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Document and Entity Information (USD $)
12 Months Ended
Dec. 31, 2013
Mar. 10, 2014
Document and Entity Information [Abstract] ' '
Document Type '10-K '
Amendment Flag 'false '
Document Period End Date Dec 31, 2013 '
Entity Registrant Name 'Ridgewood Energy U Fund LLC '
Entity Central Index Key '0001377178 '
Current Fiscal Year End Date '--12-31 '
Document Fiscal Year Focus '2013 '
Document Fiscal Period Focus 'FY '
Entity Filer Category 'Smaller Reporting Company '
Entity Common Stock, Shares Outstanding ' 486.4825
Entity Current Reporting Status 'Yes '
Entity Well-known Seasoned Issuer 'No '
Entity Voluntary Filers 'No '
Entity Public Float $ 0 '
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BALANCE SHEETS (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Current assets: ' '
Cash and cash equivalents $ 6,107 $ 7,548
Production receivable 214 420
Other current assets 36 108
Total current assets 6,357 8,076
Salvage fund 1,156 1,156
Other assets 89 89
Oil and gas properties: ' '
Proved properties 17,427 15,717
Equipment and facilities - in progress 277 61
Less: accumulated depletion, depreciation and amortization (11,942) (10,052)
Total oil and gas properties, net 5,762 5,726
Total assets 13,364 15,047
Current liabilities: ' '
Due to operators 73 155
Accrued expenses 39 39
Total current liabilities 112 194
Asset retirement obligations 986 590
Total liabilities 1,098 784
Commitments and contingencies (Note 5) '   '  
Members' capital: ' '
Distributions (1,073) (847)
Accumulated deficit (156) (335)
Manager's total (1,229) (1,182)
Capital contributions (1,000 shares authorized; 486.4825 issued and outstanding) 72,381 72,381
Syndication costs (8,541) (8,541)
Distributions (8,372) (7,089)
Accumulated deficit (41,973) (41,306)
Shareholders' total 13,495 15,445
Total members' capital 12,266 14,263
Total liabilities and members' capital $ 13,364 $ 15,047
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BALANCE SHEETS (Parenthetical)
Dec. 31, 2013
Dec. 31, 2012
BALANCE SHEETS [Abstract] ' '
Shares authorized 1,000 1,000
Shares issued 486.4825 486.4825
Shares outstanding 486.4825 486.4825
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STATEMENTS OF OPERATIONS (USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Revenue ' '
Oil and gas revenue $ 2,429 $ 3,773
Expenses ' '
Depletion, depreciation and amortization 1,385 3,245
Dry-hole costs (113) (26)
Impairment of oil and gas properties 505 3,114
Management fees to affiliate (Note 4) 371 789
Operating expenses 553 523
General and administrative expenses 216 198
Total expenses 2,917 7,843
Gain on sale of oil and gas properties '   20
Loss from operations (488) (4,050)
Other income '   3
Net loss (488) (4,047)
Manager Interest ' '
Net income 179 292
Shareholder Interest ' '
Net loss $ (667) $ (4,339)
Net loss per share $ (1,371) $ (8,920)
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STATEMENTS OF CHANGES IN MEMBERS' CAPITAL (USD $)
In Thousands, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Balances $ 14,263 $ 19,929
Balances, shares 486.4825 486.4825
Distributions (1,509) (1,619)
Net income (loss) (488) (4,047)
Balances 12,266 14,263
Balances, shares 486.4825 486.4825
# of Shares [Member] ' '
Balances, shares 486.4825 486.4825
Distributions '   '  
Net income (loss) '   '  
Balances, shares 486.4825 486.4825
Manager [Member] ' '
Balances (1,182) (1,231)
Distributions (226) (243)
Net income (loss) 179 292
Balances (1,229) (1,182)
Shareholders [Member] ' '
Balances 15,445 21,160
Distributions (1,283) (1,376)
Net income (loss) (667) (4,339)
Balances $ 13,495 $ 15,445
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STATEMENTS OF CASH FLOWS (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Cash flows from operating activities ' '
Net loss $ (488) $ (4,047)
Adjustments to reconcile net loss to net cash provided by operating activities: ' '
Depletion, depreciation and amortization 1,385 3,245
Dry-hole costs (113) (26)
Impairment of oil and gas properties 505 3,114
Gain on sale of oil and gas properties '   (20)
Accretion expense 16 6
Interest earned on marketable securities '   (1)
Derivative instrument loss '   8
Derivative instrument settlements '   1
Changes in assets and liabilities: ' '
Decrease (increase) in production receivable 206 (182)
Decrease (increase) in other current assets 40 (2)
(Decrease) increase in due to operators (10) 41
Increase in accrued expenses '   6
Net cash provided by operating activities 1,541 2,143
Cash flows from investing activities ' '
Capital expenditures for oil and gas properties (1,473) (2,729)
Investments in marketable securities '   (6,000)
Proceeds from maturity of investments '   10,501
Deposits to escrow account - Delta House '   (89)
Interest reinvested in salvage fund '   (11)
Net cash (used in) provided by investing activities (1,473) 1,672
Cash flows from financing activities ' '
Distributions (1,509) (1,619)
Net cash used in financing activities (1,509) (1,619)
Net (decrease) increase in cash and cash equivalents (1,441) 2,196
Cash and cash equivalents, beginning of year 7,548 5,352
Cash and cash equivalents, end of year 6,107 7,548
Supplemental schedule of non-cash operating activities ' '
Adjustments to asset retirement obligations '   20
Supplemental schedule of non-cash investing activities ' '
Advances used for capital expenditures in oil and gas properties reclassified to proved properties '   $ 235
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Organization and Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2013
Organization and Summary of Significant Accounting Policies [Abstract] '
Organization and Summary of Significant Accounting Policies '
1. Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy U Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on August 28, 2006 and operates pursuant to a limited liability company agreement (the "LLC Agreement") dated as of October 1, 2006 by and among Ridgewood Energy Corporation (the "Manager") and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico.
  
The Manager has direct and exclusive control over the management of the Fund's operations.  With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions in which the investments are made.  The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations.  Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information.  In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations.  The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required.  See Notes 4 and 5.

Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period.  On an ongoing basis, 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 $7.3 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 $1.0 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.
 
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 $13 thousand and $0.1 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
  $ 590     $ 463  
Liabilities incurred
    79       141  
Liabilities settled
    -       (20 )
Accretion expense
    16       6  
Revisions in estimated cash flows
    301       -  
Balance, end of year
  $ 986     $ 590  
   
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 $0.5 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 $3.1 million, related to the Alpha Project, which was attributable to revisions to reserve estimates.  During the years ended December 31, 2013 and 2012, the fair values of the impaired properties at the dates of impairment were $0.4 million and $2.6 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. Certain shares have early investment incentive and advance distribution rights, as defined in the LLC Agreement, which range from approximately $6 thousand to $12 thousand per share. The Fund began making distributions to eligible early investors during the second quarter 2009.  The Fund commenced distributions to all investors in January 2013.

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.

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Derivative Instruments
12 Months Ended
Dec. 31, 2013
Derivative Instruments [Abstract] '
Derivative Instruments '
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 $8 thousand.

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Oil and Gas Properties
12 Months Ended
Dec. 31, 2013
Oil and Gas Properties [Abstract] '
Oil and Gas Properties '
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.

   
December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Balance, beginning of year
  $ -     $ 7,163  
Additions to capitalized exploratory well costs
               
  pending the determination of proved reserves
    -       -  
Reclassifications to proved properties based on
               
  the determination of proved reserves
    -       (7,163 )
Capitalized exploratory well costs charged to
               
  expense
    -       -  
Balance, end of year
  $ -     $ -  
  
During the year ended December 31, 2012, the Fund recorded a gain on sale of oil and gas properties of $20 thousand as a result of the relief of its asset retirement obligations related to the Ajax Project.  There were no such amounts recorded during the year ended December 31, 2013.

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.  During the year ended December 31, 2013, the Fund recorded credits to dry-hole costs of $0.1 million, which related primarily to Garden Banks 334.  During the year ended December 31, 2012, the fund recorded credits to dry-hole costs of $26 thousand.

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Related Parties
12 Months Ended
Dec. 31, 2013
Related Parties [Abstract] '
Related Parties '
4.   Related Parties

In accordance with the LLC Agreement, the Manager is entitled to an annual management fee equal to 2.5% of total capital contributions made by the Fund's shareholders, net of cumulative dry-hole and related well costs incurred by the Fund.  In October 2012, the Manager elected to reduce its management fee to 1% annually.   Management fees for the years ended December 31, 2013 and 2012 were $0.4 million and $0.8 million, respectively.
 
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager for each of the years ended December 31, 2013 and 2012 were $0.2 million.

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.

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Commitments and Contingencies
12 Months Ended
Dec. 31, 2013
Commitments and Contingencies [Abstract] '
Commitments and Contingencies '
5.   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. As of December 31, 2013, the Fund expects to spend $5.2 million related to its investments in oil and gas properties, of which $1.5 million is expected to be spent during 2014.

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.
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Information about Oil and Gas Producing Activities
12 Months Ended
Dec. 31, 2013
Information about Oil and Gas Producing Activities [Abstract] '
Information about Oil and Gas Producing Activities '

Supplementary Financial Information
Information about Oil and Gas Producing Activities - Unaudited

 
In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of Louisiana and Texas in the Gulf of Mexico.
 
Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
 
   
December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Proved properties
  $ 17,427     $ 15,717  
Equipment and facilities - in progress
    277       61  
   Total oil and gas properties
    17,704       15,778  
Accumulated depletion, depreciation and amortization
    (11,942 )     (10,052 )
Oil and gas properties, net
  $ 5,762     $ 5,726  

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

   
Year ended December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Exploration costs
  $ (124 )   $ 1,021  
Development costs
    1,946       859  
    $ 1,822     $ 1,880  
 
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
    168,022       1,210,579       33,939       1,652,071  
Extensions and discoveries
    258,453       548,978       142,693       225,854  
Revisions of previous estimates (a)
    56,892       284,224       8,076       (99,696 )
Production
    (8,031 )     (424,114 )     (16,686 )     (567,650 )
End of year
    475,336       1,619,667       168,022       1,210,579  
                                 
Proved developed reserves:
                               
Beginning of year
    25,329       984,725       22,246       1,377,071  
End of year
    6,841       507,977       25,329       984,725  
                                 
Proved undeveloped reserves:
                               
Beginning of year
    142,693       225,854       11,693       275,000  
End of year (b)
    468,495       1,111,690       142,693       225,854  
 
 

 
 
(a)
Revisions of previous estimates during the years ended December 31, 2013 and 2012 were attributable to well performance.

 
(b)
At December 31, 2013, the increases in proved undeveloped reserves were due to the Marmalard Project, for which a second well was drilled during 2013.  The proved undeveloped reserves during the year ended December 31, 2012 were due to discoveries relating to the Diller and Marmalard projects.

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 c ash 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
  $ 55,970     $ 24,209  
Future production costs
    (17,281 )     (8,069 )
Future development costs
    (6,848 )     (4,585 )
Future net cash flows
    31,841       11,555  
10% annual discount for estimated timing of cash flows
    (14,494 )     (3,225 )
Standardized measure of discounted future net cash flows
  $ 17,347     $ 8,330  


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
  $ 2,364     $ (697 )
Sales and transfers of oil and gas produced during the period
    (1,983 )     (3,365 )
Net change due to extensions, discoveries, and improved recovery
    5,342       3,445  
Changes in estimated future development costs
    1,081       1,782  
Net change due to revisions in quantities estimates
    2,949       1,113  
Accretion of discount
    833       668  
Other
    (1,569 )     (1,292 )
Aggregate change in the standardized measure of discounted
 future net cash flows for the year
  $ 9,017     $ 1,654  


It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.
 
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Organization and Summary of Significant Accounting Policies (Policy)
12 Months Ended
Dec. 31, 2013
Organization and Summary of Significant Accounting Policies [Abstract] '
Use of Estimates '
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 '
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 '
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 $7.3 million.

Salvage Fund '
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 $1.0 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.
 
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 $13 thousand and $0.1 million, respectively, related to capital expenditures for oil and gas properties.
 
Advances to Operators for Working Interests and Expenditures '
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 '
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
  $ 590     $ 463  
Liabilities incurred
    79       141  
Liabilities settled
    -       (20 )
Accretion expense
    16       6  
Revisions in estimated cash flows
    301       -  
Balance, end of year
  $ 986     $ 590  
   
As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

Syndication Costs '
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 '
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 '
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 '
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 $0.5 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 $3.1 million, related to the Alpha Project, which was attributable to revisions to reserve estimates.  During the years ended December 31, 2013 and 2012, the fair values of the impaired properties at the dates of impairment were $0.4 million and $2.6 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
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 '
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 '
Income and Expense Allocation
Profits and losses are allocated to shareholders and the Manager in accordance with the LLC agreement.

Distributions '
Distributions
Distributions to shareholders are allocated in proportion to the number of shares held. Certain shares have early investment incentive and advance distribution rights, as defined in the LLC Agreement, which range from approximately $6 thousand to $12 thousand per share. The Fund began making distributions to eligible early investors during the second quarter 2009.  The Fund commenced distributions to all investors in January 2013.

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 '
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.

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Organization and Summary of Significant Accounting Policies (Tables)
12 Months Ended
Dec. 31, 2013
Organization and Summary of Significant Accounting Policies [Abstract] '
Schedule of Changes in Asset Retirement Obligations '
 
   
2013
   
2012
 
   
(in thousands)
 
Balance, beginning of year
  $ 590     $ 463  
Liabilities incurred
    79       141  
Liabilities settled
    -       (20 )
Accretion expense
    16       6  
Revisions in estimated cash flows
    301       -  
Balance, end of year
  $ 986     $ 590  
   
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Oil And Gas Properties (Tables)
12 Months Ended
Dec. 31, 2013
Oil and Gas Properties [Abstract] '
Schedule of Net Changes in Unproved Oil and Gas Properties '

   
December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Balance, beginning of year
  $ -     $ 7,163  
Additions to capitalized exploratory well costs
               
  pending the determination of proved reserves
    -       -  
Reclassifications to proved properties based on
               
  the determination of proved reserves
    -       (7,163 )
Capitalized exploratory well costs charged to
               
  expense
    -       -  
Balance, end of year
  $ -     $ -  
  
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Information about Oil and Gas Producing Activities (Tables)
12 Months Ended
Dec. 31, 2013
Information about Oil and Gas Producing Activities [Abstract] '
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities '
   
   
December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Proved properties
  $ 17,427     $ 15,717  
Equipment and facilities - in progress
    277       61  
   Total oil and gas properties
    17,704       15,778  
Accumulated depletion, depreciation and amortization
    (11,942 )     (10,052 )
Oil and gas properties, net
  $ 5,762     $ 5,726  

Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development '

   
Year ended December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Exploration costs
  $ (124 )   $ 1,021  
Development costs
    1,946       859  
    $ 1,822     $ 1,880  
 
Schedule of Reserve Quantity Information '

   
December 31, 2013
   
December 31, 2012
 
   
United States
 
   
Oil (BBLS)
   
Gas (MCF)
   
Oil (BBLS)
   
Gas (MCF)
 
                         
Proved developed and undeveloped reserves:
                       
Beginning of year
    168,022       1,210,579       33,939       1,652,071  
Extensions and discoveries
    258,453       548,978       142,693       225,854  
Revisions of previous estimates (a)
    56,892       284,224       8,076       (99,696 )
Production
    (8,031 )     (424,114 )     (16,686 )     (567,650 )
End of year
    475,336       1,619,667       168,022       1,210,579  
                                 
Proved developed reserves:
                               
Beginning of year
    25,329       984,725       22,246       1,377,071  
End of year
    6,841       507,977       25,329       984,725  
                                 
Proved undeveloped reserves:
                               
Beginning of year
    142,693       225,854       11,693       275,000  
End of year (b)
    468,495       1,111,690       142,693       225,854  
 
 

 
 
(a)
Revisions of previous estimates during the years ended December 31, 2013 and 2012 were attributable to well performance.

 
(b)
At December 31, 2013, the increases in proved undeveloped reserves were due to the Marmalard Project, for which a second well was drilled during 2013.  The proved undeveloped reserves during the year ended December 31, 2012 were due to discoveries relating to the Diller and Marmalard projects.

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves '

   
December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Future cash inflows
  $ 55,970     $ 24,209  
Future production costs
    (17,281 )     (8,069 )
Future development costs
    (6,848 )     (4,585 )
Future net cash flows
    31,841       11,555  
10% annual discount for estimated timing of cash flows
    (14,494 )     (3,225 )
Standardized measure of discounted future net cash flows
  $ 17,347     $ 8,330  


Schedule of Changes in the Standardized Measure for Discounted Cash Flows '

   
Year ended December 31,
 
   
2013
   
2012
 
   
(in thousands)
 
Net change in sales and transfer prices and in production costs
 related to future production
  $ 2,364     $ (697 )
Sales and transfers of oil and gas produced during the period
    (1,983 )     (3,365 )
Net change due to extensions, discoveries, and improved recovery
    5,342       3,445  
Changes in estimated future development costs
    1,081       1,782  
Net change due to revisions in quantities estimates
    2,949       1,113  
Accretion of discount
    833       668  
Other
    (1,569 )     (1,292 )
Aggregate change in the standardized measure of discounted
 future net cash flows for the year
  $ 9,017     $ 1,654  


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Organization and Summary of Significant Accounting Policies (Narrative) (Details) (USD $)
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Organization and Summary of Significant Accounting Policies [Abstract] ' '
Maximum cash balance federally insured per financial institution $ 250,000 '
Total cash balance not insured by the FDIC 7,300,000 '
Value of held-to-maturity securities included in salvage fund ' 1,000,000
Held-to-maturity securities included in salvage fund maturity date ' Mar 1, 2013
Value of capital expenditures for oil and gas properties owed to operators 13,000 100,000
Impaired Long-Lived Assets Held and Used [Line Items] ' '
Impairment of oil and gas properties 505,000 3,114,000
Early investment incentive and advance distribution rights, minimum price per share $ 6,000 '
Early investment incentive and advance distribution rights, maximum price per share $ 12,000 '
Percentage of cash from operations allocated to shareholders 85.00% '
Percentage of cash from operations allocated to fund manager 15.00% '
Percentage of available cash from dispositions allocated to shareholders 99.00% '
Percentage of available cash from dispositions allocated to fund manager 1.00% '
Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions 85.00% '
Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions 15.00% '
Cobalt Project [Member] ' '
Impaired Long-Lived Assets Held and Used [Line Items] ' '
Impairment of oil and gas properties 505,000 '
Oil and gas properties, fair value 400,000 '
Alpha Project [Member] ' '
Impaired Long-Lived Assets Held and Used [Line Items] ' '
Impairment of oil and gas properties ' 3,114,000
Oil and gas properties, fair value ' $ 2,600,000
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Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Organization and Summary of Significant Accounting Policies [Abstract] ' '
Balance, beginning of year $ 590 $ 463
Liabilities incurred 79 141
Liabilities settled '   (20)
Accretion expense 16 6
Revisions in estimated cash flows 301 '  
Balance, end of year $ 986 $ 590
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Derivative Instruments (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Derivative Instruments [Abstract] '
Realized (losses) gains on derivative instruments $ (8)
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Oil and Gas Properties (Schedule of Net Changes in Unproved Oil and Gas Properties) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Oil and Gas Properties [Abstract] ' '
Balance, beginning of year '   $ 7,163
Additions to capitalized exploratory well costs pending the determination of proved reserves '   '  
Reclassifications to proved properties based on the determination of proved reserves '   (7,163)
Capitalized exploratory well costs charged to expense '   '  
Balance, end of year '   '  
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Oil and Gas Properties (Narrative) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] ' '
Gain on sale of oil and gas properties '   $ 20
Dry-hole costs (113) (26)
Ajax Project [Member] ' '
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] ' '
Gain on sale of oil and gas properties ' $ 20
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Related Parties (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Oct. 01, 2012
Dec. 31, 2011
Related Party Transaction [Line Items] ' ' ' '
Annual management fee percentage rate ' ' 1.00% 2.50%
Annual management fees paid to Fund Manager $ 371 $ 789 ' '
Percentage of total distributions allocated to Fund Manager 15.00% ' ' '
Distributions (1,509) (1,619) ' '
Fund Manager [Member] ' ' ' '
Related Party Transaction [Line Items] ' ' ' '
Distributions $ (226) $ (243) ' '
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Commitments and Contingencies (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Commitments and Contingencies [Abstract] '
Commitments for the drilling and development of investment properties $ 5.2
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months $ 1.5
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Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)
In Thousands, unless otherwise specified
Dec. 31, 2013
Dec. 31, 2012
Information about Oil and Gas Producing Activities [Abstract] ' '
Proved properties $ 17,427 $ 15,717
Equipment and facilities - in progress 277 61
Total oil and gas properties 17,704 15,778
Accumulated depletion, depreciation and amortization (11,942) (10,052)
Total oil and gas properties, net $ 5,762 $ 5,726
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Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Information about Oil and Gas Producing Activities [Abstract] ' '
Exploration costs $ (124) $ 1,021
Development costs 1,946 859
Total costs $ 1,822 $ 1,880
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Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)
12 Months Ended
Dec. 31, 2013
bbl
Dec. 31, 2012
bbl
Oil (BBLS) [Member] ' '
Proved developed and undeveloped reserves: ' '
Beginning of year 168,022 33,939
Extensions and discoveries 258,453 142,693
Revisions of previous estimates 56,892 [1] 8,076 [1]
Production (8,031) (16,686)
End of year 475,336 168,022
Proved developed reserves: ' '
Beginning of year 25,329 22,246
End of year 6,841 25,329
Proved undeveloped reserves: ' '
Beginning of year 142,693 [2] 11,693
End of year 468,495 [2] 142,693 [2]
Gas (MCF) [Member] ' '
Proved developed and undeveloped reserves: ' '
Beginning of year 1,210,579 1,652,071
Extensions and discoveries 548,978 225,854
Revisions of previous estimates 284,224 [1] (99,696) [1]
Production (424,114) (567,650)
End of year 1,619,667 1,210,579
Proved developed reserves: ' '
Beginning of year 984,725 1,377,071
End of year 507,977 984,725
Proved undeveloped reserves: ' '
Beginning of year 225,854 [2] 275,000
End of year 1,111,690 [2] 225,854 [2]
[1] Revisions of previous estimates during the years ended December 31, 2013 and 2012 were attributable to well performance.
[2] At December 31, 2013, the increases in proved undeveloped reserves were due to the Marmalard Project, for which a second well was drilled during 2013. The proved undeveloped reserves during the year ended December 31, 2012 were due to discoveries relating to the Diller and Marmalard projects.
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Information about Oil and Gas Producing Activities (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Information about Oil and Gas Producing Activities [Abstract] ' '
Future cash inflows $ 55,970 $ 24,209
Future production costs (17,281) (8,069)
Future development costs (6,848) (4,585)
Future net cash flows 31,841 11,555
10% annual discount for estimated timing of cash flows (14,494) (3,225)
Standardized measure of discounted future net cash flows $ 17,347 $ 8,330
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Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) (USD $)
In Thousands, unless otherwise specified
12 Months Ended
Dec. 31, 2013
Dec. 31, 2012
Information about Oil and Gas Producing Activities [Abstract] ' '
Net change in sales and transfer prices and in production costs related to future production $ 2,364 $ (697)
Sales and transfers of oil and gas produced during the period (1,983) (3,365)
Net change due to extensions, discoveries, and improved recovery 5,342 3,445
Changes in estimated future development costs 1,081 1,782
Net change due to revisions in quantities estimates 2,949 1,113
Accretion of discount 833 668
Other (1,569) (1,292)
Aggregate change in the standardized measure of discounted future net cash flows for the year $ 9,017 $ 1,654
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