j21412110k.htm

RIDGEWOOD ENERGY T FUND, LLC

2011 ANNUAL REPORT ON FORM 10-K

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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	12
	ITEM 6	SELECTED FINANCIAL DATA	12
	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	19
	ITEM 11	EXECUTIVE COMPENSATION	20
	ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	20
	ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	20
	ITEM 14	PRINCIPAL ACCOUNTING FEES AND SERVICES	21
PART IV
	ITEM 15	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	21


		SIGNATURES	23

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FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy T Fund, LLC (the “Fund”) has incorporated by reference into this Annual 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.

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PART I

ITEM 1. BUSINESS

Overview

The Fund is a Delaware limited liability company (“LLC”) formed on April 12, 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 June 15, 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 October 31, 2006. The Fund raised $144.5 million and after payment of $23.5 million in offering fees, commissions and investment fees, the Fund had $121.0 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. With respect to project investment, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions in which the investments are made. This includes review of existing title documents, reserve information, and other technical specifications regarding a project, and review and preparation of participation agreements and other agreements relating to an investment. 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 Form 10-K.

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.

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 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.

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. Management fees for the years ended December 31, 2011 and 2010 were $2.1 million and $2.3 million, respectively. Additionally, the Manager is entitled to receive a 15% interest in cash distributions made by the Fund. Distributions paid to the Manager for the years ended December 31, 2011 and 2010 were $1.3 million and $1.2 million, respectively.

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 invests 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. Although the Fund’s focus is primarily on exploratory oil and natural gas projects, it also investigates and, if appropriate, invests in non-exploratory projects, such as producing projects and projects that have proven undeveloped reserves, some of which may need capital to construct, install or acquire the necessary infrastructure assets, such as rigs, pipelines or other equipment needed to gather, process and transport oil or natural gas. Some of these non-exploratory projects may also contain probable or possible reserves, which could be a factor in the purchase price paid by the Fund to acquire such projects. The Fund rigorously screens and evaluates non-exploratory projects using the same investment screening and selection process used for exploratory stage projects, although, depending on the nature and type of a non-exploratory project, additional or different evaluative tools and processes may be needed by the Fund when evaluating such projects.

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Investment Strategy

The Fund invests its capital with operators through working interest joint ventures with such operators and, in some cases, 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. Ridgewood Energy evaluates each project and its operator on an individual project basis, allowing the Fund to invest in what Ridgewood Energy believes are the projects with the most attractive risk/reward ratios. Critical to the success of this approach is the ability of Ridgewood Energy to diversify the Fund’s portfolio across project types and operators. Attributes sought in projects for investment include: depth of scientific analysis and preparation; strong potential project economics and favorable operating agreement terms; similarity to existing producing properties; and expertise of the operator in the proposed region/geology/technical environment. Attractive characteristics of potential and existing operators include industry contacts and relationships, sophisticated geological and geophysical teams and a strong track record of success. For certain of the Fund’s investments, the Fund may pay the operator a “promote” on the cost of the initial exploratory well, representing a larger share of the drilling costs. For a successful well, all of the Fund’s subsequent costs, including completion costs for the exploratory well, the costs of all development wells, infrastructure costs such as production platforms and pipelines, and day-to-day operating costs for the life of the project, would be paid on a proportionate basis to its working interest ownership.

Investment Process

Although Ridgewood Energy’s model of investing fund capital with operators affords it access to industry-leading technical and engineering resources, Ridgewood Energy performs its own due diligence on, and independently evaluates, all of the projects in which the Fund may invest. Ridgewood Energy conducts an initial screening process to identify new project investment opportunities and is selective as to which projects it pursues. Key criteria that form part of the detailed evaluation include the identity of the operator and other partners, the technical quality of the project, access to existing infrastructure, drilling schedule and rig availability and project economics and terms.

Ridgewood Energy maintains an investment committee consisting of five members, which provides operational, financial, scientific and technical oil and gas expertise to the Fund (the “Investment Committee”). Four members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and one member is based out of the Manager’s Houston, Texas office. Once the technical and economic analyses of a potential project are complete and a project has been deemed to satisfy Ridgewood Energy’s technical criteria, provide an attractive economic risk/reward ratio, and fit within Ridgewood Energy’s diversification strategy, final investment approval is made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee seeks to balance the economics of the projects, the potential sizes of the projects, project location, the diversity of the operators, and the likely timing of new projects. The Investment Committee also considers the geological, financial and operating risks of the proposed project and compares these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further focuses on the initial well cost relative to the overall revenue potential of the project.

Participation and Joint Operating Agreements

Once Ridgewood Energy decides that a project is an appropriate investment for the Fund, the Fund will seek to enter into participation and joint operating agreements with the other working interest owners in a lease. Ridgewood Energy negotiates these agreements with the goal of achieving the best possible economics and governance rights for the Fund in connection with acquiring the interest. Under the joint operating agreement, proposals and decisions are 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 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.

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Project Information

Existing projects, and future projects, if any, are located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama, 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 Bureau of Ocean Energy Management (“BOEM”). Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 87.5% of the total revenue, depending on the nature of the project. The net revenue interest is further reduced by any other royalty burdens that apply to a lease block, such as those imposed by override interest owners. However, as described below, the BOEM has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects. Other than BOEM royalties, the Fund does not have material royalty burdens.

Deep Gas Royalty Relief

On January 26, 2004, the BOEM promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the "Royalty Relief Rule"). Under the Royalty Relief Rule, lessees are eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief is available for wells drilled and perforated deeper than 18,000 feet subsea. The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the Continental Shelf nor does it apply if the price of natural gas exceeds $10.81 (estimated) Million British Thermal Units (“mmbtu”), adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters.

Deepwater Royalty Relief

In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater 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 Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. For purposes of royalty relief, under the Deepwater Relief Act, the BOEM defines deepwater as depths in excess of 656 feet, or 200 meters. In order for a lease to be eligible for royalty relief under the Deepwater Relief Act, it must be located in the Gulf of Mexico and west of 87 degrees and 30 minutes West longitude (essentially the Florida-Alabama boundary).

Currently, for leases entered into after November 2000, the BOEM assigns a lease a specific volume of royalty suspension based on how the suspension amount would affect the economics of the lease’s development. Any such royalty suspension applicable to a particular lease is generally set forth in the lease auction materials prepared by the BOEM. The amount of the suspension, if any, is not determined by water depth levels (as it had been in the past) but rather based upon the BOEM’s view of the characteristics and economics of the project. For example, a project deemed relatively secure and safe, such as those near existing transportation infrastructure, may receive no royalty relief while a similar project far away from any such infrastructure or in an area deemed more risky may receive significant royalty relief. As a result, unlike the royalty relief associated with deep drilling in shallow waters, there is no formulaic or predictable means of determining in advance whether, and to what extent, royalty relief would be available for a potential deepwater project.

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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, 2011. 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 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		0.51

Acreage Data

The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 2011. 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
	31,520		2,108		6,124		122

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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.

			Total Spent		Total
	Working		through		Fund
Lease Block	Interest		December 31, 2011		Budget		Status
			(in thousands)
Non-producing Properties
Beta Project		2.0%	$	1,524	$	3,967	Drilling commenced in March 2010 and was suspended due to the moratorium. Permit to resume drilling was obtained in August 2011. Drilling resumed in December 2011. Results expected in first quarter 2012.

Producing Properties
Carrera Project		3.0%	$	4,735	$	4,750	Production commenced June 2011. Separator upgrade planned for 2012 at an estimated cost of $15 thousand.

Cobalt Project		4.0%	$	1,893	$	1,945	Production commenced in 2009. Ongoing recompletion efforts planned at an estimated cost of $52 thousand.

Eugene Island 346/347 well #1		10.0%	$	7,002	$	7,052	Production commenced in 2008. Recompletion efforts to access behind the pipe reserves are planned for 2012 at an estimated cost of $50 thousand.

Liberty Project		3.0%	$	4,518	$	4,518	Production commenced July 2010.

West Cameron 75		20.0%	$	25,274	$	28,274	Production commenced in 2007. Well was shut-in from March 2011 until December 2011, as a result of damages sustained by the pipeline during a dredging operation performed by the US Army Corps of Engineers. The Fund agreed to participate in the costs to repair and deepen the third-party pipeline. The repair efforts were completed in December 2011 at a cost to the Fund of $0.8 million and the well resumed production at that time. An additional recompletion is planned for 2014 at an estimated cost of $3.0 million.

West Cameron 76 #12		11.24%	$	5,318	$	5,318	Production commenced in 2008.

Fully Depleted
Eugene Island 346/347 well #2		10.0%	$	1,392		N/A	Fully depleted at December 31, 2010.

Dry Holes
Targa Project		2.0%	$	2,280		N/A	Drilling commenced February 2010; dry hole determination May 2010.

Sold Project
Aspen Project		2.69%	$	6,791		N/A	Property sold December 2010.

Marketing/Customers

The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to sell the Fund’s oil and natural gas. Currently, the Fund has five 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 projects are near existing transportation infrastructure and pipelines. The Manager believes that it is likely that oil and natural gas from the Fund’s future projects will have access to pipeline transportation and can be marketed through Energy Upgrade, Inc.

Natural gas is sold in the spot market at prevailing prices, which fluctuate with demand as a result of related industry variables. Oil is generally sold one month at a time at prevailing market prices. Historically, the markets for, and prices of, oil and natural gas have been extremely 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. Low commodity prices could have an adverse effect on the Fund’s future profitability. In the past, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production.

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Seasonality

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

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 damage or shut-ins, or production stoppages, due to hurricane activity in 2011.

Operator

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 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 producing properties are operated by BHP Billiton Petroleum, Ltd, Deep Gulf Energy LP, El Paso E&P Company L.P., LLOG Exploration Offshore, Inc., McMoRan Oil & Gas LLC and Newfield Exploration Company.

Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders not only bear the risk that the Manager will be able to select suitable projects, but also that, once selected, 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. The Manager has 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 the projects. In addition, the Manager's past practice has been 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 the 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 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's affiliates, yearly insurance limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.

Salvage Fund

As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for the Fund’s 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. The Fund has deposited $1.0 million from capital contributions into a salvage fund, which, along with interest earned on this account, the Fund currently estimates to be sufficient to meet the Fund’s potential requirements. If, at any time, the Manager determines the salvage fund will not be sufficient to cover the Fund’s proportionate share of expense, the Fund may transfer amounts from capital contributions or operating income to fund the deficit. Payments to the salvage fund will reduce the amount of cash distributions that may be made to investors by the Fund. Any portion of a salvage fund that remains after the Fund pays its share of the actual salvage cost will be distributed to the shareholders. There are no legal restrictions on the withdrawal or use of the salvage fund.

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Competition

Strong 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. Although the Fund itself does not compete for lease acquisitions from the BOEM, it does compete with other companies for the acquisition of percentage ownership interests in oil and natural gas working interests in the secondary market.

In many instances, the Fund competes for working interests in projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and may have more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position to outbid the Fund. Nevertheless, the Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, and (ii) Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint.

Employees

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

Offices

The principal executive 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. 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 and production 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. The Fund may own interests in properties located in state waters of the Gulf of Mexico, for which such states regulate drilling and operating activities by requiring, among other things, drilling permits, bonds and reports concerning operations. The laws of such states also govern a number of environmental and conservation matters, including the handling and disposing of waste materials, unitization and pooling of natural gas and oil properties, and the levels of production from natural gas and oil wells.

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, an agency of the United States Department of Interior. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement pursuant to regulations promulgated under the OCSLA. Lessees must obtain approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. The Fund is not involved in the process of obtaining any such approvals or permits. Offshore operations are subject to numerous regulatory requirements, including stringent engineering and construction specifications related to offshore production facilities and pipelines and safety-related regulations concerning the design and operating procedures of these facilities and pipelines. Regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

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Offshore operations are subject to regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Under certain circumstances, operations on federal leases may be suspended or terminated. Any such suspension or termination could adversely affect the Fund’s operations and interests.

The BOEM conducts auctions for lease blocks of submerged areas offshore. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the duration of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a limited degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.

Sales and Transportation of Oil and Natural Gas

The Fund sells its proportionate share of oil and natural gas to the market through a marketer or a joint operating agreement 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 ("FERC"). The rates, terms and conditions are regulated by FERC pursuant to a variety of statutes, including the OCSLA, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. 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 and the protection of aquatic species and habitats. However, although it shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, 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:

The 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 (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. The OPA establishes a new liability regime for oil pollution incidents in the aquatic environment. Essentially, the OPA provides that a responsible party for a vessel or facility from which oil is discharged or that poses a substantial threat of a discharge could be liable for certain specified damages resulting from a discharge of oil, including clean-up and remediation, loss of subsistence use of natural resources, real or personal property damages, as well as certain public and private damages. A responsible party includes a lessee of an offshore facility.

The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages. In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier, the Fund has not been required to make any such showing to the BOEM, as the operators are responsible for such compliance. However, notwithstanding the operators’ responsibility for compliance, in the event of an oil spill, the Fund, along with the operators and other working interest owners, could be liable under the OPA for the resulting environmental damage.

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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.

Federal 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, 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 the 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 the costs of compliance with applicable environmental laws, including federal, state and local laws, will have a material adverse impact on its financial condition and/or operations.

ITEM 1A. RISK FACTORS

Not required.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

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 for the years ended December 31, 2011 and 2010. 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. During the years ended December 31, 2011 and 2010, the Fund had no drilling activity for developmental wells. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about wells in-progress at December 31, 2011.

	2011				2010
	Gross		Net		Gross		Net
Exploratory wells:
Nonproductive		-		-		1		0.02
In-progress		1		0.02		1		0.02
Exploratory well total		1		0.02		2		0.04

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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 reserves 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 twenty 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 at December 31, 2011 and 2010 were prepared by Ryder Scott Company, L.P., (“Ryder Scott”) an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from Ryder Scott, which is filed as Exhibit 99 to this Annual Report, and is incorporated herein by reference.

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. 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 15. “Exhibits, Financial Statement Schedules” of this Annual Report, is incorporated herein by reference.

Proved Undeveloped Reserves. At December 31, 2011 and 2010, the Fund had approximately 4 thousand barrels and 4.6 million mcf of proved undeveloped oil and natural gas reserves, respectively. These proved undeveloped reserves are related to the West Cameron 75 well. The Fund currently expects to develop these proved undeveloped reserves during 2014. To date, the Fund has not made any investments toward converting these proved undeveloped reserves to proved developed reserves.

Production and Prices

The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, 2011 and 2010 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 – Oil and Gas Revenue” and “Results of Operations – Operating Expenses” is incorporated herein by reference.

Delivery Commitments

As of December 31, 2011, the Fund had no obligations or delivery commitments under any existing contracts.

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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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 the date of this filing, there were 1,668 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. There is, however, 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, 2011 and 2010, the Fund paid distributions totaling $11.2 million and $7.7 million, respectively.

ITEM 6. SELECTED FINANCIAL DATA

Not required.

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

Overview of the Fund’s Business

The Fund was organized 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 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. However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.

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. 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.

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 effect on the Fund’s future profitability.

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 conformity 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” contained in this Annual Report for a discussion of the Fund’s significant accounting policies.

Accounting for Exploration, Development and Acquisition Costs

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

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The costs of exploratory and developmental wells are capitalized pending determination of whether proved reserves have been found. Drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are expensed as dry-hole costs. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel; active negotiations for sales contracts with customers; negotiations with governments, operators and contractors; and firm plans for additional drilling and other factors.

Unproved Property

Unproved property is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination. These costs are excluded from the depletion base until the outcome of the project has been determined, or generally until it is known whether proved reserves will or will not be assigned to the property. The Fund assesses all items in its unproved property balance on an ongoing basis for possible impairment or reduction in value.

Proved Reserves

Annually, the Fund engages an independent petroleum engineer, Ryder Scott, 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. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization.

Asset Retirement Obligations

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, a liability is recognized for the present value of asset retirement obligations once reasonably estimable. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of its proved properties. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.

Impairment of Long-Lived Assets

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 end of each period. 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. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. 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. 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.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, 2011 and 2010, 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.

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	Year ended December 31,
	2011			2010
	(in thousands)
Revenue
Oil and gas revenue	$	12,079		$	12,941
Expenses
Depletion and amortization		7,663			13,833
Dry-hole costs		(149	)		2,058
Impairment of oil and gas properties		253			949
Management fees to affiliate		2,066			2,282
Operating expenses		1,021			847
Workover expenses		823			(34	)
General and administrative expenses		297			412
Total expenses		11,974			20,347
Loss on sale of oil and gas properties		-			(4,128	)
Income (loss) from operations		105			(11,534	)
Other (loss) income		(88	)		92
Net income (loss)	$	17		$	(11,442	)

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, 2011 and 2010.

	Year ended December 31,
	2011		2010
Number of wells producing		6		6
Total number of production days		1,841		1,812
Average mcfe per production day		770		1,376
Oil sales (in thousands of barrels)		71		44
Average oil price per barrel	$	107	$	78
Gas sales (in thousands of mcfs)		850		2,013
Average gas price per mcf	$	3.75	$	4.01

The increase in production days was primarily attributable to the onset of production of the Liberty Project in July 2010 and the Carrera Project in June 2011, partially offset by the West Cameron 75 well, which was shut-in from March 2011 through December 2011, and Eugene Island 346/347 well #2, which was determined to be fully depleted at December 31, 2010.

The decreases in average production rate and gas sales volume were principally attributable to the shut-in of the West Cameron 75 well, partially offset by the onset of production of the Liberty and Carrera projects. The increase in oil sales volume was primarily the result of the onset of production of the Liberty and Carrera projects.

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

Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, 2011 was $12.1 million, a $0.9 million decrease from the year ended December 31, 2010. The decrease is attributable to decreased sales volume totaling $3.1 million, partially offset by the impact of the change in average prices totaling $2.1 million. See “Overview” above for additional information.

Depletion and Amortization. Depletion and amortization for the year ended December 31, 2011 was $7.7 million, a decrease of $6.2 million from the year ended December 31, 2010. The decrease resulted from a decrease in production volumes totaling $6.0 million coupled with a decrease in average depletion rates totaling $0.2 million. The decrease in average depletion rates was principally the result of revisions to reserve estimates coupled with the impact of the shut-in of the West Cameron 75 well, partially offset by higher cost reserve additions. See “Overview” above for additional information.

Dry-hole Costs. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. 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.

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	Year ended December 31,
Lease Block	2011			2010
	(in thousands)
Targa Project	$	(1	)	$	2,281
Other wells		(148	)		(223	)
	$	(149	)	$	2,058

Impairment of Oil and Gas Properties. During the years ended December 31, 2011 and 2010, the Fund recorded impairments of $0.3 million and $0.9 million, respectively, relating to Eugene Island 346/347 well #1, which were attributable to revisions to reserve estimates.

Management Fees to Affiliate. Management fees for the years ended December 31, 2011 and 2010 were $2.1 million and $2.3 million, respectively. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.

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,
		2011		2010
	(in thousands)
Lease operating expense		$	1,008	$	810
Accretion expense			11		25
Other expense			2		12
		$	1,021	$	847

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $0.71 per mcfe during the year ended December 31, 2011 compared to $0.32 per mcfe during the year ended December 31, 2010. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.

Workover Expenses. Workover expenses represent costs to restore or stimulate production of existing reserves of a proved property. Workover expenses of $0.8 million during the year ended December 31, 2011 related primarily to costs to repair and deepen the third-party pipeline for the West Cameron 75 well. Workover credits of $34 thousand during the year ended December 31, 2010 related to a prior year sidetrack operation for the West Cameron 75 well.

General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the following table.

	Year ended December 31,
	2011		2010
	(in thousands)
Insurance expense	$	173	$	225
Accounting fees		117		166
Trust fees and other		7		21
	$	297	$	412

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. Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund. Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

Loss on Sale of Oil and Gas Properties. During the year ended December 31, 2010, the Fund recorded a loss on sale of oil and gas properties of $4.1 million, related to the Aspen Project. There were no such amounts recorded during the year ended December 31, 2011.

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Other (Loss) Income. Other (loss) income for the years ended December 31, 2011 and 2010 is detailed in the following table.

	Year ended December 31,
	2011			2010
	(in thousands)
Interest income	$	36		$	45
Realized (losses) gains on derivative instruments		(126	)		47
Unrealized gains on derivative instruments		2			-
	$	(88	)	$	92

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the year ended December 31, 2011 were $8.6 million, primarily related to revenue received of $12.1 million coupled with derivative instrument settlements of $0.2 million, partially offset by management fees of $2.1 million, operating and workover expenses paid of $1.0 million, the purchase of derivative instruments of $0.4 million and general and administrative expenses paid of $0.3 million.

Cash flows provided by operating activities for the year ended December 31, 2010 were $8.6 million, primarily related to revenue received of $12.0 million, partially offset by management fees of $2.3 million, operating expenses of $0.8 million and general and administrative expenses of $0.4 million.

Investing Cash Flows

Cash flows provided by investing activities for the year ended December 31, 2011 were $4.5 million, primarily related to proceeds from the maturity of U.S Treasury securities of $5.0 million coupled with proceeds received from the sale of the Aspen Project of $2.7 million, partially offset by investments in U.S. Treasury securities of $3.0 million and capital expenditures for oil and gas properties of $0.1 million.

Cash flows used in investing activities for the year ended December 31, 2010 were $13.8 million, primarily related to investments in U.S. Treasury securities of $15.0 million and capital expenditures for oil and gas properties of $8.8 million, inclusive of advances, partially offset by proceeds received from the maturity of U.S. Treasury securities totaling $10.0 million.

Financing Cash Flows

Cash flows used in financing activities for the year ended December 31, 2011 were $11.2 million related to manager and shareholder distributions.

Cash flows used in financing activities for the year ended December 31, 2010 were $7.7 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 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 December 31, 2011, the Fund had committed to spend an additional $5.6 million related to its investment properties, of which $2.0 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.

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Liquidity Needs

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.

Off-Balance Sheet Arrangements

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

Contractual Obligations

The Fund enters into participation and joint operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate such contracts. No contractual obligations exist at December 31, 2011 and 2010 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits, 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, 2011. 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.

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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, 2011. 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. Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2011, 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.

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, 2011 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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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 Ridgewood Energy and the Fund and their ages at December 31, 2011 are as follows:

Name, Age and Position with Registrant	Officer of Ridgewood Energy Corporation Since

Robert E. Swanson, 64 Chief Executive Officer	1982

Kenneth W. Lang, 57 President and Chief Operating Officer	2009

Kathleen P. McSherry, 46 Executive Vice President and Chief Financial Officer	2001

Robert L. Gold, 53 Executive Vice President	1987

Daniel V. Gulino, 51 Senior Vice President and General Counsel	2003

The officers in the above table have also 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 Ridgewood Energy and 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 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 and is a member of the Investment Committee. Ms. McSherry holds a Bachelor of Science degree in Accounting.

Robert L. Gold has served as the Executive Vice President of Ridgewood Energy since 1987 and is a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.

Daniel V. Gulino is Senior Vice President of Legal Affairs for Ridgewood Energy and has served as counsel for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management 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.

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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 our 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, 2011, all filing requirements applicable to its officers, directors and 10% beneficial owners were met.

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 971.6054 shares outstanding at February 16, 2012. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.

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

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 years ended December 31, 2011 and 2010 were $2.1 million and $2.3 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund. Distributions paid to the Manager for the years ended December 31, 2011 and 2010 were $1.3 million and $1.2 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.

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.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, 2011 and 2010.

	Year ended December 31,
	2011		2010
	(in thousands)
Audit fees (1)	$	80	$	130

(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, FINANCIAL STATEMENT SCHEDULES

(a) (1) Financial Statements

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

(a) (2) Financial Statement Schedules

None.

- 21 -

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(a) (3)

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING

3.1	Articles of Formation of Ridgewood Energy T Fund, LLC dated April 12, 2006	Incorporated by reference to the Fund's Form 10 filed on April 25, 2007

3.2	Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy T Fund, LLC dated June 15, 2006	Incorporated by reference to the Fund's Form 10 filed on April 25, 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	Report of Ryder Scott Company, L.P.	Filed herewith

101.INS	XBRL Instance Document	*

101.SCH	XBRL Taxonomy Extension Schema	*

101.CAL	XBRL Taxonomy Extension Calculation Linkbase	*

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*

101.LAB	XBRL Taxonomy Extension Label Linkbase	*

101.PRE	XBRL Taxonomy Extension Presentation Linkbase	*

* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Act of 1934 and otherwise are not subject to liability.

- 22 -

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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 T FUND, LLC


Date: February 16, 2012	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
		February 16, 2012
/s/ ROBERT E. SWANSON	Chief Executive Officer (Principal Executive Officer)	February 16, 2012
Robert E. Swanson	Chief Executive Officer (Principal Executive Officer)


/s/ KATHLEEN P. MCSHERRY	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)	February 16, 2012
Kathleen P. McSherry


RIDGEWOOD ENERGY CORPORATION

BY: /s/ ROBERT E. SWANSON	Chief Executive Officer of the Manager	February 16, 2012
Robert E. Swanson

- 23 -

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INDEX TO FINANCIAL STATMENTS	PAGE

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of December 31, 2011 and 2010	F-3
Statements of Operations for the years ended December 31, 2011 and 2010	F-4
Statements of Changes in Members' Capital for the years ended December 31, 2011 and 2010	F-5
Statements of Cash Flows for the years ended December 31, 2011 and 2010	F-6
Notes to Financial Statements	F-7
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited	F-13

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Manager of Ridgewood Energy T Fund, LLC

We have audited the accompanying balance sheets of Ridgewood Energy T Fund, LLC (the “Fund”) as of December 31, 2011 and 2010, and the related statements of operations, changes in members' capital, and cash flows for the years ended December 31, 2011 and 2010. 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 Company'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 T Fund, LLC as of December 31, 2011 and 2010, and the results of its operations and its cash flows for the years ended December 31, 2011 and 2010, in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

February 16, 2012

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RIDGEWOOD ENERGY T FUND, LLC

BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	4,794		$	2,930
Short-term investments in marketable securities		3,000			4,997
Production receivable		1,426			1,427
Receivable from sale of oil and gas properties		-			2,690
Other current assets		140			106
Total current assets		9,360			12,150
Salvage fund		1,179			1,147
Oil and gas properties:
Advances to operators for working interests and expenditures		-			271
Unproved properties		1,524			1,260
Proved properties		51,120			50,056
Less: accumulated depletion and amortization		(34,366	)		(26,450	)
Total oil and gas properties, net		18,278			25,137
Total assets	$	28,817		$	38,434

LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators	$	1,546		$	195
Accrued expenses		35			52
Total current liabilities		1,581			247
Asset retirement obligations		1,052			771
Total liabilities		2,633			1,018

Commitments and contingencies (Note 6)
Members' capital:
Manager:
Distributions		(4,777	)		(3,466	)
Retained earnings		2,918			1,830
Manager's total		(1,859	)		(1,636	)

Shareholders:
Capital contributions (1,000 shares authorized;
971.6054 issued and outstanding)		144,529			144,529
Syndication costs		(16,990	)		(16,990	)
Distributions		(29,578	)		(19,640	)
Accumulated deficit		(69,918	)		(68,847	)
Shareholders' total		28,043			39,052
Total members' capital		26,184			37,416
Total liabilities and members' capital	$	28,817		$	38,434

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

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RIDGEWOOD ENERGY T FUND, LLC

STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	Year ended December 31,
	2011			2010
Revenue
Oil and gas revenue	$	12,079		$	12,941
Expenses
Depletion and amortization		7,663			13,833
Dry-hole costs		(149	)		2,058
Impairment of oil and gas properties		253			949
Management fees to affiliate (Note 4)		2,066			2,282
Operating expenses		1,021			847
Workover expenses		823			(34	)
General and administrative expenses		297			412
Total expenses		11,974			20,347
Loss on sale of oil and gas properties		-			(4,128	)
Income (loss) from operations		105			(11,534	)
Other (loss) income		(88	)		92
Net income (loss)	$	17		$	(11,442	)

Manager Interest
Net income	$	1,088		$	1,221

Shareholder Interest
Net loss	$	(1,071	)	$	(12,663	)
Net loss per share	$	(1,102	)	$	(13,033	)

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

F-4

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RIDGEWOOD ENERGY T FUND, LLC

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL

(in thousands, except share data)


	# of Shares		Manager			Shareholders			Total
Balances, December 31, 2009		971.6054	$	(1,701	)	$	58,265		$	56,564
Distributions		-		(1,156	)		(6,550	)		(7,706	)
Net income (loss)		-		1,221			(12,663	)		(11,442	)
Balances, December 31, 2010		971.6054		(1,636	)		39,052			37,416
Distributions		-		(1,311	)		(9,938	)		(11,249	)
Net income (loss)		-		1,088			(1,071	)		17
Balances, December 31, 2011		971.6054	$	(1,859	)	$	28,043		$	26,184

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

F-5

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RIDGEWOOD ENERGY T FUND, LLC

STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2011			2010
Cash flows from operating activities
Net income (loss)	$	17		$	(11,442	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion and amortization		7,663			13,833
Dry-hole costs		(149	)		2,058
Impairment of oil and gas properties		253			949
Accretion expense		11			25
Loss on sale of oil and gas properties		-			4,128
Interest earned on marketable securities		(3	)		(10	)
Derivative instrument loss (income)		124			(47	)
Derivative instrument settlements		220			79
Changes in assets and liabilities:
Decrease (increase) in production receivable		1			(939	)
Increase in other current assets		(399	)		(43	)
Increase in due to operators		878			29
Decrease in accrued expenses		(17	)		(5	)
Net cash provided by operating activities		8,599			8,615

Cash flows from investing activities
Payments to operators for working interests and expenditures		-			(271	)
Capital expenditures for oil and gas properties		(144	)		(8,483	)
Proceeds from sale of oil and gas properties		2,690			-
Proceeds from maturity of investments		5,000			10,011
Investments in marketable securities		(3,000	)		(14,998	)
Interest reinvested in salvage fund		(32	)		(32	)
Net cash provided by (used in) investing activities		4,514			(13,773	)

Cash flows from financing activities
Distributions		(11,249	)		(7,706	)
Net cash used in financing activities		(11,249	)		(7,706	)

Net increase (decrease) in cash and cash equivalents		1,864			(12,864	)
Cash and cash equivalents, beginning of year		2,930			15,794
Cash and cash equivalents, end of year	$	4,794		$	2,930

Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$	271		$	-

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

F-6

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RIDGEWOOD ENERGY T FUND, LLC

NOTES TO FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Organization

The Ridgewood Energy T Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on April 12, 2006 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of June 15, 2006 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund. 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 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 4 and 6.

Use of Estimates

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

Cash and Cash Equivalents

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 December 31, 2011, the Fund’s bank balances exceeded federally insured limits by $3.1 million, all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

Investments in Marketable Securities

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. At December 31, 2011, the Fund had short-term, held-to-maturity investments of $3.0 million, which mature in April 2012. 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.

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

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money 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. At December 31, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $1.1 million, which mature in December 2012. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

F-7

Table of Contents

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.

Exploration, development and acquisition 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. Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory drilling costs are expensed as dry-hole costs. Annual lease rentals and exploration expenses 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.

At December 31, 2011 and 2010, amounts recorded in due to operators totaling $0.5 million and $39 thousand, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures

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.

Asset Retirement Obligations

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. The following table presents changes in asset retirement obligations for the years ended December 31, 2011 and 2010.

	2011		2010
	(in thousands)
Balance, beginning of year	$	771	$	729
Accretion expense		11		25
Revisions in estimated cash flows		270		17
Balance, end of year	$	1,052	$	771

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

Syndication Costs

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

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. 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.

F-8

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Derivative Instruments

The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production. Derivative instruments are carried on the balance sheet at fair value and recorded as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met. At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as other income on the statement of operations. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows. See Note 2. “Derivative Instruments,” for more information.

Impairment of Long-Lived Assets

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.

During the years ended December 31, 2011 and 2010, the Fund recorded impairments of $0.3 million and $0.9 million, respectively, relating to Eugene Island 346/347 well #1, which were attributable to revisions to reserve estimates. Prior to such write-downs, the well had a carrying value of $1.4 million and $2.9 million at December 31, 2011 and 2010, respectively. The fair value of the impaired well at December 31 2011 and 2010 was $1.2 million and $2.0 million, respectively, which was determined based on level 3 inputs, which include projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.

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 and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.

Income and Expense Allocation

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.

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.

In January 2011, proceeds from the sale of the Aspen Project were distributed to the Manager and shareholders totaling $27 thousand and $2.7 million, respectively.

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Table of Contents

Recent Accounting Pronouncements

The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

2. Derivative Instruments

The Fund periodically enters into derivative contracts relating to its oil or gas production. During 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 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 December 31, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil that are not designated for hedge accounting as detailed in the following table.

Production Period	Type of Contract	Volume in barrels of oil		ICE Contract Price per barrel		Estimated Fair Value Asset
						(in thousands)
January 1, 2012 - April 30, 2012	Put Options		4,412	$	105.00	$	22
January 1, 2012 - April 30, 2012	Put Options		2,094	$	112.00	$	18
January 1, 2012 - April 30, 2012	Put Options		2,094	$	100.00	$	6

For the years ended December 31, 2011 and 2010, the Fund’s derivative instrument income consisted of the following:

	Year ended December 31,
	2011			2010
	(in thousands)
Realized (losses) gains on derivative instruments	$	(126	)	$	47
Unrealized gains on derivative instruments		2			-
	$	(124	)	$	47

3. Oil and Gas Properties

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 December 31, 2011, the Fund had no projects with capitalized exploratory well costs in excess of one year. The following table reflects the net changes in unproved properties for the years ended December 31, 2011 and 2010.

F-10

Table of Contents

	2011		2010
	(in thousands)
Balance, beginning of year	$	1,260	$	5,122
Additions to capitalized exploratory well costs
pending the determination of proved reserves		264		2,956
Reclassifications to proved properties based on
the determination of proved reserves		-		(6,818	)
Capitalized exploratory well costs charged to
expense		-		-
Balance, end of year	$	1,524	$	1,260

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 $2.7 million in cash, which resulted in a loss of $4.1 million. The proceeds from the sale of the Aspen Project, which were classified as a receivable from sale of oil and gas properties on the balance sheet at December 31, 2010, 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.

	Year ended December 31,
Lease Block	2011			2010
	(in thousands)
Targa Project	$	(1	)	$	2,281
Other wells		(148	)		(223	)
	$	(149	)	$	2,058

4. Related Parties

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.

5. Fair Value Measurements

At December 31, 2011 and 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 December 31, 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.

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6. Commitments and Contingencies

Capital Commitments

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 December 31, 2011, the Fund had committed to spend an additional $5.6 million related to its investment properties, of which $2.0 million is expected to be spent during the next twelve months.

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. At December 31, 2011 and 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.

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 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.

7. Subsequent Events

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.

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Ridgewood Energy T Fund, LLC

Supplementary Financial Information

Information about Oil and Gas Producing Activities – Unaudited

In accordance with the Financial Accounting Standards Board 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 currently 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,
	2011			2010
	(in thousands)
Advances to operators for working interests and expenditures	$	-		$	271
Unproved properties		1,524			1,260
Proved properties		51,120			50,056
Total oil and gas properties		52,644			51,587
Accumulated depletion and amortization		(34,366	)		(26,450	)
Oil and gas properties, net	$	18,278		$	25,137

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

	Year ended December 31,
	2011		2010
	(in thousands)
Exploration costs	$	40	$	3,615
Development costs		870		4,436
	$	910	$	8,051

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Table III - Reserve Quantity Information

Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer, Ryder Scott Company, L.P. at December 31, 2011 and 2010. 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, 2011						December 31, 2010
	United States
	Oil (BBLS)			Gas (MCF)			Oil (BBLS)			Gas (MCF)

Proved developed and undeveloped reserves:
Beginning of year		156,338			8,425,520			126,019			9,951,074
Revisions of previous estimates (a)		56,132			264,305			74,374			706,142
Production		(71,502	)		(1,004,444	)		(44,055	)		(2,231,696	)
End of year		140,968			7,685,381			156,338			8,425,520

Proved developed reserves:
Beginning of year		152,574			3,815,020			53,265			4,998,891
End of year		137,204			3,074,881			152,574			3,815,020

Proved undeveloped reserves:
Beginning of year		3,764			4,610,500			72,754			4,952,183
End of year		3,764			4,610,500			3,764			4,610,500

(a) Revisions of previous estimates are 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. At December 31, 2011 and 2010, 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,
	2011			2010
	(in thousands)
Future cash inflows	$	54,431		$	50,949
Future production costs		(4,437	)		(4,193	)
Future development costs		(4,209	)		(4,440	)
Future net cash flows		45,785			42,316
10% annual discount for estimated timing of cash flows		(7,980	)		(7,577	)
Standardized measure of discounted future net cash flows	$	37,805		$	34,739

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,
	2011			2010
	(in thousands)
Net change in sales and transfer prices and in production costs related to future production	$	8,151		$	9,519
Sales and transfers of oil and gas produced during the period		(11,071	)		(12,131	)
Changes in estimated future development costs		231			236
Net change due to revisions in quantities estimates		4,627			4,792
Accretion of discount		3,474			2,731
Other		(2,346	)		2,281
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	3,066		$	7,428

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

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