UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

☐ 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. 000-52583

Ridgewood Energy U Fund, LLC

(Exact name of registrant as specified in its charter)

Delaware		20-5464059
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

14 Philips Parkway, Montvale, NJ 07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

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

Shares of LLC Membership Interest

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

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

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 ☒ No ☐

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

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

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐ (Do not check if a smaller reporting company)	Smaller reporting company	☒

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

There is no market for the shares of LLC Membership Interest in the Fund. As of February 27, 2017 there were 486.4825 shares of LLC Membership Interest outstanding.

RIDGEWOOD ENERGY U FUND, LLC
2016 ANNUAL REPORT ON FORM 10-K
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			PAGE

PART I
	ITEM 1	BUSINESS	2
	ITEM 1A	RISK FACTORS	10
	ITEM 1B	UNRESOLVED STAFF COMMENTS	10
	ITEM 2	PROPERTIES	10
	ITEM 3	LEGAL PROCEEDINGS	11
	ITEM 4	MINE SAFETY DISCLOSURES	11
PART II
	ITEM 5	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	11
	ITEM 6	SELECTED FINANCIAL DATA	11
	ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	17
	ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	17
	ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	17
	ITEM 9A	CONTROLS AND PROCEDURES	17
	ITEM 9B	OTHER INFORMATION	18
PART III
	ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	18
	ITEM 11	EXECUTIVE COMPENSATION	19
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	19
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	19
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	20
PART IV
	ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	20

		SIGNATURES	22

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FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy U Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections and statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 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.

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PART I

ITEM 1. BUSINESS

Overview

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

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

Manager

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. Historically, when the Fund sought project investment, 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 an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund. The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. In 2012, the Manager elected to reduce its management fee to 1% annually. Management fees during each of the years ended December 31, 2016 and 2015 were $0.3 million. Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2016 and 2015 were $0.1 million and $32 thousand, 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 and printing periodic reports for shareholders and the Securities Exchange Commission (“SEC”), commission fees, taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses. The Fund is required to reimburse the Manager for all such expenses paid on its behalf.

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 exploratory or development oil and natural gas projects. Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and Fund operations. The Fund 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, in partnership with exploration and production companies. The Fund does not expect in the future to investigate or invest in any additional projects other than those in which it currently has a working interest, as discussed below under the heading “Properties” in this Item 1. “Business” of this Annual Report. The Fund’s remaining capital has been fully allocated to complete such projects.

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The Fund has invested its capital with operators through working interest joint ventures with such operators and other energy companies that also own or acquire working interests in the projects. A working interest is an undivided fractional interest in a lease block acquired from the U.S. government or from an operator that has acquired the working interest. A working interest includes the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production. Operators will generally retain 25% to 50% interests in multiple drilling projects, rather than 100% interests in a few projects, in order to share risk, obtain independent technical validation and stretch exploration budgets that are split across numerous regions of the world.

Investment Committee

Ridgewood Energy maintains an investment committee consisting of five members, all of whom are employees of the Manager (the “Investment Committee”). The Investment Committee provides operational, financial, scientific and technical oil and gas expertise to the Fund and generally approves investments and other matters for the Fund. Two members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and three members are based out of the Manager’s Houston, Texas office. Currently, the Investment Committee’s activities surrounding 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, Ridgewood Energy negotiated participation and joint operating agreements. Under the 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. As a result, Ridgewood Energy and other non-operating partners generally retain the right to make proposals and influence decisions involving certain operational matters associated with a project. This approval discretion and the operator’s desire to execute the project efficiently and expeditiously can function to limit the operator’s inclination to act on its own, or against the interests of the participants in the project.

Project Information

The Fund’s existing projects are located in the waters of the Gulf of Mexico, offshore Louisiana, 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, 8 or 10 years, depending on the water depth of the lease block. During a primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, 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, working interests in an offshore oil and natural gas lease under the OCSLA pay a 12.5%, 16.67% or 18.75% royalty to the Office of Natural Resources Revenue (“ONRR”) depending on the lease. Other than the ONRR royalties, the Fund does not have material royalty burdens.

Deep Gas Royalty Relief

On January 26, 2004, the Bureau of Ocean Energy Management (“BOEM”), an agency of the United States Department of Interior, promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the “Royalty Relief Rule”). The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the OCS nor does it apply if the price of natural gas exceeds $11.60 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation. The Fund currently has one project, the Cobalt Project, which qualifies for royalty relief under the Royalty Relief Rule.

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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 Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $37.30 per barrel and $48.43 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 $4.66 per mmbtu and $8.07 per mmbtu) adjusted annually for inflation. The Fund currently has two projects, the Diller and Marmalard projects, which qualify for royalty relief under the Deepwater Royalty Relief Act.

Properties

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which the Fund owned an interest as of December 31, 2016. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, each of which produces both oil and natural gas, are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

	Total Productive Wells
	Gross		Net
Oil and natural gas		6		0.09

Acreage Data

The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 2016. 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 gas leases that have varying terms. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.

Developed Acres				Undeveloped Acres
Gross		Net		Gross		Net
	22,280		401		11,520		101

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.

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			Total Spent
	Working		through		Total Fund
Project	Interest		December 31, 2016		Budget		Status
			(in thousands)
Producing Properties
Cobalt Project		5.0%	$	2,368	$	2,496	The Cobalt Project, a single-well project, commenced production in 2009. Recompletions are planned for 2017 and 2018 at an estimated total cost of $60 thousand. The Fund expects to spend $68 thousand for asset retirement obligations.

Diller Project		0.88%	$	2,787	$	3,938	The Diller Project is expected to include the development of two wells. Well #1 commenced production during third quarter 2015. Well #2 is expected to commence production in 2019. Well #1, which was shut-in in late-2016 due to well hydrate remediation work, resumed production in mid-January 2017. The Fund expects to spend $0.8 million for additional development costs and $0.4 million for asset retirement obligations.

Marmalard Project		0.88%	$	5,597	$	9,329	The Marmalard Project is expected to include the development of six wells. Wells #1, #2 and #3 commenced production during second quarter 2015. Well #4 commenced production during fourth quarter 2015. Additional wells are expected to commence production in 2019 and 2020. The Fund expects to spend $2.6 million for additional development costs and $1.1 million for asset retirement obligations.

Sale of Investment in Delta House

As of December 31, 2016, the Fund invested a total of $0.6 million in Delta House and has received cash from its investment totaling $0.6 million, of which $0.3 million relates to dividends received and $0.3 million relates to cash proceeds from the sale of approximately 74% of its investment, pursuant to a unit purchase agreement with D-Day Offshore Holdings, LLC dated October 31, 2016. Certain other funds managed by the Manager were also parties to this unit purchase agreement. The Fund adjusted the carrying value of its investment in Delta House in third quarter 2016 to fair value, which was determined based on the third party sale and recorded a loss on investment during the year ended December 31, 2016 of $0.1 million. The loss was included on the Fund’s statement of operations within “Loss on investment in Delta House”. Inputs used to estimate fair value of the investment in Delta House are categorized as Level 3 in the fair value hierarchy. As of December 31, 2016, the Fund’s remaining carrying value for the investment in Delta House was $0.1 million.

Marketing/Customers

The Manager, on behalf of the Fund, markets the Fund’s oil and natural gas to third parties consistent with industry practice. During 2015, DH Sales and Transport, LLC (“DH S&T”), a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Diller and Marmalard projects. During 2016, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2016, the Fund had four 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.

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The Fund’s natural gas and oil generally is sold to its customers at prevailing market prices, which fluctuate with demand as a result of related industry variables. Historically, 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. During the year ended December 31, 2016, fluctuations in commodity prices had an adverse effect on the Fund’s profitability and distributions. 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 fix the future prices or 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.

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 2016.

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 LLOG Exploration Offshore, L.L.C. and W&T Offshore, Inc.

Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders not only had to bear the risk that the Manager would find suitable projects, but also that, once selected, have to bear the risk that such projects will be managed prudently, efficiently and fairly by the operators.

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 funds 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 to the Fund or to its affiliates, yearly insurance coverage limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for its proportionate share of the anticipated cost of dismantling production platforms and facilities, plugging and abandoning the wells, and removing the platforms, facilities and wells in respect of the projects after the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2016, the Fund has $1.7 million invested in a salvage fund. On a monthly basis, the Fund expects to contribute to the salvage fund a portion of the operating income from the Diller and Marmalard projects, to fund the asset retirement obligations of such projects. Such contributions to the salvage fund will reduce the amount of cash distributions that would 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.

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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 its 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 1254 Enclave Parkway, Houston, TX 77077 and 125 Worth Avenue, Suite 318, Palm Beach, Florida, 33480. In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.

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. In April 2016, BSEE adopted a final rule establishing updated standards for blowout prevention systems and other well controls pertaining to offshore activities. The final rule became effective July 28, 2016; compliance with certain provisions of the final rule, however, are deferred as specified. The final rule imposes new requirements relating to, among, other things, 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. The rule applies directly to operators as opposed to non-operators. However, the costs associated with compliance, which at this time cannot be determined or estimated, will likely increase the costs of operating in the Gulf of Mexico and such costs will be imposed upon all working interest owners, including the Fund. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties 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.

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BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL”) 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, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM 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.

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 upon 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 any environmental damage. 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 increases 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 establishes a liability limit for onshore facilities and deepwater ports of $633.85 million, while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $133.65 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. The 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.

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Clean Water Act. Generally, the Clean Water Act 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 state, if applicable, agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.

Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), 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.

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 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 regulations 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 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. The Fund cannot predict at this time what regulations or portions of the law, if any, will be changed as a result of the Order.

Under its LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. 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 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 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 2016 or at any time since 2012, a party to any derivative instruments or hedging programs.

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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 resource extraction issuer payment disclosure rules pursuant to Section 1504 of the Dodd-Frank Act that will require resource extraction companies to publicly file with the SEC information about the type and total amount of payments made to a foreign government or to the U.S. federal government for each project related to the development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government. However, on February 14, 2017, a bill passed by the United States Congress was signed eliminating the SEC resource extraction issuer payment disclosure rules. The SEC will have one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act.

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, 2016 and 2015. Gross wells are the total number of wells in which the Fund has an 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.

	2016				2015
	Gross		Net		Gross		Net
Exploratory wells:
Productive		-		-		2		0.02
Exploratory well total		-		-		2		0.02

Development wells:
Productive		-		-		3		0.03
Development well total		-		-		3		0.03

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

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.

The Fund’s reserve estimates as of December 31, 2016 and 2015 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.

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Proved Reserves. Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from 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, 2016, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.1 million barrels of oil, 67 thousand barrels of natural gas liquid (“NGL”) and 0.5 million mcf of natural gas. As of December 31, 2015, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.2 million barrels of oil, 45 thousand barrels of NGL and 0.4 million mcf of natural gas. The Marmalard Project was determined to be a discovery in 2012 and commenced production during 2015.

During the year ended December 31, 2016, the Fund did not incur costs to advance the development of the proved undeveloped reserves related to the Marmalard Project. The Fund currently expects to develop the proved undeveloped reserves relating to the Marmalard Project over the next several years. Information regarding estimated future development costs relating to the Marmalard Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, 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. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.

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, 2016 and 2015 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, 2016, the Fund had no delivery obligations or delivery commitments under any existing contracts.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II

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

There is currently no established public trading market for the Shares. As of January 31, 2017, there were 967 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Due to the significant capital required to develop the Diller and Marmalard projects, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for their ongoing development costs and funding of their estimated asset retirement obligations. 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, 2016 and 2015, the Fund paid distributions totaling $0.7 million and $0.2 million, respectively.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

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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 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 exploratory or development oil and natural gas projects. Distributions to shareholders are made in accordance with the Fund’s LLC Agreement. The Fund does not expect in the future to investigate or invest in any additional projects other than those in which it currently has a working interest. The Fund’s remaining capital has been fully allocated to complete such projects.

The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. The Fund 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 exploration, development and producing operations, as appropriate. 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 commodity prices may significantly affect liquidity and expected operating results. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment.

During fourth quarter 2014, there was a significant decline in oil and natural gas commodity prices, which continued into mid-year 2016 when oil and gas commodity prices began to show improvement. The Fund plans for price cyclicality in its planning and believes it is well positioned to withstand such price volatility. The Fund continues to conserve cash to complete the ongoing development of the Diller and Marmalard projects. 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, 2016 and 2015 and the effect of such decreased average prices on the Fund’s results of operations. If oil and natural gas prices decline, even if only for a short period of time, the Fund’s results of operations and liquidity will continue to be adversely impacted.

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

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.

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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 that management believes are most significant.

Accounting for Acquisition, Exploration and Development Costs

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 engineer 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, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change.

Asset Retirement Obligations

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

Impairment of Long-Lived Assets

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

Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have resulted in impairments of oil and gas properties as described below in this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Results of Operations - Impairment of Oil and Gas Properties”. If oil and natural gas prices decline, even if only for a short period of time, it is possible that additional impairments of oil and gas properties will occur.

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Results of Operations

The following table summarizes the Fund’s results of operations during the years ended December 31, 2016 and 2015, 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,
	2016			2015
	(in thousands)
Revenue
Oil and gas revenue	$	4,302		$	2,386
Expenses
Depletion and amortization		1,863			1,476
Impairment of oil and gas properties		-			142
Management fees to affiliate		262			262
Operating expenses		2,655			1,738
General and administrative expenses		146			141
Total expenses		4,926			3,759
Loss from operations		(624	)		(1,373	)
Other (loss) income
Loss on investment in Delta House		(114	)		-
Dividend income		191			75
Interest income		2			3
Total other income		79			78
Net loss	$	(545	)	$	(1,295	)

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, 2016 and 2015. NGL sales are included within gas sales.

	Year ended December 31,
	2016		2015
Number of wells producing		6		6
Total number of production days		1,915		1,177
Oil sales (in thousands of barrels)		91		45
Average oil price per barrel	$	41	$	46
Gas sales (in thousands of mcfs)		220		125
Average gas price per mcf	$	2.41	$	2.53

The increases noted in the above table were primarily related to the commencement of production of the Diller and Marmalard projects. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.

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

Oil and gas revenue during the year ended December 31, 2016 was $4.3 million, an increase of $1.9 million from the year ended December 31, 2015. The increase was attributable to increased sales volume totaling $2.3 million, partially offset by decreased oil and gas prices totaling $0.4 million.

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

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Depletion and Amortization. Depletion and amortization during the year ended December 31, 2016 was $1.9 million, an increase of $0.4 million from the year ended December 31, 2015. The increase was attributable to an increase in production volumes totaling $1.1 million, partially offset by a decrease in the average depletion rate totaling $0.5 million and adjustments to asset retirement obligations related to fully depleted properties totaling $0.3 million, which were recorded in second quarter of 2015. The decrease in the average depletion rate was primarily attributable to the lower cost of reserves for the Diller and Marmalard projects. Depletion and amortization rates are also impacted by changes in reserve estimates provided annually by the Fund’s independent petroleum engineers.

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

Impairment of Oil and Gas Properties. The Fund did not record any impairments of oil and gas properties during the year ended December 31, 2016. During the year ended December 31, 2015, the Fund recorded an impairment of oil and gas properties of $0.1 million related to the Cobalt Project, which was attributable to both declines in future oil and gas prices and revisions to reserve estimates as provided by the Fund’s independent petroleum engineers.

Management Fees to Affiliate. An annual management fee, totaling 1% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term capital commitments.

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

	Year ended December 31,
	2016		2015
	(in thousands)
Lease operating expense	$	2,135	$	1,454
Transportation expense		322		153
Insurance expense		46		53
Accretion expense		25		64
Workover expense and other		127		14
	$	2,655	$	1,738

Lease operating expense and transportation expense relates to the Fund’s producing properties. Insurance expense represents premiums related to the Fund’s properties, which vary depending upon the number of wells producing or drilling. Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties. Workover expense represents costs to restore or stimulate production of existing reserves. During the year ended December 31, 2016, workover expense primarily relates to the Diller and Marmalard projects.

The average production cost, which includes lease operating expense, transportation expense and insurance expense, was $19.67 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2016, compared to $25.34 per BOE during the year ended December 31, 2015. The decrease was primarily attributable to the Marmalard and Diller projects, which had higher average production costs per BOE in 2015 as a result of costs associated with the projects’ onset of production.

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

Loss on Investment in Delta House. During the year ended December 31, 2016, the Fund recognized a loss on investment of $0.1 million related to its investment in Delta House. There were no such amounts recorded during the year ended December 31, 2015. See Note 1 of “Notes to Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Investment in Delta House.

Dividend Income. Dividend income is related to the Fund’s investment in Delta House. See Note 1 of “Notes to Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Investment in Delta House.

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

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Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities during the year ended December 31, 2016 were $1.4 million, related to revenue received of $4.3 million and dividend income received of $0.2 million, partially offset by operating expenses of $2.7 million, management fees of $0.3 million, and general and administrative expenses of $0.1 million.

Cash flows provided by operating activities during the year ended December 31, 2015 were $0.3 million, related to revenue received of $2.1 million and dividend income received of $0.1 million, partially offset by operating expenses of $1.4 million, management fees of $0.3 million, and general and administrative expenses of $0.1 million.

Investing Cash Flows

Cash flows used in investing activities during the year ended December 31, 2016 were $0.1 million, primarily related to investments in salvage fund of $0.4 million partially offset by proceeds from the sale of investment in Delta House of $0.3 million.

Cash flows used in investing activities during the year ended December 31, 2015 were $3.3 million, related to capital expenditures for oil and gas properties and investment in Delta House of $3.2 million and investments in salvage fund of $0.1 million.

Financing Cash Flows

Cash flows used in financing activities during the year ended December 31, 2016 were $0.7 million, related to manager and shareholder distributions.

Cash flows used in financing activities during the year ended December 31, 2015 were $0.2 million, related to manager and shareholder distributions.

Estimated Capital Expenditures

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

Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering. The number of projects in which the Fund could invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.

Liquidity Needs

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

As of December 31, 2016, the Fund’s estimated capital commitments related to its oil and gas properties were $6.0 million (which include asset retirement obligations for the Fund’s projects of $2.5 million), of which $0.1million is expected to be spent during the year ending December 31, 2017. 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 as well as 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. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. Due to the significant capital required to develop the Diller and Marmalard projects, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for their ongoing development costs and funding their estimated asset retirement obligations.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of December 31, 2016 and 2015 and does not anticipate the use of such arrangements in the future.

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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, 2016 and 2015 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

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

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 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits and Financial Statement Schedules” and filed as part of this report.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2016. 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)). 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, 2016. 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, 2016, 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 to provide only management’s report in this Annual Report.

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Changes in Internal Control over Financial Reporting

The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 2016 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, 2016 are as follows:

Name, Age and Position with Registrant

Robert E. Swanson, 69

Chief Executive Officer

Kenneth W. Lang, 62

President and Chief Operating Officer

Kathleen P. McSherry, 51

Executive Vice President and Chief Financial Officer

Robert L. Gold, 58

Executive Vice President

Daniel V. Gulino, 56

Senior Vice President, General Counsel and Secretary

The officers in the above table have been officers of the Fund since April 12, 2006, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. 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 and Ridgewood Private Equity Partners, LLC, and President of 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. 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.

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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 and Ridgewood Private Equity Partners, 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 or in a current report on Form 8-K. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN: General Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, 2016, all filing requirements applicable to its officers, directors and 10% beneficial owners were met on a timely basis.

ITEM 11. EXECUTIVE COMPENSATION

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

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

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 486.4825 shares outstanding as of January 31, 2017. The following table sets forth information with respect to beneficial ownership of the Shares as of January 31, 2017 (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.

	Number
Name of beneficial owner	of shares	Percent

Robert L. Gold	0.1667	*
Executive officers as a group	0.1667	*

* 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, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. In 2012, the Manager elected to reduce its management fee to 1% annually. Management fees during each of the years ended December 31, 2016 and 2015 were $0.3 million.

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The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager during the years ended December 31, 2016 and 2015 were $0.1 million and $32 thousand, respectively.

None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.

During 2015, DH S&T, a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Diller and Marmalard projects. During 2016, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, DH S&T is pass-through entity such that it receives no benefit or compensation for the services provided under the agreement or under any other agreements it enters into with regard to the oil and gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless DH S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Diller and Marmalard projects. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations. These revenues and operating expenses allocable to the Fund are based on the Fund’s working interest ownership in the Diller and Marmalard projects.

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

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with 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, 2016 and 2015.

	Year ended December 31,
	2016		2015
	(in thousands)
Audit fees⁽¹⁾	$	88	$	88

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

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1) Financial Statements

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

(a) (2) Financial Statement Schedules

None.

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(a) (3)

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING

3.1	Certificate of Formation of Ridgewood Energy U Fund, LLC dated August 28, 2006	Incorporated by reference to the Fund’s Form 10 filed on April 26, 2007

3.2	Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy U Fund, LLC dated October 1, 2006	Incorporated by reference to the Fund’s Form 10 filed on April 26, 2007

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

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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 U FUND, LLC


Date: February 27, 2017	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	February 27, 2017
Robert E. Swanson	(Principal Executive Officer)


/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer	February 27, 2017
Kathleen P. McSherry	(Principal Financial and Accounting Officer)


RIDGEWOOD ENERGY CORPORATION

BY: /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	February 27, 2017
Robert E. Swanson

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INDEX TO FINANCIAL STATEMENTS	PAGE

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2016 and 2015	F-3
Statements of Operations for the years ended December 31, 2016 and 2015	F-4
Statements of Changes in Members' Capital for the years ended December 31, 2016 and 2015	F-5
Statements of Cash Flows for the years ended December 31, 2016 and 2015	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-12

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying balance sheets of Ridgewood Energy U Fund, LLC (the "Fund") as of December 31, 2016 and 2015, and the related statements of operations, changes in members' capital, and cash flows for the years then ended. These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy U Fund, LLC as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Parsippany, New Jersey

February 27, 2017

F-2

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RIDGEWOOD ENERGY U FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2016			2015
Assets
Current assets:
Cash and cash equivalents	$	1,463		$	855
Salvage fund		117			117
Production receivable		361			353
Other current assets		22			-
Total current assets		1,963			1,325
Salvage fund		1,588			1,142
Investment in Delta House		119			572
Oil and gas properties:
Proved properties		11,143			11,218
Less: accumulated depletion and amortization		(5,358	)		(3,508	)
Total oil and gas properties, net		5,785			7,710
Total assets	$	9,455		$	10,749

Liabilities and Members' Capital
Current liabilities:
Due to operators	$	265		$	310
Accrued expenses		59			42
Asset retirement obligations		117			117
Total current liabilities		441			469
Asset retirement obligations		1,349			1,365
Total liabilities		1,790			1,834
Commitments and contingencies (Note 3)
Members' capital:
Manager:
Distributions		(1,342	)		(1,236	)
Retained earnings (accumulated deficit)		161			(38	)
Manager's total		(1,181	)		(1,274	)
Shareholders:
Capital contributions (1,000 shares authorized;
486.4825 issued and outstanding)		72,381			72,381
Syndication costs		(8,541	)		(8,541	)
Distributions		(9,895	)		(9,296	)
Accumulated deficit		(45,099	)		(44,355	)
Shareholders' total		8,846			10,189
Total members' capital		7,665			8,915
Total liabilities and members' capital	$	9,455		$	10,749

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

F-3

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RIDGEWOOD ENERGY U FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2016			2015
Revenue
Oil and gas revenue	$	4,302		$	2,386
Expenses
Depletion and amortization		1,863			1,476
Impairment of oil and gas properties		-			142
Management fees to affiliate (Note 2)		262			262
Operating expenses		2,655			1,738
General and administrative expenses		146			141
Total expenses		4,926			3,759
Loss from operations		(624	)		(1,373	)
Other (loss) income
Loss on investment in Delta House		(114	)		-
Dividend income		191			75
Interest income		2			3
Total other income		79			78
Net loss	$	(545	)	$	(1,295	)

Manager Interest
Net income	$	199		$	41

Shareholder Interest
Net loss	$	(744	)	$	(1,336	)
Net loss per share	$	(1,530	)	$	(2,747	)

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

F-4

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RIDGEWOOD ENERGY U FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)

	# of Shares		Manager			Shareholders			Total

Balances, December 31, 2014		486.4825	$	(1,283	)	$	11,711		$	10,428
Distributions		-		(32	)		(186	)		(218	)
Net income (loss)		-		41			(1,336	)		(1,295	)
Balances, December 31, 2015		486.4825		(1,274	)		10,189			8,915
Distributions		-		(106	)		(599	)		(705	)
Net income (loss)		-		199			(744	)		(545	)
Balances, December 31, 2016		486.4825	$	(1,181	)	$	8,846		$	7,665

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

F-5

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RIDGEWOOD ENERGY U FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2016			2015

Cash flows from operating activities
Net loss	$	(545	)	$	(1,295	)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion and amortization		1,863			1,476
Impairment of oil and gas properties		-			142
Loss on investment in Delta House		114			-
Accretion expense		25			64
Changes in assets and liabilities:
Increase in production receivable		(8	)		(332	)
(Increase) decrease in other current assets		(22	)		8
(Decrease) increase in due to operators		(45	)		237
Increase in accrued expenses		17			-
Net cash provided by operating activities		1,399			300

Cash flows from investing activities
Credits (capital expenditures) for oil and gas properties and
investment in Delta House		21			(3,195	)
Proceeds from sale of investment in Delta House		339			-
Increase in salvage fund		(446	)		(103	)
Net cash used in investing activities		(86	)		(3,298	)

Cash flows from financing activities
Distributions		(705	)		(218	)
Net cash used in financing activities		(705	)		(218	)

Net increase (decrease) in cash and cash equivalents		608			(3,216	)
Cash and cash equivalents, beginning of year		855			4,071
Cash and cash equivalents, end of year	$	1,463		$	855

Supplemental disclosure of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$	-		$	589

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

F-6

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RIDGEWOOD ENERGY U FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy U Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 28, 2006 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of October 1, 2006 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. With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 2 and 3.

Use of Estimates

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

Fair Value Measurements

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

Cash and Cash Equivalents

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2016, 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, 2016, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.

Salvage Fund

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

Investment in Delta House

The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by LLOG Exploration Company. The Fund accounts for its investment in Delta House using the cost method of accounting for investments as it does not have the ability to exercise significant influence over such investment. Under the cost method, the Fund recognizes an investment in the equity of an investee at cost. The Fund recognizes as income dividends received that are distributed from net accumulated earnings of the investee since the date of acquisition by the Fund. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment. The Fund reviews its cost method investment for impairment at each reporting period and when an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment. Losses on cost method investments including impairments that are deemed to be other than temporary are classified as non-operating losses in the Fund’s statements of operations.

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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 well 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.

Advances to Operators for Working Interests and Expenditures

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

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2016 and 2015.

	2016			2015
	(in thousands)
Balance, beginning of year	$	1,482		$	1,028
Liabilities incurred		-			37
Accretion expense		25			64
Revision of estimates		(41	)		353
Balance, end of year	$	1,466		$	1,482

As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

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Syndication Costs

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

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.

Impairment of Long-Lived Assets

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

Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund’s oil and gas properties. There were no impairments of oil and gas properties during the year ended December 31, 2016. During the year ended December 31, 2015, the Fund recorded an impairment of oil and gas properties of $0.1 million related to the Cobalt Project, which was attributable to both declines in future oil and gas prices and revisions to reserve estimates as provided by the Fund’s independent petroleum engineers. The fair value of the impaired property at the date of impairment was $0.2 million. If oil and natural gas prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur.

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. During the year ended December 31, 2015, the Fund recorded $0.3 million of depletion expense related to adjustments to asset retirement obligations for fully depleted properties.

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 2013 through 2015 tax returns remain open for examination by tax authorities.

Income and Expense Allocation

Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement.

Distributions

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

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

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Recent Accounting Pronouncements

In January 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that requires, among other things, companies to measure investments in other entities, except those accounted for under the equity method, at fair value and recognize any changes in fair value in net income unless an election is made to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. This pronouncement is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, with early adoption not permitted. The Fund is currently evaluating the impact of this guidance on its financial statements.

In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Based on the Fund’s initial assessment of the accounting guidance, the Fund currently does not expect it will have a material impact on its results of operations or cash flows in the period after adoption. Under the accounting guidance, revenue is recognized as control transfers to the customer, as such the Fund expects the application of the accounting guidance to its existing contracts to be generally consistent with its current revenue recognition model. The Fund will continue the evaluation of the provisions of this accounting guidance, as well as new or emerging interpretations, as it relates to new contracts the Fund receives and in particular as it relates to disclosure requirements through the date of adoption, which is currently expected to be January 1, 2018.

2. Related Parties

Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is entitled to an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments. In 2012, the Manager elected to reduce its management fee to 1% annually. Management fees during each of the years ended December 31, 2016 and 2015 were $0.3 million.

None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.

In February 2015, DH Sales and Transport, LLC (“DH S&T”), a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager (the “Ridgewood Delta House Funds”) to facilitate the transportation and sale of oil and gas produced from the Diller and Marmalard projects. On April 11, 2016, the Ridgewood Delta House Funds entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from Ridgewood Delta House Funds all of their interests in oil and gas produced at the Diller and Marmalard projects and sell such volumes to unrelated third party purchasers.

Pursuant to the master agreement, DH S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and gas purchased from the Ridgewood Delta House Funds. The Ridgewood Delta House Funds have agreed to indemnify, defend and hold harmless DH S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of DH S&T’s dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Diller and Marmalard projects. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations. These revenues and operating expenses allocable to the Fund are based on the Fund’s working interest ownership in the Diller and Marmalard projects.

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

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

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3. Commitments and Contingencies

Capital Commitments

As of December 31, 2016, the Fund’s estimated capital commitments related to its oil and gas properties were $6.0 million (which include asset retirement obligations for the Fund’s projects of $2.5 million), of which $ 0.1 million is expected to be spent during the year ending December 31, 2017. 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 as well as 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.

Environmental Considerations

The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. 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 and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. 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, 2016 and 2015, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations. 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. 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.

BOEM Notice to Lessees on Supplemental Bonding

On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) 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, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM 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.

Insurance Coverage

The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. 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 funds managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other funds 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 U 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 Louisiana in the Gulf of Mexico.

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

	December 31,
	2016			2015
	(in thousands)
Proved properties	$	11,143		$	11,218
Total oil and gas properties		11,143			11,218
Accumulated depletion and amortization		(5,358	)		(3,508	)
Oil and gas properties, net	$	5,785		$	7,710

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

	Year ended December 31,
	2016			2015
	(in thousands)
Exploration costs	$	17		$	5
Development costs		(60	)		3,279
	$	(43	)	$	3,284

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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, 2016 and 2015. 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, 2016									December 31, 2015
	United States
	Oil (BBLS)			NGL (BBLS)			Gas (MCF)			Oil (BBLS)			NGL (BBLS)			Gas (MCF)

Proved developed and undeveloped reserves:
Beginning of year		547,595			98,544			980,059			477,973			437			1,223,969
Revisions of previous estimates (a)		(7,145	)		71,601			382,003			114,384			105,524			(160,076	)
Production		(90,560	)		(7,785	)		(174,462	)		(44,762	)		(7,417	)		(83,834	)
End of year		449,890			162,360			1,187,600			547,595			98,544			980,059

Proved developed reserves:
Beginning of year		338,935			53,401			530,719			1,352			437			51,737
End of year		334,510			95,310			697,170			338,935			53,401			530,719

Proved undeveloped reserves:
Beginning of year		208,660			45,143			449,340			476,621			-			1,172,232
End of year		115,380			67,050			490,430			208,660			45,143			449,340

(a)

Revisions of previous estimates were attributable to well performance.

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

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

	December 31,
	2016			2015
	(in thousands)
Future cash inflows	$	21,275		$	30,133
Future production costs		(8,196	)		(10,703	)
Future development costs		(5,214	)		(5,727	)
Future net cash flows		7,865			13,703
10% annual discount for estimated timing of cash flows		(1,582	)		(4,300	)
Standardized measure of discounted future net cash flows	$	6,283		$	9,403

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,
	2016			2015
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	(4,519	)	$	(13,448	)
Sales and transfers of oil and gas produced during the period		(1,799	)		(726	)
Changes in estimated future development costs		513			(11	)
Net change due to revisions in quantities estimates		1,652			3,183
Accretion of discount		940			1,948
Other		93			(1,022	)
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	(3,120	)	$	(10,076	)

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.