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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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.  The Fund was organized 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 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 in which the investments are made.  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.  In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations.  The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 74 and 9.6.

These unaudited interim condensed financial statements have been prepared by the Fund’s management in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Fund’s financial position, results of operations and cash flows for the periods presented. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted in these unaudited interim condensed financial statements.  The results of operations, financial position, and cash flows for the periods presented herein are not necessarily indicative of future financial results.  These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2010 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”).  The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

The preparation of financial statements in accordance with 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, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.

All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents.  At times, deposits may be in excess of federally insured limits, which, for interest bearing deposits, are $250 thousand per insured financial institution.  Additionally, non-interest bearing deposits are fully insured through December 31, 2012, after which they will be included within the $250 thousand limit.  At JuneSeptember 30, 2011, the Fund’s bank balances exceeded federally insured limits by $7.6$3.1 million, all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

At times, the Fund may invest in U.S. Treasury bills and notes.  These investments are considered short-term when their maturities are one year or less, and long-term when their maturities are greater than one year.  The Fund currently has short-term investments that are classified as held-to-maturity.  Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value.  At JuneSeptember 30, 2011, the Fund had short-term, held-to-maturity investments of $3.0 million and $4.5 million, which mature in December 2011.2011 and February 2012, respectively.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.

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.

The successful efforts method of accounting for oil and gas producing activities is followed.  Acquisition costs are capitalized when incurred.  Other oil and gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves.  If proved commercial reserves have not been found, exploratory drilling costs are expensed as dry-hole costs.  Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of oil and gas, are capitalized.  Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred.

Upon the sale or retirement of a proved property, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized.

Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.

At JuneSeptember 30, 2011 and December 31, 2010, amounts recorded in due to operators totaling $0.4$0.6 million and $1.4 million, respectively, related to capital expenditures for oil and gas properties.

The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest.  The Fund may be required to advance its share of estimated cash expenditures for the succeeding month’s operation.  The Fund accounts for such payments as advances to operators for working interests and expenditures.  As drilling costs are incurred, the advances are reclassified to unproved or proved properties.

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired.  When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

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.

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review.  If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred.  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.  If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

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.  The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs.

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.

Profits and losses are allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for interest income and certain expenses such as dry-hole costs, trust fees, depletion and amortization, which are allocated 99% to shareholders and 1% to the Manager.

In January 2010,The Manager determines whether available cash from operations, as defined in the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements.  This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective beginning January 1, 2010.  The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, whichLLC Agreement, will be effective fordistributed. Such distributions are allocated 85% to the Fund’s financial statements forshareholders and 15% to the year ending December 31, 2011. The adoption ofManager, as required by the guidance is not expected to have a material impact.LLC Agreement.

The Fund periodically enters into derivative contracts relating to its oil or gas production. In JanuaryDuring the first quarter 2011, the Fund entered into two eight-month derivative contracts for put options relating to the pricing of gas for a portion of its anticipated production.  During the second quarter 2011, the Fund entered into three twelve-month derivative contracts for put options relating to the pricing of oil for a portion of its anticipated production.  The use of such derivative instruments limits the downside risk of adverse price movements.  Currently, the Fund has elected not to use hedge accounting for its derivatives and consequently, the derivatives are marked-to-market each quarter with fair value gains and losses recognized as other income on the statement of operations.  The estimated fair value of these contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  See Note 8.5. “Fair Value Measurements.”  The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.

Derivative instruments are carried at their fair value on the balance sheet within “Other current assets”.  The derivative contracts relating to gas pricing are settled based upon reported prices on NYMEX.  The derivative contracts relating to oil pricing are settled based upon averaged reported prices on ICE.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis in the statement of operations under the caption “Other (loss) income.”  Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.

At JuneSeptember 30, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil and gas that are not designated for hedge accounting as detailed in the following tables.

For the three and sixnine months ended JuneSeptember 30, 2011 and 2010, the Fund’s derivative instrument income consisted of the following:

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves.  Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves.  At JuneSeptember 30, 2011, the Fund had one unproved property, the Alpha Project, with capitalized exploratory well costs in excess of one year.  The Fund is currently undergoing completion efforts for the Alpha Project and production is expected to commence fourthduring the first quarter 2011.2012.

During June 2010, the Fund sold its interest in the Ajax Project to KNOC USA Corporation and Samsung Oil & Gas USA Corp., for net proceeds of $0.7 million in cash and estimated overriding royalty interest amounts, which resulted in a gain of $0.4 million.  At the time of the sale, the carrying value for the Ajax Project was $0.3 million, which reflectsreflected a prior year impairment charge of $1.1 million.  During the three and sixnine months ended JuneSeptember 30, 2011, the Fund recorded a loss on sale of oil and gas properties of $10 thousand as a result of additional asset retirement obligations related to the Ajax Project.

In December 2010, after determining not to proceed with the completion of the Aspen Project, the Fund entered into an agreement to sell its working interest in the Aspen Project to Stone Energy Corporation, for net proceeds of $1.8 million in cash, which resulted in a loss of $2.7 million.  The proceeds from the sale of the Aspen Project were collected in January 2011.

Capitalized exploratory well costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field.  At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.  Dry-hole costs, inclusive of such credits, are detailed in the following table.

The LLC Agreement provides that the Manager render management, administrative and advisory services.  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.  Management fees for the three months ended JuneSeptember 30, 2011 and 2010 were $0.2 million and $0.3 million, respectively.  Management fees for the sixnine months ended JuneSeptember 30, 2011 and 2010 were $0.5$0.7 million and $0.6$0.8 million, respectively.

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

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

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.

At JuneSeptember 30, 2011 and December 31, 2010, cash and cash equivalents, short-term investments in marketable securities, production receivable, receivable from sale of oil and gas properties, salvage fund and accrued expenses approximate fair value.  At JuneSeptember 30, 2011, derivative instruments are recorded at fair value based on Level 2 inputs, as the instruments are over-the-counter derivatives with a third party.

The Fund has entered into multiple agreements for the drilling and development of its investment properties.  The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis.  As of JuneSeptember 30, 2011, the Fund had committed to spend an additional $10.4$9.1 million related to its investment properties, of which $5.8$4.0 million is expected to be spent during the next twelve months.

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.  At JuneSeptember 30, 2011 and December 31, 2010, there were no known environmental contingencies that required the Fund to record a liability.

In response to the April 2010 oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore.  Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our 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.

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 an adverse impact upon earnings and financial position.  Moreover, insurance is obtained as a package covering all of the funds managed by the Manager.  Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.

On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011.  Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

The Fund has assessed the impact of subsequent events through the date of issuance of its financial statements, and has concluded that there were no such events that require adjustment to, or disclosure in, the notes to the financial statements.

Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy U Fund, LLC (the “Fund”) has incorporated by reference into this Quarterly Report, other than purely historical information, including estimates, projections, 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 US 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 conditions affecting the pricing of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations.  Examples of forward-looking statements made herein include statements regarding future projects, investments and insurance.  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.

The following discussion and analysis of the Fund’s financial condition and operating results is based on its financial statements.  The preparation of this Quarterly Report requires the Fund to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of the Fund’s financial statements, and the reported amount of revenue and expense during the reporting period. Actual results may differ from those estimates and assumptions.  See “Notes to Unaudited Condensed Financial Statements” in Part I of this Quarterly Report for a presentation of the Fund’s significant accounting policies.  No changes have been made to the Fund’s critical accounting policies and estimates disclosed in its 2010 Annual Report on Form 10-K.

The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing management, administrative and advisory services associated with these projects. For these services, the Manager receives an annual management fee equal to 2.5% of capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, payable monthly.  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.  The Manager also participates in distributions.

Revenues are subject to market pricing for oil and natural gas, which has been 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. Low commodity prices could have an adverse affect on the Fund’s future profitability.

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.

On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011.  Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

The following table summarizes the Fund’s results of operations for the three and sixnine months ended JuneSeptember 30, 2011 and 2010, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1 “Financial Statements” in Part I of this Quarterly Report.

Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling and directors’ and officers’ liability insurance.  Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

Cash flows provided by operating activities for the sixnine months ended JuneSeptember 30, 2011 were $1.2$1.6 million, primarily related to revenue received of $2.0$2.8 million, partially offset by management fees of $0.5$0.7 million, operating expenses paid of $0.2 million, general and administrative expenses of $0.1$0.2 million and the purchase of derivative instruments of $0.1 million.

Cash flows used inprovided by operating activities for the sixnine months ended JuneSeptember 30, 2010 were $0.1$0.3 million, primarily related to revenue received of $1.5 million and favorable working capital of $0.1 million, partially offset by management fees of $0.6$0.8 million, general and administrative expenses of $0.2$0.4 million and operating expenses of $0.1 million, partially offset by revenue received of $0.7 million.

Cash flows provided by investing activities for the sixnine months ended JuneSeptember 30, 2010 were $8.0$7.0 million, primarily related to the maturity of investments in U.S. Treasury securities of $14.0 million coupled with theand proceeds from the sale of the Ajax Project totaling $0.7 million, partially offset by capital expenditures for oil and gas properties of $3.7$4.7 million inclusive of advances and investments in U.S. Treasury securities of $3.0 million.

Cash flows used in financing activities for the sixnine months ended JuneSeptember 30, 2010 were $0.2$1.3 million, related to manager and shareholder distributions.

The Fund has entered into multiple agreements for the acquisition, drilling and development of its investment properties.  The estimated capital expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis.  As of JuneSeptember 30, 2011, the Fund had committed to spend an additional $10.4$9.1 million related to its investment properties, of which $5.8$4.0 million is expected to be spent during the next twelve months.

When the Manager makes a decision to participate in an exploratory project, it assumes that the well will be successful and allocates enough capital to budget for the completion of that well and the additional development wells and infrastructure anticipated.  If an exploratory well is deemed a dry hole or if it is determined by the Manager to be un-economical, the capital allocated to the completion of that well and to the development of additional wells is then reallocated to a new project or used to make additional investments.

Capital expenditures for investment properties are funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain.  The number of projects in which the Fund can invest is limited, and each unsuccessful project the Fund experiences exhausts its capital and reduces its ability to generate revenue.

The Fund’s primary short-term liquidity needs are to fund its operations, inclusive of management fees, and capital expenditures for its investment properties.  Operations are funded utilizing operating income, existing cash on-hand, short-term investments, if any, and income earned therefrom. 

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, all or a portion of the management fee is paid from operating income.

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.

The Fund had no off-balance sheet arrangements at JuneSeptember 30, 2011 and December 31, 2010 and does not anticipate the use of such arrangements in the future.

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 at JuneSeptember 30, 2011 and December 31, 2010 other than those discussed in “Estimated Capital Expenditures” above.

Not required.

None.

Not required.

None.

None.

None.