Ridgewood Energy P Fund 10-K 24 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 24, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Entity Registrant Name	Ridgewood Energy P Fund LLC
Entity Central Index Key	1325703
Current Fiscal Year End Date	-19
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014
Entity Filer Category	Smaller Reporting Company
Entity Units Outstanding		933.06
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Public Float	$0

BALANCE_SHEETS

BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,803	$894
Production receivable	174	267
Asset held for sale		317
Other current assets	20	35
Total current assets	1,997	1,513
Salvage fund	1,438	1,328
Oil and gas properties:
Advances to operators for working interests and expenditures		84
Proved properties	22,527	22,434
Less: accumulated depletion and amortization	-20,763	-19,086
Total oil and gas properties, net	1,764	3,432
Total assets	5,199	6,273
Current liabilities:
Due to operators	241	423
Accrued expenses	35	41
Liability held for sale		171
Total current liabilities	276	635
Asset retirement obligations	1,316	1,292
Total liabilities	1,592	1,927
Commitments and contingencies (Note 4)
Members' capital:
Distributions	-6,734	-6,417
Retained earnings	4,206	3,951
Manager's total	-2,528	-2,466
Capital contributions (1,335 shares authorized; 933.06 issued and outstanding)	138,344	138,344
Syndication costs	-15,898	-15,898
Distributions	-39,397	-36,368
Accumulated deficit	-76,914	-79,266
Shareholders' total	6,135	6,812
Total members' capital	3,607	4,346
Total liabilities and members' capital	$5,199	$6,273

BALANCE_SHEETS_Parenthetical

BALANCE SHEETS (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
BALANCE SHEETS [Abstract]
Shares authorized	1,335	1,335
Shares issued	933.06	933.06
Shares outstanding	933.06	933.06

STATEMENTS_OF_OPERATIONS

STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Revenue
Oil and gas revenue	$3,242	$5,891
Expenses
Depletion and amortization	793	1,876
Dry-hole costs	20	587
Impairment of oil and gas properties	807
Management fees to affiliate (Note 3)	272	1,203
Operating expenses	735	995
Workover expense	387	510
General and administrative expenses	230	248
Total expenses	3,244	5,419
Gain on sale of oil and gas properties	2,599
Income from operations	2,597	472
Interest income	10	16
Net income	2,607	488
Manager Interest
Net income	255	418
Shareholder Interest
Net income	$2,352	$70
Net income per share	$2,520	$76

STATEMENTS_OF_CHANGES_IN_MEMBE

STATEMENTS OF CHANGES IN MEMBERS' CAPITAL (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Balances	$4,346	$7,770
Balances, shares	933.06
Distributions	-3,346	-3,912
Net income	2,607	488
Balances	3,607	4,346
Balances, shares	933.06	933.06
# of Shares [Member]
Balances, shares	933.06	933.06
Distributions
Net income
Balances, shares	933.06	933.06
Fund Manager [Member]
Balances	-2,466	-2,297
Distributions	-317	-587
Net income	255	418
Balances	-2,528	-2,466
Shareholders [Member]
Balances	6,812	10,067
Distributions	-3,029	-3,325
Net income	2,352	70
Balances	$6,135	$6,812

STATEMENTS_OF_CASH_FLOWS

STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net income	$2,607	$488
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and amortization	793	1,876
Gain on sale of oil and gas properties	-2,599
Dry-hole costs	20	587
Impairment of oil and gas properties	807
Accretion expense	24	12
Changes in assets and liabilities:
Decrease in production receivable	93	620
Decrease in other current assets	13	33
(Decrease) increase in due to operators	-192	233
Decrease in accrued expenses	-6
Settlements of asset retirement obligations		-1,549
Net cash provided by operating activities	1,560	2,300
Cash flows from investing activities
Payments to operators for working interests and expenditures		-84
Proceeds from sale of oil and gas properties	2,745
Credits (expenditures) for capital investment properties	60	-800
(Investments in) proceeds from salvage fund, net	-110	865
Net cash provided by (used in) investing activities	2,695	-19
Cash flows from financing activities
Distributions	-3,346	-3,912
Net cash used in financing activities	-3,346	-3,912
Net increase (decrease) in cash and cash equivalents	909	-1,631
Cash and cash equivalents, beginning of year	894	2,525
Cash and cash equivalents, end of year	1,803	894
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to proved properties	$84

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 P Fund, LLC (the "Fund”), a Delaware limited liability company, was formed on March 21, 2005 and operates pursuant to a limited liability company agreement (the “LLC Agreement") dated as of May 16, 2005 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 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.
	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 approximate fair value based on Level 1 inputs. Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.
	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, 2014, the Fund's bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
	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, 2014 and 2013, the Fund had investments in federal agency mortgage-backed securities within its salvage fund that are classified as available-for-sale of $0.2 million and $0.3 million, respectively, which mature in January 2042. Available-for-sale securities are carried in the financial statements at fair value.  Available-for-sale securities are carried in the financial statements at fair value.  At December 31, 2014 and 2013, there was no unrealized gain or loss related to the Fund's available-for-sale investments.
	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. Exploratory costs 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. Dry-hole costs during the years ended December 31, 2014 and 2013 related to the wells that were determined to be dry holes in prior years. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells' costs.
	Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity and workover efforts are expensed as incurred.  Workover expense during the years ended December 31, 2014 and 2013 related to Eugene Island 354 and the Liberty and Carrera projects.
	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, 2014 and 2013, amounts recorded in due to operators totaling $30 thousand and $20 thousand, respectively, related to capital expenditures for oil and gas properties.
	Advances to Operators for Working Interests and Expenditures
	The Fund's acquisition of a working interest in an oil and gas property 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, 2014 and 2013.
		2014		2013
		(in thousands)
	Balance, beginning of year	$	1,292	$	1,986
	Liabilities relieved/settled		-		(1,720	)
	Accretion expense		24		12
	Revisions in estimated cash flows		-		1,014
	Balance, end of year	$	1,316	$	1,292
	At December 31, 2013, the Fund's balance sheet reflects the reclassification of the Raven Project's asset retirement obligation from “Asset retirement obligation” to “Liability held for sale”. On January 17, 2014, the Fund entered into an agreement to sell its interest in the Raven Project to a third party. See Note 2. “Oil and Gas Properties” for additional information related to the transaction.
	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 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 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 and the well was fully impaired.  Accordingly, during the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.8 million, representing the remaining net book value of the well at the date of impairment.  There were no impairments of oil and gas properties during the year ended December 31, 2013.
	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.
	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 2010 through 2013 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% 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.  During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $1.3 million. There were no such distributions during the year ended December 31, 2013.
	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.

Oil_and_Gas_Properties

Oil and Gas Properties	12 Months Ended
	Dec. 31, 2014
Oil and Gas Properties [Abstract]
Oil and Gas Properties	2.  Oil and Gas Properties
	On January 17, 2014, the Fund, along with its affiliates, Ridgewood Energy Gulf of Mexico Oil and Gas Fund, L.P., Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy W Fund, LLC, and Ridgewood Energy Y Fund, LLC, (when used with the Fund the “Ridgewood Funds”) entered into a purchase and sale agreement to sell the Ridgewood Funds' interests in the Raven Project, located in the state waters of Louisiana, to Castex Energy Partners, L.P. for cash consideration totaling $21.7 million. The closing of the sale transaction occurred on January 30, 2014.
	The Fund had a 6.25% working interest in the Raven Project and received $2.7 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.1 million, thereby resulting in a gain to the Fund of $2.6 million, which was recognized during the year ended December 31, 2014. There was no such amount recorded during the year ended December 31, 2013.
	At December 31, 2013, the Fund's balance sheet reflected the Raven Project's cost and accumulated depletion classified as “Asset held for sale”, which totaled $0.3 million, and the Raven Project's asset retirement obligation classified as “Liability held for sale”, which totaled $0.2 million. Such asset was monetized and obligation was relieved upon the closing of the Raven Project's sale.

Related_Parties

Related Parties	12 Months Ended
	Dec. 31, 2014
Related Parties [Abstract]
Related Parties	3.  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 entitled to an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees for the years ended December 31, 2014 and 2013 were $0.3 million and $1.2 million, respectively.   Effective April 1, 2014, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs related to services provided by the Manager for accounting and investor relations.
	The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2014 and 2013 were $0.3 million and $0.6 million, respectively.  In addition, the Manager is entitled to receive a 1% interest in cash distributions from dispositions.  Distributions from the sale of the Raven project paid to the Manager during the year ended December 31, 2014 were $13 thousand. There were no such distributions during the year ended December 31, 2013.
	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.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies [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, 2014, the Fund's estimated capital commitments related to its oil and gas properties were $2.6 million (which include asset retirement obligations for the Fund's projects of $1.4 million), none of which is expected to be spent during the year ending December 31, 2015.
	Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations 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.
	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, 2014 and 2013, 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_

Information about Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]
Information about Oil and Gas Producing Activities	Ridgewood Energy P 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,
			2014			2013
			(in thousands)
	Advances to operators for working interests and expenditures		$	-		$	84
	Proved properties			22,527			22,434
	Total oil and gas properties			22,527			22,518
	Accumulated depletion and amortization			(20,763	)		(19,086	)
	Oil and gas properties, net		$	1,764		$	3,432
	Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
			Year ended December 31,
			2014			2013
			(in thousands)
	Exploration costs		$	1		$	50
	Development costs			(49	)		1,207
			$	(48	)	$	1,257
	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, 2014 and 2013.  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.
			31-Dec-14									31-Dec-13
			United States
			Oil (BBLS)			NGL (BBLS)			Gas (MCF)			Oil (BBLS)			NGL (BBLS)			Gas (MCF)
	Proved developed and undeveloped reserves:
	Beginning of year			105,086			56,674			1,752,564			126,408			-			2,158,720
	Sales of minerals in place (a)			(10,053	)		(38,442	)		(1,468,384	)		-			-			-
	Revisions of previous estimates (b)			14,535			1,819			59,246			14,976			71,735			29,900
	Production			(31,362	)		(3,596	)		(86,541	)		(36,298	)		(15,061	)		(436,056	)
	End of year (c)			78,206			16,455			256,885			105,086			56,674			1,752,564
	Proved developed reserves:
	Beginning of year			96,164			24,131			505,077			118,717			-			1,045,040
	End of year			78,206			16,455			256,885			96,164			24,131			505,077
	Proved undeveloped reserves:
	Beginning of year			8,922			32,543			1,247,487			7,691			-			1,113,680
	End of year (d)			-			-			-			8,922			32,543			1,247,487
	(a)	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 6 thousand barrels and 33 thousand barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.2 million mcf and 1.2 million mcf, respectively.
	(b)	Revisions of previous estimates were attributable to well performance.
	(c)	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 19 thousand barrels of oil, 2 thousand barrels of NGL's, and 22 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered.
	(d)	At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.
	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,
			2014			2013
			(in thousands)
	Future cash inflows		$	9,014		$	18,635
	Future production costs			(2,798	)		(3,658	)
	Future development costs			(2,643	)		(4,923	)
	Future ad valorem taxes			-			(150	)
	Future net cash flows (a) (b)			3,573			9,904
	10% annual discount for estimated timing of cash flows			(445	)		(2,082	)
	Standardized measure of discounted future net cash flows (a) (b)		$	3,128		$	7,822
	(a)	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $4.3 million and $3.1 million, respectively.
	(b)	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, undiscounted and discounted cash flows at December 31, 2014 of approximately $0.8 million, related to the Carrera Project, are not expected to be realized.
	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,
			2014			2013
			(in thousands)
	Net change in sales and transfer prices and in production costs		$	(978	)	$	(214	)
	related to future production
	Sales and transfers of oil and gas produced during the period			(2,531	)		(4,907	)
	Net change due to purchases and sales of minerals in place (a)			(3,132	)		-
Changes in estimated future development costs			417			(637	)
Net change due to revisions in quantities estimates			1,038			2,387
Accretion of discount			782			1,055
Other			(290	)		(416	)
Aggregate change in the standardized measure of discounted		$	(4,694	)	$	(2,732	)
future net cash flows for the year (b)
(a)	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $3.1 million.
(b)	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.  See additional information in the Tables III and IV.
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_Si1

Organization and Summary of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
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 approximate fair value based on Level 1 inputs. Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.
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, 2014, the Fund's bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
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, 2014 and 2013, the Fund had investments in federal agency mortgage-backed securities within its salvage fund that are classified as available-for-sale of $0.2 million and $0.3 million, respectively, which mature in January 2042. Available-for-sale securities are carried in the financial statements at fair value.  Available-for-sale securities are carried in the financial statements at fair value.  At December 31, 2014 and 2013, there was no unrealized gain or loss related to the Fund's available-for-sale investments.
	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. Exploratory costs 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. Dry-hole costs during the years ended December 31, 2014 and 2013 related to the wells that were determined to be dry holes in prior years. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells' costs.
	Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity and workover efforts are expensed as incurred.  Workover expense during the years ended December 31, 2014 and 2013 related to Eugene Island 354 and the Liberty and Carrera projects.
	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, 2014 and 2013, amounts recorded in due to operators totaling $30 thousand and $20 thousand, 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 an oil and gas property 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, 2014 and 2013.
		2014		2013
		(in thousands)
	Balance, beginning of year	$	1,292	$	1,986
	Liabilities relieved/settled		-		(1,720	)
	Accretion expense		24		12
	Revisions in estimated cash flows		-		1,014
	Balance, end of year	$	1,316	$	1,292
	At December 31, 2013, the Fund's balance sheet reflects the reclassification of the Raven Project's asset retirement obligation from “Asset retirement obligation” to “Liability held for sale”. On January 17, 2014, the Fund entered into an agreement to sell its interest in the Raven Project to a third party. See Note 2. “Oil and Gas Properties” for additional information related to the transaction.
	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 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 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 and the well was fully impaired.  Accordingly, during the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.8 million, representing the remaining net book value of the well at the date of impairment.  There were no impairments of oil and gas properties during the year ended December 31, 2013.
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.
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 2010 through 2013 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% 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.  During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $1.3 million. There were no such distributions during the year ended December 31, 2013.
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.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Organization and Summary of Significant Accounting Policies [Abstract]
Schedule of Changes in Asset Retirement Obligations
		2014		2013
		(in thousands)
	Balance, beginning of year	$	1,292	$	1,986
	Liabilities relieved/settled		-		(1,720	)
	Accretion expense		24		12
	Revisions in estimated cash flows		-		1,014
	Balance, end of year	$	1,316	$	1,292

Information_about_Oil_and_Gas_1

Information about Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2014
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,
			2014			2013
			(in thousands)
	Advances to operators for working interests and expenditures		$	-		$	84
	Proved properties			22,527			22,434
	Total oil and gas properties			22,527			22,518
	Accumulated depletion and amortization			(20,763	)		(19,086	)
	Oil and gas properties, net		$	1,764		$	3,432
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,
			2014			2013
			(in thousands)
	Exploration costs		$	1		$	50
	Development costs			(49	)		1,207
			$	(48	)	$	1,257
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, 2014 and 2013.  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.
			31-Dec-14									31-Dec-13
			United States
			Oil (BBLS)			NGL (BBLS)			Gas (MCF)			Oil (BBLS)			NGL (BBLS)			Gas (MCF)
	Proved developed and undeveloped reserves:
	Beginning of year			105,086			56,674			1,752,564			126,408			-			2,158,720
	Sales of minerals in place (a)			(10,053	)		(38,442	)		(1,468,384	)		-			-			-
	Revisions of previous estimates (b)			14,535			1,819			59,246			14,976			71,735			29,900
	Production			(31,362	)		(3,596	)		(86,541	)		(36,298	)		(15,061	)		(436,056	)
	End of year (c)			78,206			16,455			256,885			105,086			56,674			1,752,564
	Proved developed reserves:
	Beginning of year			96,164			24,131			505,077			118,717			-			1,045,040
	End of year			78,206			16,455			256,885			96,164			24,131			505,077
	Proved undeveloped reserves:
	Beginning of year			8,922			32,543			1,247,487			7,691			-			1,113,680
	End of year (d)			-			-			-			8,922			32,543			1,247,487
	(a)	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 6 thousand barrels and 33 thousand barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.2 million mcf and 1.2 million mcf, respectively.
	(b)	Revisions of previous estimates were attributable to well performance.
	(c)	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 19 thousand barrels of oil, 2 thousand barrels of NGL's, and 22 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered.
	(d)	At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.
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,
			2014			2013
			(in thousands)
	Future cash inflows		$	9,014		$	18,635
	Future production costs			(2,798	)		(3,658	)
	Future development costs			(2,643	)		(4,923	)
	Future ad valorem taxes			-			(150	)
	Future net cash flows (a) (b)			3,573			9,904
	10% annual discount for estimated timing of cash flows			(445	)		(2,082	)
	Standardized measure of discounted future net cash flows (a) (b)		$	3,128		$	7,822
	(a)	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $4.3 million and $3.1 million, respectively.
	(b)	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, undiscounted and discounted cash flows at December 31, 2014 of approximately $0.8 million, related to the Carrera Project, are not expected to be realized.
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,
			2014			2013
			(in thousands)
	Net change in sales and transfer prices and in production costs		$	(978	)	$	(214	)
	related to future production
	Sales and transfers of oil and gas produced during the period			(2,531	)		(4,907	)
	Net change due to purchases and sales of minerals in place (a)			(3,132	)		-
	Changes in estimated future development costs			417			(637	)
	Net change due to revisions in quantities estimates			1,038			2,387
	Accretion of discount			782			1,055
	Other			(290	)		(416	)
	Aggregate change in the standardized measure of discounted		$	(4,694	)	$	(2,732	)
	future net cash flows for the year (b)
	(a)	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $3.1 million.
	(b)	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.  See additional information in the Tables III and IV.

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Organization and Summary of Significant Accounting Policies [Abstract]
Maximum cash balance insured by the FDIC, per financial institution	$250,000
Value of available-for-sale securities included in salvage fund	200,000	300,000
Available-for-sale securities included in salvage fund maturity date	1-Jan-42	1-Jan-42
Value of capital expenditures for oil and gas properties owed to operators	30,000	20,000
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and gas properties	807,000
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 the Fund manager	1.00%
Percentage of available cash from dispositions allocated to shareholders after shareholders have received distributions equal to their capital contributions	85.00%
Percentage of available cash from dispositions allocated to the Fund manager after shareholders have received distributions equal to their capital contributions	15.00%
Distributions related to Raven Project	1,300,000
Carrera Project [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and gas properties	$800,000

Organization_and_Summary_of_Si4

Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Organization and Summary of Significant Accounting Policies [Abstract]
Balance, beginning of year	$1,292	$1,986
Liabilities relieved/settled		-1,720
Accretion expense	24	12
Revisions in estimated cash flows		1,014
Balance, end of year	$1,316	$1,292

Oil_and_Gas_Properties_Details

Oil and Gas Properties (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Properties [Abstract]
Cash consideration	$21,700,000
Working interest percentage	6.25%
Proceeds from sale of oil and gas properties	2,745,000
Carrying value of oil and gas properties at date of sale	100,000
Gain on sale of oil and gas properties	2,599,000
Asset held for sale		317,000
Liability held for sale		$171,000

Related_Parties_Details

Related Parties (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Annual management fee percentage rate	2.50%
Annual management fees paid to Fund Manager	$272	$1,203
Percentage of total distributions allocated to Fund Manager	15.00%
Distributions	-3,346	-3,912
Fund Manager [Member]
Related Party Transaction [Line Items]
Distributions	-300	-600
Fund Manager [Member] | Raven Project [Member]
Related Party Transaction [Line Items]
Percentage of total distributions allocated to Fund Manager	1.00%
Distributions	($13)

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Commitments and Contingencies [Abstract]
Commitments for the drilling and development of investment properties	$2.60
Commitments for asset retirement obligations included in estimated capital commitments	$1.40

Information_about_Oil_and_Gas_2

Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Information About Oil And Gas Producing Activities [Abstract]
Advances to operators for working interests and expenditures		$84
Proved properties	22,527	22,434
Total oil and gas properties	22,527	22,518
Accumulated depletion and amortization	-20,763	-19,086
Total oil and gas properties, net	$1,764	$3,432

Information_about_Oil_and_Gas_3

Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Information About Oil And Gas Producing Activities [Abstract]
Exploration costs	$1	$50
Development costs	-49	1,207
Total costs	($48)	$1,257

Information_about_Oil_and_Gas_4

Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Jan. 31, 2015	Jan. 17, 2014
	bbl		bbl		bbl	bbl
Oil (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year	105,086	[1]	126,408
Sales of minerals in place	-10,053	[2]		[2]
Revisions of previous estimates	14,535	[3]	14,976	[3]
Production	-31,362		-36,298
End of year	78,206	[1]	105,086	[1]
Reserves not expected to be recovered					19,000
Proved developed reserves:
Beginning of year	96,164		118,717			1,000
End of year	78,206		96,164			1,000
Proved undeveloped reserves:
Beginning of year	8,922	[4]	7,691			9,000
End of year		[4]	8,922	[4]		9,000
NGL (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year	56,674	[1]
Sales of minerals in place	-38,442	[2]		[2]
Revisions of previous estimates	1,819	[3]	71,735	[3]
Production	-3,596		-15,061
End of year	16,455	[1]	56,674	[1]
Reserves not expected to be recovered					2,000
Proved developed reserves:
Beginning of year	24,131					6,000
End of year	16,455		24,131			6,000
Proved undeveloped reserves:
Beginning of year	32,543	[4]				33,000
End of year		[4]	32,543	[4]		33,000
Gas (MCF) [Member]
Proved developed and undeveloped reserves:
Beginning of year	1,752,564	[1]	2,158,720
Sales of minerals in place	-1,468,384	[2]		[2]
Revisions of previous estimates	59,246	[3]	29,900	[3]
Production	-86,541		-436,056
End of year	256,885	[1]	1,752,564	[1]
Reserves not expected to be recovered					22,000
Proved developed reserves:
Beginning of year	505,077		1,045,040			200,000
End of year	256,885		505,077			200,000
Proved undeveloped reserves:
Beginning of year	1,247,487	[4]	1,113,680			1,200,000
End of year		[4]	1,247,487	[4]		1,200,000
[1]	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 19 thousand barrels of oil, 2 thousand barrels of NGL's, and 22 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered.
[2]	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 6 thousand barrels and 33 thousand barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.2 million mcf and 1.2 million mcf, respectively.
[3]	Revisions of previous estimates were attributable to well performance.
[4]	At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.

Information_about_Oil_and_Gas_5

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 $)	Jan. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Information About Oil And Gas Producing Activities [Abstract]
Future cash inflows		$9,014,000		$18,635,000
Future production costs		-2,798,000		-3,658,000
Future development costs		-2,643,000		-4,923,000
Future ad valorem taxes				-150,000
Future net cash flows		3,573,000	[1],[2]	9,904,000	[1],[2]
10% annual discount for estimated timing of cash flows		-445,000		-2,082,000
Standardized measure of discounted future estimated net cash flows		3,128,000	[1],[2]	7,822,000	[1],[2]
Undiscounted cash flows				4,300,000
Discounted cash flows				3,100,000
Undiscounted cash flows not expected to be realized	800,000
Discounted cash flows not expected to be realized	$800,000
[1]	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $4.3 million and $3.1 million, respectively.
[2]	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, undiscounted and discounted cash flows at December 31, 2014 of approximately $0.8 million, related to the Carrera Project, are not expected to be realized.

Information_about_Oil_and_Gas_6

Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Information About Oil And Gas Producing Activities [Abstract]
Net change in sales and transfer prices and in production costs related to future production	($978,000)		($214,000)
Sales and transfers of oil and gas produced during the period	-2,531,000		-4,907,000
Net change due to purchases and sales of minerals in place	-3,132,000	[1]		[1]
Changes in estimated future development costs	417,000		-637,000
Net change due to revisions in quantities estimates	1,038,000		2,387,000
Accretion of discount	782,000		1,055,000
Other	-290,000		-416,000
Aggregate change in the standardized measure of discounted future net cash flows for the year	-4,694,000	[2]	-2,732,000	[2]
Discounted cash flows			$3,100,000
[1]	On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $3.1 million.
[2]	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. See additional information in the Tables III and IV.