	)		(14,244	)
Net change due to extensions, discoveries, and improved recovery		-			1,878
Net change due to purchases and sales of minerals in place		-			(4,398	)
Changes in estimated future development costs		41			2,562
Net change due to revisions in quantities estimates		(537	)		16,587
Accretion of discount		4,078			2,459
Other		198			(6,248	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(14,023	)	$	16,182

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

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