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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2013
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File No. 000-52578

Ridgewood Energy T Fund, LLC
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
 
27-0141421
(I.R.S. Employer
Identification No.)

14 Philips Parkway, Montvale, NJ  07645
(Address of principal executive offices) (Zip code)
(800) 942-5550
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Shares of LLC Membership Interest

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

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

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

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

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

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

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

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

There is no market for the shares of LLC Membership Interest in the Fund.  As of February 25, 2014, there are 971.6054 shares of LLC Membership Interest outstanding.
        


 
RIDGEWOOD ENERGY T FUND, LLC
2013 ANNUAL REPORT ON FORM 10-K
 
     
PAGE
       
PART I
     
  2
  10
  10
  10
  11
  11
PART II
     
  12
  12
  12
  18
  18
  18
  18
  18
PART III
     
  19
  20
  20
  20
  21
PART IV
     
  21
       
    23
 
 
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 and production 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 projects, investments, insurance, capital expenditures and liquidity.  Forward-looking statements made in this document speak only as of the date on which they are made.  The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
 
 
 
 
 
 
 
PART I


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.   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. Historically when the Fund had sought project investment, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects.  Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com.  No information on such website shall be deemed to be included or incorporated by reference into this Form 10-K.

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 each of the years ended December 31, 2013 and 2012 were $2.0 million.  Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2013 and 2012 were $1.0 million and $1.3 million, respectively.

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

Business Strategy

The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects.  Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and Fund operations.  The Fund has invested in the drilling and development of both shallow and deepwater oil and natural gas projects in the U.S. offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico, in partnership with exploration and production companies.  At December 31, 2013, the Fund’s participation in investments in oil and natural gas properties had been completely identified and contracted and the balance of the Fund’s capital has been fully allocated to complete such projects and since that time, the Fund has not investigated or invested in, and does not expect in the future to investigate or invest in, any additional projects, other than those in which the Fund currently has a working interest.
 
 
Investment Strategy
The Fund has invested 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. Attributes sought in projects for investment have included: 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, geological and geophysical teams and a 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 third-party technical and engineering resources, Ridgewood Energy has performed its own due diligence on, and independently evaluated, all of the projects in which the Fund has invested.  When seeking new project investment opportunities, Ridgewood Energy has conducted an initial screening process to identify these opportunities and has been selective as to which projects it has chosen to pursue.  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”).  Two members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and three members are based out of the Manager’s Houston, Texas office.  Once the technical and economic analyses of a potential project have been completed and a project has been deemed to satisfy Ridgewood Energy’s technical criteria, 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.  Currently, the Investment Committee activities surrounding this fund are principally related to the development and operation of properties for which it already has a working interest.

Participation and Joint Operating Agreements
Once Ridgewood Energy decides that a project is an appropriate investment for the Fund, the Fund enters 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.

Project Information

Existing projects are located in the waters of the Gulf of Mexico, offshore Louisiana, on the Outer Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“OCSLA”), which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS.  See further discussion under the heading “Regulation” in this Item 1. “Business” of this Annual Report.
 
 
Leases in the OCS are generally issued for a primary lease term of 5, 8 or 10 years, depending on the water depth of the lease block. During a primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.

The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee, or third-party operator for a project, may conduct additional geological studies and may determine to drill additional exploratory or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee’s working interest ownership percentage.

Royalty Payments
Generally, working interests in an offshore oil and natural gas lease under the OCSLA pay a 12.5%, 16.67% or 18.75% royalty to the 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.  In certain circumstances, 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 other than as provided by the terms of the Fund’s credit agreement, which requires the Fund to pay royalties from the Beta Project to the lender. See Note 5 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

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 Outer Continental Shelf nor does it apply if the price of natural gas exceeds $11.16 (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.

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, 2013.  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, 2013.  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  
 
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
     
Project
   
Interest
   
December 31, 2013
   
Budget
   
Status
(in thousands)
Non-producing Properties                        
Beta Project
      2.0 %   $ 4,352     $ 18,411    
Well deemed to be a discovery in February 2012.  Completion efforts are ongoing and production is expected to commence in 2016.
                               
Producing Properties                              
Carrera Project
      3.0 %   $ 4,865     $ 4,865    
Production commenced in 2011.    During second quarter 2013, the well's umbilical was flooded and electrical communication was lost.  Costs to install a new umbilical and compressor totaled $0.4 million.  Well is currently shut-in and was shut-in periodically throughout 2013 due to repairs and maintenance, pipeline work, and storm activity.  The well is expected to resume production in March 2014 after ongoing workover efforts are completed at an estimated expense of $0.4 million.
                               
Cobalt Project
      4.0 %   $ 1,894     $ 1,926    
Production commenced in 2009.   Production rate has decreased, however, zone continues to be economic.  A recompletion is currently being evaluated for 2015 and an additional recompletion is expected in 2017 at an estimated total cost of $32 thousand.
                               
Eugene Island 346/347 well #1
      10.0 %   $ 7,002     $ 7,052    
Production commenced in 2008.   Well is currently producing at nominal rates; awaiting recompletion, which is expected in 2014 at an estimated cost of $50 thousand.
                               
Liberty Project
      3.0 %   $ 4,512     $ 4,542    
Production commenced in 2010. Well was shut-in for several weeks periodically throughout 2013 due to repairs and maintenance and storm activity.  Recompletion is planned for 2015 at an estimated cost of  $30 thousand.
                               
West Cameron 75
      20.0 %   $ 25,112     $ 28,112    
Production commenced in 2007.  Recompletion is planned for 2016 at an estimated cost of $3.0 million.
                               
West Cameron 76 #12
      11.24 %   $ 5,318     $ 5,318    
Production commenced in 2008.
 
 
Marketing/Customers

The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to market the Fund’s oil and natural gas.  The number of customers purchasing the Fund’s oil and natural gas may vary from time to time.  During 2013, the Fund had three major customers in the public market and currently, the Fund has two major customers in the public market.  Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations.
  
The Fund’s current producing projects are near existing transportation infrastructure and pipelines.  The Manager believes that oil and natural gas from the Fund’s non-producing projects will have access to pipeline transportation and will be marketed through Energy Upgrade, Inc.   The Fund is participating in the financing of both platform and pipeline infrastructure for its non-producing project.

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 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.  Historically, 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.   

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, however, it did experience limited shut-ins, or production stoppages due to hurricane activity in 2013.

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 properties are operated by Arena Offshore, LP, Deep Gulf Energy LP, Enven Energy Ventures, LLC, LLOG Exploration Company, LLC, M21K LLC, W&T Offshore, Inc. and Walter Oil & Gas Corporation.
 
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 to cover the risks associated with the Fund’s passive investments.  Although the Fund is not an operator, the Manager has, nonetheless, obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to 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
 
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 $1.3 million from capital contributions and reinvested interest into a salvage fund.  As a result of the significant capital required and number of wells anticipated for the Beta Project, any further contributions 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 and the Manager. There are no legal restrictions on the withdrawal or use of the salvage fund.

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

Employees

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

Offices

The 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 and also owns additional office space at 79 Turtle Point, Tuxedo Park, NY, 10987. 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.
 
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 (the “Department of Interior”). Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”) 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.
 
 
Offshore operations are subject to regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities.  Effective October 22, 2012, the Department of Interior, acting through the BSEE, implemented the Final Drilling Safety Rule (the “Final Rule”), which refined certain interim rules imposed in the immediate wake of the 2010 Deepwater Horizon oil spill.  The Final Rule was promulgated for the prevention of waste and for the conservation of natural resources of the OCS under the rulemaking authority of the OCSLA.  Among other things, the Final Rule (1) enhances the description and classification of well-control barriers, (2) defines testing requirements for cement, (3) clarifies requirements for the installation of dual mechanical barriers, (4) extends requirements for blowout preventers and well-control fluids to well-completions, workovers and decommissioning operations, and (5) requires independent third-party verification of certain safety measures and enhanced documentation for blowout preventer inspections and maintenance.

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.  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.
 
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, as amended (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez spill, that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to, and increases penalties for, such spills. 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.

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, as amended, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment.

The above represents a brief outline of 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 its environmental, health and safety risks are materially different from those of comparable companies in the United States in the offshore oil and gas industry.  However, there are no assurances that the environmental regulations described above will not result in curtailment of production or material increases in the costs of production, development or exploration, or otherwise have a material adverse effect on the Fund’s operating results and cash flows.

Dodd-Frank Act.  The Dodd-Frank Act, signed into law in July 2010, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market and, in addition, requires certain additional SEC reporting requirements.

The Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Dodd-Frank mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses.  Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the CFTC, and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums.  In addition, as required by Dodd-Frank, the CFTC has set “speculative position limits” (limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts.  These requirements under Dodd-Frank could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties.  If the Fund alters any hedging program as a result of the legislation and regulations, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance.
 
 
Dodd-Frank also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals.  Rules were issued by the SEC in August 2012, and resource extraction issuers were required to comply with these new rules for fiscal years ending after September 30, 2013.  These rules were vacated in federal court in July 2013.  The SEC has indicated that it will not appeal this decision and will instead redraft the rules.  When any newly proposed resource extraction rules are issued by the SEC, the Fund will evaluate any impact of the rules on its business.


Not required.


None.


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, 2013 and 2012.  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 will produce both oil and natural gas, are located in the offshore waters of the Gulf of Mexico.  During the years ended December 31, 2013 and 2012, 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, 2013.

   
2013
   
2012
 
   
Gross
   
Net
   
Gross
   
Net
 
Exploratory wells:
                       
In-progress
    1       0.02       1       0.02  
Exploratory well total
    1       0.02       1       0.02  
 
Unaudited Oil and Gas Reserve Quantities
The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation.  The Fund’s management controls over proved reserve estimation include: 1) verification of input data that is provided to an independent petroleum engineering firm; 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines; and 3) a review of the reserve estimates by the Manager.

The Manager’s primary technical person in charge of overseeing the Fund’s reserve estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute.  With over twenty-five 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, 2013 and 2012 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.

Proved 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 8. “Financial Statements and Supplementary Data” of this Annual Report, is incorporated herein by reference. 
 
 
Proved Undeveloped Reserves.  At December 31, 2013, the Fund had approximately 278 thousand barrels and 5.3 million mcf of proved undeveloped oil and natural gas reserves, respectively.  At December 31, 2012, the Fund had approximately 278 thousand barrels and 4.9 million mcf of proved undeveloped oil and natural gas reserves, respectively.  Such reserves are related to the Beta Project and West Cameron 75.  The development of the Beta Project, which was determined to be a discovery during 2012, is ongoing and production is expected to commence in 2016.  The Fund currently expects to develop the proved undeveloped reserves relating to West Cameron 75 during 2016.

Costs incurred to advance the development of proved undeveloped reserves were approximately $1.5 million during the year ended December 31, 2013, which related to the Beta Project.  Information regarding estimated future development costs relating to the development of the Fund’s non-producing properties, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.

Production and Prices
The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, 2013 and 2012 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference. 

Delivery Commitments
As of December 31, 2013, the Fund had no delivery obligations or delivery commitments under any existing contracts.


None.


None.

 
-11-

 
PART II


There is currently no established public trading market for the Shares. As of the date of this filing, there were 1,681 shareholders of record of the Fund.

Distributions are made in accordance with the provisions of the LLC Agreement.  At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders.  Due to the significant capital required to develop the Beta Project, distributions have been impacted, and may be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations. There is no requirement to distribute available cash and as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 2013 and 2012, the Fund paid distributions totaling $6.5 million and $8.9 million, respectively.


Not required.


Overview of the Fund’s Business
The Fund was organized primarily to acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects.  However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.

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

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 a material 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” within 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 and exploration expenses are expensed as incurred. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”

Unproved Property
Unproved property is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination.  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.  The Fund assesses all items in its unproved property balance on an ongoing basis for possible impairment or reduction in value.

Proved Reserves
Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization.  Annually, the Fund engages an independent petroleum engineer to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change.

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

Impairment of Long-Lived Assets
The Fund reviews the 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 proved 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 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.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, 2013 and 2012, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.
 
 
   
Year ended December 31,
 
   
2013
   
2012
 
Revenue
 
(in thousands)
 
Oil and gas revenue
  $ 12,744     $ 15,081  
                 
Expenses
               
Depletion, depreciation and amortization
    3,019       8,850  
Dry-hole costs
    466       10  
Impairment of oil and gas properties
    404       680  
Management fees to affiliate
    2,044       2,046  
Operating expenses
    1,501       1,408  
Workover expenses
    404       221  
General and administrative expenses
    289       339  
Total expenses
    8,127       13,554  
Income from operations
    4,617       1,527  
Other income (loss)
    1       (14 )
Net income
  $ 4,618     $ 1,513  
 
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, 2013 and 2012. During the year ended December 31, 2013, natural gas liquid (“NGL”) sales are included within gas sales.  NGL information for the year ended December 31, 2012 has been consolidated to conform to the current presentation.
 
   
Year ended December 31,
 
   
2013
   
2012
 
Number of wells producing
    6       6  
Total number of production days
    1,809       1,841  
Oil sales (in thousands of barrels)
    49       76  
Average oil price per barrel
  $ 104     $ 106  
Gas sales (in thousands of mcfs)
    2,078       2,125  
Average gas price per mcf
  $ 3.69     $ 3.27  
 
The decrease in production days was primarily related to the Liberty and Carrera projects, which were shut-in periodically during 2013, partially offset by Eugene Island 346/347 well #1, which was shut-in periodically during 2012.  The decrease in sales volumes was related to a reduction in producing days coupled with natural declines in the Fund’s wells’ production.  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, 2013 was $12.7 million, a decrease of $2.3 million from the year ended December 31, 2012.  The decrease is attributable to decreased sales volume totaling $3.1 million, partially offset by the impact of the change in average prices totaling $0.8 million.  See “Overview” above for additional information.
 
Depletion, Depreciation and Amortization.  Depletion, depreciation and amortization for the year ended December 31, 2013 was $3.0 million, a decrease of $5.8 million from the year ended December 31, 2012.  The decrease resulted from a decrease in average depletion rates totaling $5.3 million coupled with a decrease in production volumes totaling $0.6 million.  The decrease in average depletion rates was principally attributable to increases in reserve estimates, principally related to West Cameron 75.  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 adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.  Dry hole costs were $0.5 million during the year ended December 31, 2013, which related primarily to Mississippi Canyon 489/490.  Dry-hole costs were $10 thousand during the year ended December 31, 2012.

Impairment of Oil and Gas Properties.   During the year ended December 31, 2013, the Fund recorded an impairment of $0.4 million related to the Cobalt Project, which was attributable to declines in future oil and gas prices and an increase in estimated asset retirement costs.  During the year ended December 31, 2012, the Fund recorded an impairment of $0.7 million, related to Eugene Island 346/347 well #1, which was attributable to revisions to reserve estimates as provided by the Fund’s independent petroleum engineers coupled with declines in future oil and gas prices.

Management Fees to Affiliate.  Management fees for each of the years ended December 31, 2013 and 2012 were $2.0 million.  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,
 
   
2013
   
2012
 
   
(in thousands)
 
Lease operating expense
  $ 1,468     $ 1,328  
Geological costs
    21       69  
Accretion expense
    12       11  
    $ 1,501     $ 1,408  
 
Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  The average production cost was $3.72 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2013 compared to $3.18 per BOE during the year ended December 31, 2012.  Geological costs, which were primarily related to the Beta Project, represent costs incurred to obtain seismic data, surveys, and lease rentals.  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.  Workover expenses of $0.4 million during the year ended December 31, 2013 related to the Liberty and Carrera projects and West Cameron 75. Workover expenses of $0.2 million during the year ended December 31, 2012 related primarily to West Cameron 75.

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,
 
   
2013
   
2012
 
   
(in thousands)
 
Accounting and professional fees
  $ 140     $ 126  
Insurance expense
    144       135  
Legal costs and other
    5       78  
    $ 289     $ 339  

Accounting and professional fees represent expenses for audits, quarterly reviews, tax preparation, reserve data engineering and reporting, and administration of filings.  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.  During the year ended December 31, 2012, legal costs represent fees incurred in connection with obtaining financing for the Beta Project.  See Note 5 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the debt acquisition costs.
 
 
Other Income (Loss).  Other income (loss) for the years ended December 31, 2013 and 2012 is detailed in the following table.
 
   
Year ended December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Interest income
  $ 1     $ 32  
Realized losses on derivative instruments
    -       (46 )
    $ 1     $ (14 )

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the year ended December 31, 2013 were $9.2 million, primarily related to revenue received of $13.4 million, partially offset by management fees of $2.0 million, operating expenses paid of $1.2 million, workover expenses paid of $0.7 million, and general and administrative expenses paid of $0.3 million.
 
Cash flows provided by operating activities for the year ended December 31, 2012 were $10.4 million, primarily related to revenue received of $14.3 million, partially offset by management fees of $2.0 million, operating and workover expenses paid of $1.6 million, and general and administrative expenses paid of $0.3 million.

Investing Cash Flows
Cash flows used in investing activities for the year ended December 31, 2013 were $2.1 million, primarily related to capital expenditures for oil and gas properties of $2.0 million, inclusive of advances and investments in salvage fund of $0.1 million.

Cash flows provided by investing activities for the year ended December 31, 2012 were $1.8 million, primarily related to proceeds from U.S Treasury securities of $3.0 million, partially offset by capital expenditures for oil and gas properties of $1.1 million.

Financing Cash Flows
Cash flows used in financing activities for the year ended December 31, 2013 were $6.5 million, related to manager and shareholder distributions.

Cash flows used in financing activities for the year ended December 31, 2012 were $9.0 million, primarily related to manager and shareholder distributions of $8.9 million and debt acquisition costs of $0.1 million.  See Note 5 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the debt acquisition costs.

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 vary depending on the stage of development on a property-by-property basis. As of December 31, 2013, the Fund has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $14.1 million related to the development of this project, which the Fund anticipates will include a four-well development with related platform and pipeline infrastructure. It is also possible that full development of the Beta Project will entail the drilling of additional wells beyond the four projected wells, the cost of which is not included in the above estimates. See “Liquidity Needs” below for additional information.

Capital expenditures for investment properties have been funded with the capital raised by the Fund in its private placement offering, and in certain circumstances, through debt financing. The number of projects in which the Fund can invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.
 
 
Liquidity Needs

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

As of December 31, 2013, the Fund expects to spend an additional $17.2 million related to its investments in oil and gas properties, of which $3.7 million is expected to be spent during 2014. Total capital commitments exceed available working capital by $8.7 million at December 31, 2013, which includes projected interest costs and asset retirement obligations for the Beta Project. In November 2012, the Fund entered into a credit agreement that provides for an aggregate loan commitment of up to $8.8 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Principal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2020. See “Credit Agreement” below for additional information. The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, 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. Due to the significant capital required to develop the Beta Project, distributions have been impacted, and may be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations.

Credit Agreement
In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as administrative agent and lender (and any other banks or financial institutions that may in the future become a party thereto) that provides for an aggregate loan commitment to the Fund of approximately $8.8 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of December 31, 2013 and 2012, the Fund had no borrowings under the Credit Agreement.  See Note 5 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.

The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warrants and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the Lenders under the Credit Agreement may accelerate the maturity of the loans and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund believes it is in compliance with all covenants under the Credit Agreement at December 31, 2013 and 2012.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at December 31, 2013 and 2012 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, 2013 and 2012 other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs” – Credit Agreement 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.
 
 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Not required.
 
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.
 

None.

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, 2013.  Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

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

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

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2013.  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 (1992). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2013, 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, 2013 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

OTHER INFORMATION

None.
 
 
PART III
 
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, 2013 are as follows:
 
 
Name, Age and Position with Registrant
Officer of Ridgewood Energy
Corporation Since
   
Robert E. Swanson, 66
  Chief Executive Officer
1982
   
Kenneth W. Lang, 59
  President and Chief Operating Officer
2009
   
Kathleen P. McSherry, 48
  Executive Vice President and Chief Financial Officer
2001
   
Robert L. Gold, 55
  Executive Vice President
1987
   
Daniel V. Gulino, 53
  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.  Ms. McSherry holds a Bachelor of Science degree in Accounting.

Robert L. Gold has served as a senior officer of Ridgewood Energy since 1987, is an Executive Vice President of the Fund 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.

Board of Directors and Board Committees
The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure.  Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11. “Executive Compensation” of this Annual Report.  Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager, the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.
 
 
Code of Ethics
The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on the Manager’s website or in a current report on Form 8-K.  Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN:  General Counsel.

Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, 2013, all filing requirements applicable to its officers, directors and 10% beneficial owners were met on a timely basis.


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.


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 as of the date of this filing.  No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.


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 each of the years ended December 31, 2013 and 2012 were $2.0 million.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.   Distributions paid to the Manager for the years ended December 31, 2013 and 2012 were $1.0 million and $1.3 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 amounts paid to the Manager have 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.
 
 
 
The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, 2013 and 2012.
 
   
Year ended December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Audit fees (1)
  $ 85     $ 80  
 
(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


(a) (1)     Financial Statements

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

(a) (2)     Financial Statement Schedules

None.


(a) (3)    
 
EXHIBIT
NUMBER
   TITLE OF EXHIBIT   METHOD OF FILING
         
3.1
 
Certificate of Formation of Ridgewood Energy 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

10.1
 
Credit Agreement dated as of November 27, 2012 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto
 
Incorporated by reference to the Fund's Form 8-K filed on December 3, 2012
         
31.1
 
Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
 
Filed herewith
         
31.2
 
Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)
 
Filed herewith
 
 
32
 
Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund
 
Filed herewith
         
99.1
 
Report of Netherland, Sewell & Associates, Inc.
 
Filed herewith
         
101.INS
 
XBRL Instance Document
 
Filed herewith
         
101.SCH
 
XBRL Taxonomy Extension Schema
 
Filed herewith
         
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase
 
Filed herewith
         
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
Filed herewith
         
101.LAB
 
XBRL Taxonomy Extension Label Linkbase
 
Filed herewith
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase
 
Filed herewith
 
 
 
 
 
 
 

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 25, 2014
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 25, 2014
/s/ ROBERT E. SWANSON
Chief Executive Officer (Principal
  Executive Officer)
Robert E. Swanson
 
     
     
/s/ KATHLEEN P. MCSHERRY
Executive Vice President and Chief Financial
Officer (Principal Financial and Accounting
Officer)
February 25, 2014
Kathleen P. McSherry
 
     
RIDGEWOOD ENERGY
CORPORATION
   
BY:  /s/ ROBERT E. SWANSON
Chief Executive Officer of the Manager
February 25, 2014
Robert E. Swanson
   
 
 
 

 

 
 
 
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, 2013 and 2012, and the related statements of operations, changes in members’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Fund’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Fund’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy T Fund, LLC as of December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
 

 
/s/ Deloitte & Touche LLP
 
Parsippany, New Jersey
February 25, 2014
 

RIDGEWOOD ENERGY T FUND, LLC
(in thousands, except share data)

   
December 31,
 
   
2013
   
2012
 
Assets
           
Current assets:
           
Cash and cash equivalents
  $ 8,636     $ 8,050  
Production receivable
    1,568       2,217  
Other current assets
    92       75  
                      Total current assets     10,296       10,342  
Salvage fund
    1,309       1,210  
Other assets
    526       657  
Oil and gas properties:
               
Advances to operators for working interests and expenditures
    101       -  
Proved properties
    53,448       52,938  
Equipment and facilities - in progress
    1,842       -  
Less:  accumulated depletion, depreciation and amortization
    (47,319 )     (43,896 )
  Total oil and gas properties, net
    8,072       9,042  
  Total assets
  $ 20,203     $ 21,251  
                 
Liabilities and Members' Capital
               
Current liabilities:
               
Due to operators
  $ 1,753     $ 1,377  
Accrued expenses
    41       42  
  Total current liabilities
    1,794       1,419  
Asset retirement obligations
    1,556       1,076  
  Total liabilities
    3,350       2,495  
Commitments and contingencies (Note 6)
               
Members' capital:
               
Manager:
               
  Distributions
    (7,096 )     (6,118 )
  Retained earnings
    5,729       4,488  
  Manager's total
    (1,367 )     (1,630 )
Shareholders:
               
  Capital contributions (1,000 shares authorized;
     971.6054 issued and outstanding)
    144,529       144,529  
  Syndication costs
    (16,990 )     (16,990 )
  Distributions
    (42,721 )     (37,178 )
  Accumulated deficit
    (66,598 )     (69,975 )
  Shareholders' total
    18,220       20,386  
  Total members' capital
    16,853       18,756  
  Total liabilities and members' capital
  $ 20,203     $ 21,251  

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

RIDGEWOOD ENERGY T FUND, LLC
(in thousands, except per share data)

   
Year ended December 31,
 
   
2013
   
2012
 
Revenue
           
Oil and gas revenue
  $ 12,744     $ 15,081  
                 
Expenses
               
Depletion, depreciation and amortization
    3,019       8,850  
Dry-hole costs
    466       10  
Impairment of oil and gas properties
    404       680  
Management fees to affiliate (Note 4)
    2,044       2,046  
Operating expenses
    1,501       1,408  
Workover expenses
    404       221  
General and administrative expenses
    289       339  
             Total expenses     8,127       13,554  
              Income from operations     4,617       1,527  
Other income (loss)
    1       (14 )
              Net income   $ 4,618     $ 1,513  
                 
                      Manager Interest                
                      Net income   $ 1,241     $ 1,570  
                 
                      Shareholder Interest                
                      Net income (loss)   $ 3,377     $ (57 )
                      Net income (loss) per share   $ 3,474     $ (58 )

The accompanying notes are an integral part of these financial statements.
 
 
RIDGEWOOD ENERGY T FUND, LLC
(in thousands, except share data)

   
# of Shares
   
Manager
   
Shareholders
   
Total
 
Balances, December 31, 2011
    971.6054     $ (1,859 )   $ 28,043     $ 26,184  
Distributions
    -       (1,341 )     (7,600 )     (8,941 )
Net income (loss)
    -       1,570       (57 )     1,513  
Balances, December 31, 2012
    971.6054       (1,630 )     20,386       18,756  
Distributions
    -       (978 )     (5,543 )     (6,521 )
Net income
    -       1,241       3,377       4,618  
Balances, December 31, 2013
    971.6054     $ (1,367 )   $ 18,220     $ 16,853  
 
The accompanying notes are an integral part of these financial statements.
 
 
 
 
 
 
 
F-5

 
RIDGEWOOD ENERGY T FUND, LLC
(in thousands)
 
   
Year ended December 31,
 
   
2013
   
2012
 
Cash flows from operating activities
           
Net income
  $ 4,618     $ 1,513  
Adjustments to reconcile net income to net cash
provided by operating activities:
               
Depletion, depreciation and amortization
    3,019       8,850  
Dry-hole costs
    466       10  
Impairment of oil and gas properties
    404       680  
Accretion expense
    12       11  
Interest earned on marketable securities
    -       (1 )
Derivative instrument loss
    -       46  
Derivative instrument settlements
    -       4  
Debt acquisition costs
    -       71  
Changes in assets and liabilities:
               
Decrease (increase) in production receivable
    649       (791 )
Decrease (increase) in other current assets
    30       (14 )
(Decrease) increase in due to operators
    (36 )     38  
(Decrease) increase in accrued expenses
    (1 )     7  
Net cash provided by operating activities
    9,161       10,424  
                 
Cash flows from investing activities
               
Payments to operators for working interests and expenditures
    (101 )     -  
Capital expenditures for oil and gas properties
    (1,854 )     (1,126 )
Proceeds from maturity of investments
    -       3,001  
Investments in salvage fund
    (99 )     (31 )
Net cash (used in) provided by investing activities
    (2,054 )     1,844  
                 
Cash flows from financing activities
               
Distributions
    (6,521 )     (8,941 )
Debt acquisition costs
    -       (71 )
Net cash used in financing activities
    (6,521 )     (9,012 )
                 
Net increase in cash and cash equivalents
    586       3,256  
Cash and cash equivalents, beginning of year
    8,050       4,794  
Cash and cash equivalents, end of year
  $ 8,636     $ 8,050  
                 
Supplemental schedule of non-cash financing activities
               
Deferred financing charges related to the conveyance of
overriding royalty interest in the Beta Project
  $ -     $ 657  
 
The accompanying notes are an integral part of these financial statements.
 
 
RIDGEWOOD ENERGY T FUND, LLC

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, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico.

The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions 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, 5 and 6.
 
Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.

Fair Value Measurements
The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Cash and cash equivalents and held-to-maturity investments approximate fair value based on Level 1 inputs.
 
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 are $250 thousand per insured financial institution. At December 31, 2013, the Fund’s bank balances exceeded federally insured limits by $9.9 million.

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, 2012, the Fund had investments in U.S. Treasury securities within its salvage fund that were classified as held-to-maturity of $1.1 million, which matured in March 2013. 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.  There were no held-to-maturity investments at December 31, 2013.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.
 
 
Debt Discounts and Deferred Financing Costs
Debt discounts and deferred financing costs include lender fees and other costs of the Credit Agreement (see Note 5. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”. At December 31, 2013 and 2012, $0.5 million and $0.7 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $0.1 million during the year ended December 31, 2013. There was no amortization expense during the year ended December 31, 2012. During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”.

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. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”  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.  All costs related to production activity and workover efforts are expensed as incurred.
 
Upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion, depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.
 
At December 31, 2013 and 2012, amounts recorded in due to operators totaling $0.7 million and $0.3 million, 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, 2013 and 2012.
 
   
2013
   
2012
 
   
(in thousands)
 
Balance, beginning of year
  $ 1,076     $ 1,052  
Liabilities incurred
    -       13  
Liabilities settled
    -       -  
Accretion expense
    12       11  
Revisions in estimated cash flows
    468       -  
Balance, end of year
  $ 1,556     $ 1,076  
 
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 collectability 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.

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 estimated fair value of such 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.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.  See Note 2.  “Derivative Instruments”.

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 proved 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 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 year ended December 31, 2013, the Fund recorded an impairment of $0.4 million related to the Cobalt Project, which was attributable to declines in future oil and gas prices and an increase in estimated asset retirement costs.  During the year ended December 31, 2012, the Fund recorded an impairment of $0.7 million, related to Eugene Island 346/347 well #1, which was attributable to revisions to reserve estimates and declines in future oil and gas prices.   During the years ended December 31, 2013 and 2012, the fair values of the impaired properties at the dates of impairment were $0.3 million and $0.4 million, respectively.  Such amounts were determined based on level 3 inputs, which included projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.

Depletion, Depreciation and Amortization
Depletion, depreciation and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs.  In certain circumstances, equipment and facilities costs are depreciated over the estimated useful life of the asset.
 
 
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 to shareholders and the Manager in accordance with the LLC agreement.
 
Distributions
Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.

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

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. The use of such derivative instruments limits the downside risk of adverse price movements. The estimated fair value of such contracts is based upon various factors, including reported prices on NYMEX and ICE, volatility, and the time value of options. The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.

The Fund had no derivative contracts during the year ended December 31, 2013.  For the year ended December 31, 2012, the Fund’s derivative instrument income consisted of realized losses of $46 thousand.

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. The following table reflects the net changes in unproved properties for the years ended December 31, 2013 and 2012.

   
2013
   
2012
 
   
(in thousands)
 
Balance, beginning of year
  $ -     $ 1,524  
Additions to capitalized exploratory well costs
  pending the determination of proved reserves
    -       -  
Reclassifications to proved properties based on
  the determination of proved reserves
    -       (1,524 )
Capitalized exploratory well costs charged to
 expense
    -       -  
Balance, end of year
  $ -     $ -  
 
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 adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.  Dry-hole costs during the year ended December 31, 2013 were principally related to additional costs for Mississippi Canyon 489/490.

Workover expenses of $0.4 million during the year ended December 31, 2013 related primarily to the Liberty and Carrera projects and to West Cameron 75. Workover expenses of $0.2 million during the year ended December 31, 2012 related primarily to West Cameron 75.
 
 
4.   Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services to the Fund.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for each of the years ended December 31, 2013 and 2012 were $2.0 million.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2013 and 2012 were $1.0 million and $1.3 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 amounts paid to the Manager have 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.  Credit Agreement – Beta Project Financing

In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $8.8 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. In addition to the Fund’s execution of the Credit Agreement, Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC and Ridgewood Energy B-1 Fund, LLC (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Fund. The Manager serves as the manager for each Ridgewood Participating Fund.

As of December 31, 2013 and 2012, the Fund had no borrowings under the Credit Agreement.  The Fund anticipates it will borrow approximately $8.8 million over the development period of the Beta Project, which will bear interest at 8% compounded annually and accrue only on Loan proceeds as they are drawn.  Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected to occur in 2016. At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund’s total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund’s total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020.  The Loan may be prepaid by the Fund without premium or penalty.

As additional consideration to the Lenders, each Ridgewood Participating Fund has agreed to convey an overriding royalty interest (“ORRI”) to the Lenders in their working interests in the Beta Project. Each Ridgewood Participating Fund’s share of the Lender’s aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Using these principles, the Fund’s percentage ORRI to be granted to the Lenders equals 17.39% of the Fund’s production until the Fund’s share of Beta Project’s cumulative production equals approximately 0.5 million barrels of oil (“MMBO”), net of royalties. Upon reaching that milestone, the Fund’s ORRI percentage decreases to 11.59% of the Fund’s production until the Fund’s share of the Beta Project’s cumulative production equals approximately 0.79 MMBO, net of royalties, whereupon it decreases to, and remains at, 5.80% of the Fund’s net production.  The Fund recorded the additional consideration as debt discounts and deferred financing costs at a fair value of $0.7 million, which is amortized to interest expense over the expected payoff period of the loan.  The fair value of the ORRI was determined using net discounted cash flows from the Beta Project related to the ORRI based on level 3 inputs, which include projected net income from reserves and forward pricing curves.  At December 31, 2013 and 2012, the outstanding debt discounts and deferred financing costs recorded on the balance sheet within “Other assets” were $0.5 million and $0.7 million, respectively.
 
 
The Credit Agreement contains customary covenants, for which the Fund believes it is in compliance at December 31, 2013 and 2012.
 
The expenses related to the securing of the Credit Agreement were borne by the Ridgewood Participating Funds. The Fund’s portion of such expenses was $0.1 million.

6.  Commitments and Contingencies

Capital Commitments
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 vary depending on the stage of development on a property-by-property basis. Currently, the Fund has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently anticipates such development will include a four-well development with related platform and pipeline infrastructure. It is also possible that full development of the Beta Project will entail the drilling of additional wells beyond the four projected wells, the cost of which is not included in the below estimates.

As of December 31, 2013, the Fund expects to spend an additional $17.2 million related to its investments in oil and gas properties, of which $3.7 million is expected to be spent during 2014. Total capital commitments exceed available working capital by $8.7 million at December 31, 2013, which includes projected interest costs and asset retirement obligations for the Beta Project. In November 2012, the Fund entered into the Credit Agreement that provides for an aggregate loan commitment of up to $8.8 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. See Note 5. “Credit Agreement – Beta Project Financing,” for additional information. The Fund expects that cash flows from operations will be sufficient to fund its remaining commitments.

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, 2013 and 2012, there were no known environmental contingencies that required the Fund to record a liability.

Effective October 22, 2012, the United States Department of Interior, acting through the Bureau of Safety and Environmental Enforcement, implemented the Final Drilling Safety Rule (the “Final Rule”) which refined certain interim rules imposed in the immediate wake of the 2010 Deepwater Horizon oil spill. The Final Rule was promulgated for the prevention of waste and for the conservation of natural resources of the Outer Continental Shelf under the rulemaking authority of the Outer Continental Shelf Lands Act. The United States Congress continues to consider a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore, in addition to the Final Rule. 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 the Fund’s business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

Insurance Coverage
The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.
 
 
Ridgewood Energy T Fund, LLC
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 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,
 
   
2013
   
2012
 
   
(in thousands)
 
Advances to operators for working interests and expenditures
  $ 101     $ -  
Proved properties
    53,448       52,938  
Equipment and facilities - in progress
    1,842       -  
   Total oil and gas properties
    55,391       52,938  
Accumulated depletion, depreciation and amortization
    (47,319 )     (43,896 )
Oil and gas properties, net
  $ 8,072     $ 9,042  
 
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
 
   
Year ended December 31,
 
      2013       2012  
   
(in thousands)
 
Exploration costs
  $ (73 )   $ 826  
Development costs
    2,882       203  
    $ 2,809     $ 1,029  
 
 
 
 
 
 
 
Table III - Reserve Quantity Information
 
Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2013 and 2012.  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, 2013
   
December 31, 2012
 
   
United States
 
   
Oil (BBLS)
   
Gas (MCF)
   
Oil (BBLS)
   
Gas (MCF)
 
                         
Proved developed and undeveloped reserves:
                   
Beginning of year
    396,709       7,483,686       140,968       7,685,381  
Extensions and discoveries
    -       -       273,596       205,197  
Revisions of previous estimates (a)
    3,524       2,270,161       58,165       1,721,994  
Production
    (48,456 )     (2,063,476 )     (76,020 )     (2,128,886 )
End of year
    351,777       7,690,371       396,709       7,483,686  
                                 
Proved developed reserves:
                               
Beginning of year
    118,283       2,593,554       137,204       3,074,881  
End of year
    73,333       2,349,780       118,283       2,593,554  
                                 
Proved undeveloped reserves:
                               
Beginning of year
    278,426       4,890,132       3,764       4,610,500  
End of year (b)
    278,444       5,340,591       278,426       4,890,132  
 
 (a) Revisions of previous estimates during the years ended December 31, 2013 and 2012 were attributable to well performance.

(b) The increases in proved undeveloped reserves during the year ended December 31, 2013 were principally due to revisions to estimates for West Cameron 75, which were attributable to well performance.  The increases in proved undeveloped reserves during the year ended December 31, 2012 were due to discoveries relating to the Beta Project, coupled with revisions to estimates for West Cameron 75, which were attributable to well performance.
 

 
Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves.  Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve month period.  Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.
 
   
December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Future cash inflows
  $ 64,522     $ 68,398  
Future production costs
    (6,958 )     (6,343 )
Future development costs
    (16,999 )     (17,068 )
Future net cash flows
    40,565       44,987  
10% annual discount for estimated timing of cash flows
    (13,794 )     (14,957 )
Standardized measure of discounted future net cash flows
  $ 26,771     $ 30,030  

 
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,
 
   
2013
   
2012
 
   
(in thousands)
 
Net change in sales and transfer prices and in production costs
related to future production
  $ (4,132 )   $ (9,274 )
Sales and transfers of oil and gas produced during the period
    (11,276 )     (13,753 )
Net change due to extensions, discoveries, and improved recovery
    -       6,728  
Changes in estimated future development costs
    69       (42 )
Net change due to revisions in quantities estimates
    8,881       9,093  
Accretion of discount
    3,003       3,781  
Other
    196       (4,308 )
Aggregate change in the standardized measure of discounted future net
cash flows for the year
  $ (3,259 )   $ (7,775 )
 
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.
 
 
 F-15