Ridgewood Energy T Fund 10-K 7 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 07, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Entity Registrant Name	RIDGEWOOD ENERGY T FUND LLC
Entity Central Index Key	1,364,397
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015
Entity Filer Category	Smaller Reporting Company
Entity Units Outstanding		971.6054
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Public Float	$ 0

BALANCE SHEETS

BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 2,516	$ 7,065
Salvage fund	868
Production receivable	$ 83	$ 752
Other current assets		109
Total current assets	$ 3,467	7,926
Salvage fund	966	1,693
Other assets	263	394
Oil and gas properties:
Proved properties	53,518	54,127
Less: accumulated depletion and amortization	(40,491)	(44,750)
Total oil and gas properties, net	13,027	9,377
Total assets	17,723	19,390
Current liabilities:
Due to operators	576	1,455
Accrued expenses	231	$ 35
Asset retirement obligations	868
Total current liabilities	1,675	$ 1,490
Long-term borrowings	2,900	1,800
Asset retirement obligations	1,646	1,585
Other liabilities	127	48
Total liabilities	$ 6,348	$ 4,923
Commitments and contingencies (Note 4)
Members' capital:
Distributions	$ (8,219)	$ (8,103)
Retained earnings	6,619	6,784
Manager's total	(1,600)	(1,319)
Capital contributions (1,000 shares authorized; 971.6054 issued and outstanding)	144,529	144,529
Syndication costs	(16,990)	(16,990)
Distributions	(49,085)	(48,429)
Accumulated deficit	(65,479)	(63,324)
Shareholders' total	12,975	15,786
Total members' capital	11,375	14,467
Total liabilities and members' capital	$ 17,723	$ 19,390

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014
UNAUDITED CONDENSED BALANCE SHEETS
Shares authorized	1,000	1,000
Shares issued	971.6054	971.6054
Shares outstanding	971.6054	971.6054

STATEMENTS OF OPERATIONS

STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revenue
Oil and gas revenue	$ 2,244	$ 10,867
Expenses
Depletion and amortization	799	1,891
Impairment of oil and gas properties	418	969
Management fees to affiliate (Note 2)	1,772	1,965
Operating expenses	1,435	1,574
General and administrative expenses	147	149
Total expenses	4,571	6,548
(Loss) income from operations	(2,327)	4,319
Interest income	7	10
Net (loss) income	(2,320)	4,329
Manager Interest
Net (loss) income	(165)	1,055
Shareholder Interest
Net (loss) income	$ (2,155)	$ 3,274
Net (loss) income per share	$ (2,217)	$ 3,370

STATEMENTS OF CHANGES IN MEMBER

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Balances	$ 14,467	$ 16,853
Balances, shares	971.6054
Distributions	$ (772)	(6,715)
Net (loss) income	(2,320)	4,329
Balances	$ 11,375	$ 14,467
Balances, shares	971.6054	971.6054
# of Shares [Member]
Balances, shares	971.6054	971.6054
Distributions
Net (loss) income
Balances, shares	971.6054	971.6054
Fund Manager [Member]
Balances	$ (1,319)	$ (1,367)
Distributions	(116)	(1,007)
Net (loss) income	(165)	1,055
Balances	(1,600)	(1,319)
Shareholders [Member]
Balances	15,786	18,220
Distributions	(656)	(5,708)
Net (loss) income	(2,155)	3,274
Balances	$ 12,975	$ 15,786

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net (loss) income	$ (2,320)	$ 4,329
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities:
Depletion and amortization	799	1,891
Impairment of oil and gas properties	418	969
Accretion expense	88	29
Changes in assets and liabilities:
Decrease in production receivable	669	816
Decrease (increase) in other current assets	109	(64)
Decrease in due to operators	(243)	(324)
Increase in accrued expenses	51	3
Net cash (used in) provided by operating activities	(429)	7,649
Cash flows from investing activities
Capital expenditures for oil and gas properties	(4,307)	(3,921)
Investments in salvage fund	(141)	(384)
Net cash used in investing activities	(4,448)	(4,305)
Cash flows from financing activities
Long-term borrowings	1,100	1,800
Distributions	(772)	(6,715)
Net cash provided by (used in) financing activities	328	(4,915)
Net decrease in cash and cash equivalents	(4,549)	(1,571)
Cash and cash equivalents, beginning of year	7,065	8,636
Cash and cash equivalents, end of year	$ 2,516	7,065
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties		$ 101

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 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 2, 3 and 4. 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. Reclassifications The Fund's financial statements for prior periods include reclassifications that were made to conform to the current-year presentation. 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 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. Cash and cash equivalents 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 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. 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 acquiring debt (see Note 3. “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, 2015 and 2014, $ 0.3 0.4 0.1 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. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells' costs. Interest costs related to the Credit Agreement (see Note 3. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity and workover efforts are expensed as incurred. Insurance expense related to operating wells of $ 0.1 The aggregate prior year balance of $ 4.9 Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. At December 31, 2015 and 2014, amounts recorded in due to operators totaling $ 0.1 0.7 Advances to Operators for Working Interests and Expenditures The Fund may be required to advance its share of the estimated succeeding month's expenditures to the operator for its oil and gas properties. The Fund accounts for such payments as advances to operators for working interests and expenditures. As the costs are incurred, the advances are reclassified to proved properties. Asset Retirement Obligations For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. 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, 2015 and 2014. 2015 2014 (in thousands) Balance, beginning of year $ 1,585 $ 1,556 Liabilities incurred 404 - Accretion expense 88 29 Revisions in estimated cash flows 437 - Balance, end of year $ 2,514 $ 1,585 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. Impairment of Long-Lived Assets The Fund reviews the value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund's estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. Significant declines in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund's oil and gas properties. During the year ended December 31, 2015, the Fund recorded impairments of oil and gas properties of $ 0.4 0.1 1.0 Depletion and Amortization Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. During the year ended December 31, 2015, the Fund recorded $ 0.3 Income Taxes No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund's income or loss is passed through and included in the tax returns of the Fund's shareholders. The Fund files U.S. Federal and State tax returns and the 2012 through 2014 tax returns remain open for examination by tax authorities. Income and Expense Allocation Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. Distributions Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85 15 Available cash from dispositions, as defined in the LLC Agreement, will be paid 99 1 85 15 Recent Accounting Pronouncements In April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs in the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset. Amortization of debt issuance costs will continue to be reported as interest expense. Debt issuance costs related to revolving credit arrangements, however, will continue to be presented as an asset and amortized ratably over the term of the arrangement. In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset. These pronouncements are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. The Fund is currently evaluating the impact that the adoption of these pronouncements will have on its financial statements.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Parties	2. Related Parties Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5 1.8 2.0 The Manager is entitled to receive a 15 0.1 1.0 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.

Credit Agreement - Beta Project

Credit Agreement - Beta Project Financing	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Credit Agreement - Beta Project Financing	3. 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. Certain other funds managed by Ridgewood (“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. The Fund anticipates it will borrow approximately $ 8.8 8 1.25 4.5 December 31, 2020 2.9 1.8 0.3 48 As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders. The Credit Agreement contains customary covenants, for which the Fund believes it was in compliance at December 31, 2015 and 2014.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	4. Commitments and Contingencies Capital Commitments The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2015, the Fund had 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. As of December 31, 2015, the Fund's estimated capital commitments related to its oil and gas properties were $ 8.2 3.1 0.1 4.5 4.6 Based upon its current cash position, its current reserve estimates and its current development plan of the Beta Project, the Fund expects cash flow from operations and borrowings to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund's capital requirements, the Manager will take action, which may include adjusting its management fee temporarily to accommodate the Fund's short-term capital requirements. 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, 2015 and 2014, there were no known environmental contingencies that required the Fund to record a liability. During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund's business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund's operations. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund's business. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund's operating results and cash flows. 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.

Information about Oil and Gas P

Information about Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2015
Information About Oil And Gas Producing Activities [Abstract]
Information about Oil and Gas Producing Activities	Ridgewood Energy T Fund, LLC Supplementary Financial Information Information about Oil and Gas Producing Activities – Unaudited In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are 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, 2015 2014 (in thousands) Proved properties $ 53,518 $ 54,127 Total oil and gas properties (a) 53,518 54,127 Accumulated depletion and amortization (40,491 ) (44,750 ) Oil and gas properties, net $ 13,027 $ 9,377 (a) Capitalized costs related to oil and gas producing activities as of December 31, 2014 includes a reclassification that was made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification. Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2015 2014 (in thousands) Exploration costs $ 4 $ - Development costs 4,735 4,053 $ 4,739 $ 4,053 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, 2015 and 2014. 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, 2015 December 31, 2014 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Oil (BBLS) NGL (BBLS) Gas (MCF) Proved developed and undeveloped reserves: Beginning of year 330,155 27,404 865,624 351,777 160,708 6,726,123 Revisions of previous estimates (a) (8,872 ) (3,861 ) 59,662 16,977 (87,970 ) (4,395,482 ) Production (16,066 ) (16,801 ) (546,603 ) (38,599 ) (45,334 ) (1,465,017 ) End of year 305,217 6,742 378,683 330,155 27,404 865,624 Proved developed reserves: Beginning of year 51,170 27,404 656,384 73,333 59,542 1,992,528 End of year 27,661 6,742 170,516 51,170 27,404 656,384 Proved undeveloped reserves: Beginning of year 278,985 - 209,240 278,444 101,166 4,733,595 End of year (a) 277,556 - 208,167 278,985 - 209,240 (a) Revisions of previous estimates during the year ended December 31, 2015 were attributable to the Carrera Project and to well performance. During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 22 2 27 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, 2015 2014 (in thousands) Future cash inflows $ 14,876 $ 33,800 Future production costs (2,512 ) (4,010 ) Future development costs (7,516 ) (9,631 ) Future net cash flows 4,848 20,159 10% annual discount for estimated timing of cash flows (1,426 ) (5,296 ) Standardized measure of discounted future net cash flows $ 3,422 $ 14,863 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, 2015 2014 (in thousands) Net change in sales and transfer prices and in production costs related to future production $ (12,092 ) $ 13,321 Sales and transfers of oil and gas produced during the period (a) (952 ) (9,713 ) Changes in estimated future development costs 2,115 7,368 Net change due to revisions in quantities estimates (65 ) (35,169 ) Accretion of discount 1,486 2,677 Other (a) (1,933 ) 9,608 Aggregate change in the standardized measure of discounted future net cash flows for the year $ (11,441 ) $ (11,908 ) (a) Changes in the standardized measure for discounted cash flows for the year ended December 31, 2014 includes an insurance expense reclassification that was made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the heading and “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification. 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.

Organization and Summary of S12

Organization and Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
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.
Reclassifications	Reclassifications The Fund's financial statements for prior periods include reclassifications that were made to conform to the current-year presentation.
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 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. Cash and cash equivalents 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
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. 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 Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 3. “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, 2015 and 2014, $ 0.3 0.4 0.1
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. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells' costs. Interest costs related to the Credit Agreement (see Note 3. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity and workover efforts are expensed as incurred. Insurance expense related to operating wells of $ 0.1 The aggregate prior year balance of $ 4.9 Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. At December 31, 2015 and 2014, amounts recorded in due to operators totaling $ 0.1 0.7
Advances to Operators for Working Interests and Expenditures	Advances to Operators for Working Interests and Expenditures The Fund may be required to advance its share of the estimated succeeding month's expenditures to the operator for its oil and gas properties. The Fund accounts for such payments as advances to operators for working interests and expenditures. As the costs are incurred, the advances are reclassified to 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, 2015 and 2014. 2015 2014 (in thousands) Balance, beginning of year $ 1,585 $ 1,556 Liabilities incurred 404 - Accretion expense 88 29 Revisions in estimated cash flows 437 - Balance, end of year $ 2,514 $ 1,585 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.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The Fund reviews the value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund's estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. Significant declines in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund's oil and gas properties. During the year ended December 31, 2015, the Fund recorded impairments of oil and gas properties of $ 0.4 0.1 1.0
Depletion and Amortization	Depletion and Amortization Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. During the year ended December 31, 2015, the Fund recorded $ 0.3
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. The Fund files U.S. Federal and State tax returns and the 2012 through 2014 tax returns remain open for examination by tax authorities.
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. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85 15 Available cash from dispositions, as defined in the LLC Agreement, will be paid 99 1 85 15
Recent Accounting Pronouncements	Recent Accounting Pronouncements In April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs in the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset. Amortization of debt issuance costs will continue to be reported as interest expense. Debt issuance costs related to revolving credit arrangements, however, will continue to be presented as an asset and amortized ratably over the term of the arrangement. In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset. These pronouncements are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. The Fund is currently evaluating the impact that the adoption of these pronouncements will have on its financial statements.

Organization and Summary of S13

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Organization and Summary of Significant Accounting Policies [Abstract]
Schedule of Changes in Asset Retirement Obligations	2015 2014 (in thousands) Balance, beginning of year $ 1,585 $ 1,556 Liabilities incurred 404 - Accretion expense 88 29 Revisions in estimated cash flows 437 - Balance, end of year $ 2,514 $ 1,585

Information about Oil and Gas14

Information about Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Information About Oil And Gas Producing Activities [Abstract]
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities	Table I - Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2015 2014 (in thousands) Proved properties $ 53,518 $ 54,127 Total oil and gas properties (a) 53,518 54,127 Accumulated depletion and amortization (40,491 ) (44,750 ) Oil and gas properties, net $ 13,027 $ 9,377 (a) Capitalized costs related to oil and gas producing activities as of December 31, 2014 includes a reclassification that was made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development	Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2015 2014 (in thousands) Exploration costs $ 4 $ - Development costs 4,735 4,053 $ 4,739 $ 4,053
Schedule of Reserve Quantity Information	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, 2015 and 2014. 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, 2015 December 31, 2014 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Oil (BBLS) NGL (BBLS) Gas (MCF) Proved developed and undeveloped reserves: Beginning of year 330,155 27,404 865,624 351,777 160,708 6,726,123 Revisions of previous estimates (a) (8,872 ) (3,861 ) 59,662 16,977 (87,970 ) (4,395,482 ) Production (16,066 ) (16,801 ) (546,603 ) (38,599 ) (45,334 ) (1,465,017 ) End of year 305,217 6,742 378,683 330,155 27,404 865,624 Proved developed reserves: Beginning of year 51,170 27,404 656,384 73,333 59,542 1,992,528 End of year 27,661 6,742 170,516 51,170 27,404 656,384 Proved undeveloped reserves: Beginning of year 278,985 - 209,240 278,444 101,166 4,733,595 End of year (a) 277,556 - 208,167 278,985 - 209,240 (a) Revisions of previous estimates during the year ended December 31, 2015 were attributable to the Carrera Project and to well performance. During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 22 2 27
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves	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, 2015 2014 (in thousands) Future cash inflows $ 14,876 $ 33,800 Future production costs (2,512 ) (4,010 ) Future development costs (7,516 ) (9,631 ) Future net cash flows 4,848 20,159 10% annual discount for estimated timing of cash flows (1,426 ) (5,296 ) Standardized measure of discounted future net cash flows $ 3,422 $ 14,863
Schedule of Changes in the Standardized Measure for Discounted Cash Flows	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, 2015 2014 (in thousands) Net change in sales and transfer prices and in production costs related to future production $ (12,092 ) $ 13,321 Sales and transfers of oil and gas produced during the period (a) (952 ) (9,713 ) Changes in estimated future development costs 2,115 7,368 Net change due to revisions in quantities estimates (65 ) (35,169 ) Accretion of discount 1,486 2,677 Other (a) (1,933 ) 9,608 Aggregate change in the standardized measure of discounted future net cash flows for the year $ (11,441 ) $ (11,908 ) (a) Changes in the standardized measure for discounted cash flows for the year ended December 31, 2014 includes an insurance expense reclassification that was made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the heading and “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.

Organization and Summary of S15

Organization and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Organization and Summary of Significant Accounting Policies [Abstract]
Maximum cash balance federally insured per financial institution	$ 250
Unamortized debt discounts and deferred financing costs	300	$ 400
Amortization of financing costs	100	100
Reclassification of general and administrative expenses	100
Reclassification of equipment and facilities in progress	4,900
Value of capital expenditures for oil and gas properties owed to operators	100	700
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and gas properties	418	969
Depletion	$ 300
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%
Eugene Island 346/347 and Cobalt Project [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and gas properties	$ 400
Oil and gas properties, fair value	$ 100
Carrera Project [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and gas properties		$ 1,000

Organization and Summary of S16

Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Organization and Summary of Significant Accounting Policies [Abstract]
Balance, beginning of year	$ 1,585	$ 1,556
Liabilities incurred	404
Accretion expense	88	$ 29
Revisions in estimated cash flows	437
Balance, end of year	$ 2,514	$ 1,585

Related Parties (Details)

Related Parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Annual management fee percentage rate	2.50%
Annual management fees paid to Fund Manager	$ 1,772	$ 1,965
Percentage of total distributions allocated to Fund Manager	15.00%
Distributions	$ (772)	(6,715)
Fund Manager [Member]
Related Party Transaction [Line Items]
Distributions	$ 100	$ 1,000

Credit Agreement - Beta Proje18

Credit Agreement - Beta Project Financing (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Credit agreement, maximum borrowing capacity	$ 8,800
Credit agreement, interest rate	8.00%
Credit agreement, contingency repayment rate, first seven months of production	1.25%
Credit agreement, contingency repayment rate, after first seven months of production	4.50%
Credit agreement, maturity date	Dec. 31, 2020
Long-term borrowings	$ 2,900	$ 1,800
Capitalized interest	$ 300	$ 48

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitments for the drilling and development of investment properties	$ 8.2
Commitments for asset retirement obligations included in estimated capital commitments	3.1
Commitments for projected interest costs included in estimated capital commitments	0.1
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months	4.5
Commitments for the drilling and development of investment properties in excess of working capital	$ 4.6

Information about Oil and Gas20

Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]
Proved properties		$ 53,518	$ 54,127
Total oil and gas properties	[1]	53,518	54,127
Accumulated depletion and amortization		(40,491)	(44,750)
Total oil and gas properties, net		$ 13,027	$ 9,377
[1]	Capitalized costs related to oil and gas producing activities as of December 31, 2014 includes a reclassification that was made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.

Information about Oil and Gas21

Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]
Exploration costs	$ 4
Development costs	4,735	$ 4,053
Total costs	$ 4,739	$ 4,053

Information about Oil and Gas22

Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)		12 Months Ended
		Dec. 31, 2015bblMcf		Dec. 31, 2014bblMcf	Jan. 31, 2015bblMcf
Oil (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year		330,155		351,777
Revisions of previous estimates	[1]	(8,872)		16,977
Production		(16,066)		(38,599)
End of year		305,217		330,155
Reserves not recovered					22,000
Proved developed reserves:
Beginning of year		51,170		73,333
End of year		27,661		51,170
Proved undeveloped reserves:
Beginning of year		278,985	[1]	278,444
End of year	[1]	277,556		278,985
NGL (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year		27,404		160,708
Revisions of previous estimates	[1]	(3,861)		(87,970)
Production		(16,801)		(45,334)
End of year		6,742		27,404
Reserves not recovered					2,000
Proved developed reserves:
Beginning of year		27,404		59,542
End of year		6,742		27,404
Proved undeveloped reserves:
Beginning of year			[1]	101,166
End of year	[1]
Gas (MCF) [Member]
Proved developed and undeveloped reserves:
Beginning of year | Mcf		865,624		6,726,123
Revisions of previous estimates | Mcf	[1]	59,662		(4,395,482)
Production | Mcf		(546,603)		(1,465,017)
End of year | Mcf		378,683		865,624
Reserves not recovered | Mcf					27,000
Proved developed reserves:
Beginning of year | Mcf		656,384		1,992,528
End of year | Mcf		170,516		656,384
Proved undeveloped reserves:
Beginning of year | Mcf		209,240	[1]	4,733,595
End of year | Mcf	[1]	208,167		209,240
[1]	Revisions of previous estimates during the year ended December 31, 2015 were attributable to the Carrera Project and to well performance. During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 22 thousand barrels of oil, 2 thousand barrels of NGL's, and 27 thousand mcf's of gas, related to the Carrera Project, which are included in the above table as of December 31, 2014, were not recovered. During the year ended December 31, 2014, revisions of previous estimates were attributable to well performance and to a decrease in proved undeveloped reserves related to West Cameron 75, which as a result of an increase to the estimated costs to develop these reserves coupled with prevailing oil and gas prices, the Fund has elected not to develop these reserves. Such decreases were offset by increases in reserve estimates for the Beta Project.

Information about Oil and Gas23

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	Dec. 31, 2015	Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]
Future cash inflows	$ 14,876	$ 33,800
Future production costs	(2,512)	(4,010)
Future development costs	(7,516)	(9,631)
Future net cash flows	4,848	20,159
10% annual discount for estimated timing of cash flows	(1,426)	(5,296)
Standardized measure of discounted future net cash flows	$ 3,422	$ 14,863

Information about Oil and Gas24

Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]
Net change in sales and transfer prices and in production costs related to future production		$ (12,092)	$ 13,321
Sales and transfers of oil and gas produced during the period	[1]	(952)	(9,713)
Changes in estimated future development costs		2,115	7,368
Net change due to revisions in quantities estimates		(65)	(35,169)
Accretion of discount		1,486	2,677
Other	[1]	(1,933)	9,608
Aggregate change in the standardized measure of discounted future net cash flows for the year		$ (11,441)	$ (11,908)
[1]	Changes in the standardized measure for discounted cash flows for the year ended December 31, 2014 includes an insurance expense reclassification that was made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the heading and “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.