Atlas America Series 25-2004 Inactive 10-Q12 Nov 132013 Q3 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
Document and Entity Information	Sep. 30, 2013
Document - Document and Entity Information [Line Items]	'
Document Type	'10-Q
Amendment Flag	'false
Document Period End Date	30-Sep-13
Document Fiscal Year Focus	'2013
Document Fiscal Period Focus	'Q3
Entity Registrant Name	'Atlas America Series 25-2004 (A) L.P.
Entity Central Index Key	'0001283810
Current Fiscal Year End Date	'--12-31
Entity Filer Category	'Smaller Reporting Company
Entity Common Stock, Shares Outstanding	1,106.76

CONDENSED_BALANCE_SHEETS

CONDENSED BALANCE SHEETS (USD $)	Sep. 30, 2013	Dec. 31, 2012
Current assets:	'	'
Cash and cash equivalents	$62,800	$65,800
Accounts receivable trade-affiliate	229,000	260,700
Accounts receivable monetized gains-affiliate	19,600	63,400
Current portion of derivative assets	2,300	3,000
Total current assets	313,700	392,900
Oil and gas properties, net	2,629,200	2,919,900
Long-term derivative assets	8,200	12,100
TOTAL ASSETS	2,951,100	3,324,900
Current liabilities:	'	'
Accrued liabilities	13,400	900
Total current liabilities	13,400	900
Asset retirement obligation	2,187,600	2,101,900
Long-term put premiums payable-affiliate	9,700	3,100
Commitments and contingencies	'	'
Partnersâ€™ capital:	'	'
Managing general partnerâ€™s interest	726,400	838,500
Limited partnersâ€™ interest (1,106.76 units)	22,100	388,400
Accumulated other comprehensive loss	-8,100	-7,900
Total partnersâ€™ capital	740,400	1,219,000
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$2,951,100	$3,324,900

CONDENSED_BALANCE_SHEETS_Paren

CONDENSED BALANCE SHEETS (Parenthetical)	Sep. 30, 2013
Limited partners' units	1,106.76

CONDENSED_STATEMENTS_OF_OPERAT

CONDENSED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		9 Months Ended
CONDENSED STATEMENTS OF OPERATIONS (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUES	'	'	'	'
Natural gas, oil and liquids	$293,600	$379,500	$827,200	$881,500
Total revenues	293,600	379,500	827,200	881,500
COSTS AND EXPENSES	'	'	'	'
Production	190,100	232,700	550,100	619,900
Depletion	104,500	112,600	290,700	286,100
Accretion of asset retirement obligation	28,500	26,300	85,700	79,000
General and administrative	40,300	41,300	116,800	120,700
Total costs and expenses	363,400	412,900	1,043,300	1,105,700
Net loss	-69,800	-33,400	-216,100	-224,200
Allocation of net (loss) income:	'	'	'	'
Managing general partner	-19,100	3,100	-59,400	-40,700
Limited partners	($50,700)	($36,500)	($156,700)	($183,500)
Net loss per limited partnership unit	($46)	($33)	($142)	($166)

CONDENSED_STATEMENTS_OF_COMPRE

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS (USD $)	3 Months Ended		9 Months Ended
CONDENSED STATEMENTS OF COMPREHENSIVE LOSS (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net loss	($69,800)	($33,400)	($216,100)	($224,200)
Other comprehensive income (loss):	'	'	'	'
Unrealized holding gain (loss) on cash flow hedging contracts	17,600	-7,600	7,800	-9,400
Difference in estimated hedge (losses) gains receivable	-10,900	16,600	6,700	62,700
Reclassification adjustment for gains realized in net loss from cash flow hedges	-4,700	-16,600	-14,700	-62,700
Total other comprehensive income (loss)	2,000	-7,600	-200	-9,400
Comprehensive loss	($67,800)	($41,000)	($216,300)	($233,600)

CONDENSED_STATEMENT_OF_CHANGES

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (USD $)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive Loss
Balance at Dec. 31, 2012	$1,219,000	$838,500	$388,400	($7,900)
Participation in revenues and expenses:	'	'	'	'
Net production revenues	277,100	97,600	179,500	'
Depletion	-290,700	-86,100	-204,600	'
Accretion of asset retirement obligation	-85,700	-30,000	-55,700	'
General and administrative	-116,800	-40,900	-75,900	'
Net loss	-216,100	-59,400	-156,700	'
Other comprehensive loss	-200	'	'	-200
Distributions to partners	-262,300	-52,700	-209,600	'
Balance at Sep. 30, 2013	$740,400	$726,400	$22,100	($8,100)

CONDENSED_STATEMENTS_OF_CASH_F

CONDENSED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
CONDENSED STATEMENTS OF CASH FLOWS (USD $)	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:	'	'
Net loss	($216,100)	($224,200)
Adjustments to reconcile net loss to net cash provided by operating activities:	'	'
Depletion	290,700	286,100
Non-cash loss on derivative value	54,800	99,300
Accretion of asset retirement obligation	85,700	79,000
Decrease in accounts receivable-affiliate	31,700	9,600
Increase in accrued liabilities	12,500	2,800
Net cash provided by operating activities	259,300	252,600
Cash flows from financing activities	'	'
Distributions to partners	-262,300	-314,100
Net cash used in financing activities	-262,300	-314,100
Net decrease in cash and cash equivalents	-3,000	-61,500
Cash and cash equivalents at beginning of period	65,800	61,500
Cash and cash equivalents at end of period	$62,800	'

Description_of_Business

Description of Business	9 Months Ended
Description of Business	Sep. 30, 2013
DESCRIPTION OF BUSINESS	'

	NOTE 1—DESCRIPTION OF BUSINESS
	Atlas America Series 25-2004 (A) L.P. (the “Partnership”) is a Delaware limited partnership, formed on January 21, 2004 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).
	In March 2012, the MGP’s ultimate parent, Atlas Energy L.P. (“Atlas Energy”) (NYSE: ATLS), contributed to ARP, a newly-formed exploration and production master limited partnership, substantially all of Atlas Energy’s natural gas and oil development and production assets and its partnership management business, including ownership of the MGP.
	On February 17, 2011, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS), a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business, its oil and gas exploration, development and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).
	The Partnership has drilled and currently operates wells located in Pennsylvania and Tennessee. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy, for administrative services.
	The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and or third-party gas gathering systems. The Partnership does not plan to sell any of its wells and intends to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership expects that no other wells will be drilled and no additional funds will be required for drilling.
	The accompanying condensed financial statements, which are unaudited, except that the condensed balance sheet at December 31, 2012 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in the Partnership’s Form 10-K. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The results of operations for the three and nine months ended September 30, 2013 may not necessarily be indicative of the results of operations for the year ended December 31, 2013.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2013
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
	In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission (“SEC”).
	Use of Estimates
	Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2013 and 2012 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).
	Accounts Receivable and Allowance for Possible Losses
	In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September 30, 2013 and December 31, 2012, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
	Oil and Gas Properties
	Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
	The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.
	The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $290,700 and $286,100 for the nine months ended September 30, 2013 and 2012, respectively.
	Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.
	The following is a summary of oil and gas properties at the dates indicated:

		September 30,			December 31,
		2013			2012
	Proved properties:
	Leasehold interest	$	716,500		$	716,500
	Wells and related equipment		35,113,000			35,113,000
	Total natural gas and oil properties		35,829,500			35,829,500
	Accumulated depletion and impairment		(33,200,300	)		(32,909,600	)
	Oil and gas properties, net	$	2,629,200		$	2,919,900

	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.
	The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
	In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and nine months ended September 30, 2013 and 2012 nor during the year ended December 31, 2012.
	Working Interest
	The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
	Revenue Recognition
	The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.
	The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at September 30, 2013 and December 31, 2012 of $155,400 and $218,100, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
	Comprehensive Loss
	Comprehensive loss includes net loss and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
	Recently Adopted Accounting Standards
	In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
	In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
	Recently Issued Accounting Standards
	In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

Asset_Retirement_Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2013
ASSET RETIREMENT OBLIGATION	'
	NOTE 3—ASSET RETIREMENT OBLIGATION
	The Partnership recognized an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considered the estimated salvage value in the depletion calculation. The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in cost estimates, remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for the Partnership’s gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.
	A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Asset retirement obligation at beginning of period	$	2,159,100	$	2,120,400	$	2,101,900	$	2,067,700
	Accretion expense		28,500		26,300		85,700		79,000
	Asset retirement obligation at end of period	$	2,187,600	$	2,146,700	$	2,187,600	$	2,146,700

Derivative_Instruments

Derivative Instruments	9 Months Ended
Derivative Instruments	Sep. 30, 2013
DERIVATIVE INSTRUMENTS	'
	NOTE 4—DERIVATIVE INSTRUMENTS
	The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, collars and options, in connection with the Partnership’s commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.
	The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative was effective in offsetting changes in the forecasted cash flow of the hedged item. If the MGP determines that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management of the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to the Partnership’s commodity derivatives to gas and oil production revenues within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations as they occur.
	The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheet of $10,500 and $15,100 at September 30, 2013 and December 31, 2012, respectively.
	The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
	At September 30, 2013, the Partnership had the following commodity derivatives:
	Natural Gas Put Options—Limited Partners

	Production Period Ending	Volumes	Average				Fair Value
	December 31,	(MMBtu) ⁽¹⁾	Fixed Price				Asset ⁽²⁾
			(per MMBtu) ⁽¹⁾
	2013	2,900	$		3.45		$		100
	2014	9,800			3.80				2,900
	2015	7,800			4.00				3,300
	2016	7,800			4.15				4,200
							$		10,500

	(1) “MMBtu” represents million British Thermal Units.
	(2) Fair value based on forward New York Mercantile Exchange (“NYMEX”) natural gas prices, as applicable.
	Effects of Derivative Instruments on Statements of Operations:
	The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three and nine months ended September 30, 2013 and 2012:

		Three Months Ended											Nine Months Ended
		September 30,											September 30,
		2013				2012							2013			2012
	Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$	4,700			$	16,600				$			14,700	$		62,700
	As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the three and nine months ended September 30, 2013 and 2012 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
	Monetized Gains
	Prior to February 17, 2011 (date of the Transferred Business), Atlas Energy Inc., (“AEI”) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments that were specifically related to the future natural gas and oil production of the Partnership. At September 30, 2013 and December 31, 2012, remaining hedge monetization cash proceeds of $25,200 and $69,000 related to the amounts hedged on behalf of the Partnership’s limited partners were included within accounts receivable monetized gains-affiliate, respectively, and $3,000 and $13,800 in long-term put premiums payable-affiliate, respectively, on the Partnership’s balance sheets. The Partnership will allocate the monetized net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.
	During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At September 30, 2013 and December 31, 2012, the put premiums were recorded as short-term payables to affiliate of $5,600 and $5,600 and long-term payables to affiliate of $12,700 and $16,900, respectively. Furthermore, the current portion of the put premium liability was included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate was included in long term put premiums payable-affiliate in the Partnership’s balance sheets, presenting the impact of offsetting the related party assets and liabilities. The put premiums included on the Partnership’s balance sheets are allocable to the limited partners only.
	The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:

	Offsetting Assets	Gross Amounts				Gross Amounts				Net Amount of Assets
		of Recognized				Offset in the				Presented in the Balance
		Assets				Balance Sheets				Sheets
	As of September 30, 2013
	Accounts receivable monetized gains-affiliate	$	25,200			$	(5,600	)		$	19,600
	Long-term receivable monetized gains-affiliate		3,000				(3,000	)			-
	Total	$	28,200			$	(8,600	)		$	19,600

	As of December 31, 2012
	Accounts receivable monetized gains-affiliate	$	69,000			$	(5,600	)		$	63,400
	Long-term receivable monetized gains-affiliate		13,800				(13,800	)			-
	Total	$	82,800			$	(19,400	)		$	63,400


	Offsetting Liabilities	Gross Amounts				Gross Amounts				Net Amount of Liabilities
		of Recognized				Offset in the				Presented in the Balance
		Liabilities				Balance Sheets				Sheets
	As of September 30, 2013
	Put premiums payable-affiliate	$	(5,600	)		$	5,600			$	-
	Long-term put premiums payable-affiliate		(12,700	)			3,000				(9,700	)
	Total	$	(18,300	)		$	8,600			$	(9,700	)

	As of December 31, 2012
	Put premiums payable-affiliate	$	(5,600	)		$	5,600			$	-
	Long-term put premiums payable-affiliate		(16,900	)			13,800				(3,100	)
	Total	$	(22,500	)		$	19,400			$	(3,100	)
	Accumulated Other Comprehensive Income
	As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, and the unrealized gains recognized in earnings in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred loss on its balance sheets in accumulated other comprehensive loss of $8,100 as of September 30, 2013. Included in accumulated other comprehensive income are unrealized gains of $28,500, net of the MGP, interest that were recognized into earnings as a result of oil and gas property impairments during prior periods. During the current year, $1,800 of net losses were recorded by the Partnership and allocated only to the limited partners. Of the remaining $8,100 of net unrealized loss in accumulated other comprehensive loss, the Partnership will reclassify $3,300 of net losses to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $4,800 in later periods.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	9 Months Ended
Fair Value of Financial Instruments	Sep. 30, 2013
FAIR VALUE OF FINANCIAL INSTRUMENTS	'
	NOTE 5—FAIR VALUE OF FINANCIAL INSTRUMENTS
	The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:
	Level 1-Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
	Level 2-Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
	Level 3-Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The carrying values of cash, accounts receivable, and accounts payable approximate their respective fair values due to the short term maturities of such financial instruments. The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 4). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.


	Information for assets and liabilities measured at fair value at September 30, 2013 and December 31, 2012 was as follows:

		Level 1		Level 2		Level 3		Total
	As of September 30, 2013
	Derivative assets, gross
	Commodity puts	$	-	$	10,500	$	-	$	10,500
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	10,500	$	-	$	10,500

	As of December 31, 2012
	Derivative assets, gross
	Commodity puts	$	-	$	15,100	$	-	$	15,100
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	15,100	$	-	$	15,100
	Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
	The Partnership estimates the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates (see Note 3). There were no additional assets or liabilities that were measured at fair value on a nonrecurring basis for the three and nine months ended September 30, 2013 and 2012.

Certain_Relationships_and_Rela

Certain Relationships and Related Party Transactions	9 Months Ended
	Sep. 30, 2013
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	'
	NOTE 6—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	The Partnership has entered into the following significant transactions with the MGP and its affiliates as provided under its Partnership Agreement. Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $313 per well per month for operating and maintaining the wells. Transportation fees, which are included in production expenses in the Partnership’s statements of operations, are generally payable at 13% of the natural gas sales price.
	The following table provides information with respect to these costs and the periods incurred.

		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013		2012		2013			2012
	Administrative	$	22,500	$	25,000	$		67,600	$	73,800
	Supervision		92,900		103,600			279,100		305,100
	Transportation		33,700		42,700			100,400		103,100
	Total	$	149,100	$	171,300	$		447,100	$	482,000
	The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP.

Commitments_and_Contingencies

Commitments and Contingencies	9 Months Ended
Commitments and Contingencies	Sep. 30, 2013
COMMITMENTS AND CONTINGENCIES	'
	NOTE 7—COMMITMENTS AND CONTINGENCIES
	General Commitments
	Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.
	Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of September 30, 2013, the MGP has not withheld any such funds. The MGP is currently evaluating its right to exercise this option based on several factors such as commodity prices, the natural decline in well production, and current and future plugging services and costs.
	Legal Proceedings
	The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2013
Use of Estimates	'
	Use of Estimates
	Preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenues and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following months’ financial results. Management believes that the operating results presented for the three and nine months ended September 30, 2013 and 2012 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).
Accounts Receivable and Allowance for Possible Losses	'
	Accounts Receivable and Allowance for Possible Losses
	In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of the Partnership’s customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness as determined by review of such customers’ credit information. Credit is extended on an unsecured basis to many of the Partnership’s energy customers. At September 30, 2013 and December 31, 2012, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
Oil and Gas Properties	'
	Oil and Gas Properties
	Oil and gas properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
	The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to six mcf of natural gas.
	The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties. The Partnership recorded depletion expense on natural gas and oil properties of $290,700 and $286,100 for the nine months ended September 30, 2013 and 2012, respectively.
	Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets.
	The following is a summary of oil and gas properties at the dates indicated:

		September 30,			December 31,
		2013			2012
	Proved properties:
	Leasehold interest	$	716,500		$	716,500
	Wells and related equipment		35,113,000			35,113,000
	Total natural gas and oil properties		35,829,500			35,829,500
	Accumulated depletion and impairment		(33,200,300	)		(32,909,600	)
	Oil and gas properties, net	$	2,629,200		$	2,919,900

Impairment of Long-Lived Assets	'
	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.
	The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
	In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods. The Partnership may have to pay additional consideration in the future as a well becomes uneconomic under the terms of the Partnership Agreement in order to recover these reserves. There were no impairments recorded during the three and nine months ended September 30, 2013 and 2012 nor during the year ended December 31, 2012.
Working Interest	'
	Working Interest
	The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
Revenue Recognition	'
	Revenue Recognition
	The Partnership generally sells natural gas and crude oil at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of working interest and/or overriding royalty.
	The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGL’s, crude oil, and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees, which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at September 30, 2013 and December 31, 2012 of $155,400 and $218,100, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.
Comprehensive Loss	'
	Comprehensive Loss
	Comprehensive loss includes net loss and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
Recently Adopted Accounting Standards	'
	Recently Adopted Accounting Standards
	In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-10, Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes (“Update 2013-10”). Currently, Topic 815 provides guidance on the risks that are permitted to be hedged in a fair value or cash flow hedge. In addition, only the interest rates on direct Treasury obligations of the U.S. Government (“UST”) and the London Interbank Offered Rate (“LIBOR”) swap rate are considered benchmark interest rates. Update 2013-10 amends Topic 815 to include the Overnight Index Swap Rate (“OIS”), also referred to as the Fed Funds Effective Swap Rate, as a U.S. benchmark interest rate for hedge accounting purposes. Including the OIS as an acceptable U.S. benchmark interest rate in addition to UST and LIBOR will provide risk managers with a more comprehensive spectrum of interest rate resets to utilize as the designated benchmark interest rate risk component under the hedge accounting guidance in Topic 815. Update 2013-10 is effective for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Partnership adopted the requirements of Update 2013-10 upon its effective date of July 17, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
	In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership adopted the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it had no material impact on its financial position, results of operations or related disclosures.
Recently Issued Accounting Standards	'
	Recently Issued Accounting Standards
	In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership will apply the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables) (Oil and Gas Properties)	9 Months Ended
	Sep. 30, 2013
Oil and Gas Properties	'
Schedule of Oil and Gas Properties	'
	The following is a summary of oil and gas properties at the dates indicated:

		September 30,			December 31,
		2013			2012
	Proved properties:
	Leasehold interest	$	716,500		$	716,500
	Wells and related equipment		35,113,000			35,113,000
	Total natural gas and oil properties		35,829,500			35,829,500
	Accumulated depletion and impairment		(33,200,300	)		(32,909,600	)
	Oil and gas properties, net	$	2,629,200		$	2,919,900

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	9 Months Ended
Asset Retirement Obligation (Tables)	Sep. 30, 2013
Schedule of Asset Retirement Obligation	'
	A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Asset retirement obligation at beginning of period	$	2,159,100	$	2,120,400	$	2,101,900	$	2,067,700
	Accretion expense		28,500		26,300		85,700		79,000
	Asset retirement obligation at end of period	$	2,187,600	$	2,146,700	$	2,187,600	$	2,146,700

Derivative_Instruments_Tables

Derivative Instruments (Tables)	9 Months Ended
Derivative Instruments (Tables)	Sep. 30, 2013
Effects of Derivative Instruments on Statements of Operations	'
	Effects of Derivative Instruments on Statements of Operations:
	The following table summarizes the gain or loss recognized in the statements of operations for effective derivative instruments for the three and nine months ended September 30, 2013 and 2012:

		Three Months Ended											Nine Months Ended
		September 30,											September 30,
		2013				2012							2013			2012
	Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$	4,700			$	16,600				$			14,700	$		62,700

Offsetting Derivative Assets	'
	The following table summarizes the gross and net fair values of the Partnership’s balances on the Partnership’s balance sheets for the periods indicated:

	Offsetting Assets	Gross Amounts				Gross Amounts				Net Amount of Assets
		of Recognized				Offset in the				Presented in the Balance
		Assets				Balance Sheets				Sheets
	As of September 30, 2013
	Accounts receivable monetized gains-affiliate	$	25,200			$	(5,600	)		$	19,600
	Long-term receivable monetized gains-affiliate		3,000				(3,000	)			-
	Total	$	28,200			$	(8,600	)		$	19,600

	As of December 31, 2012
	Accounts receivable monetized gains-affiliate	$	69,000			$	(5,600	)		$	63,400
	Long-term receivable monetized gains-affiliate		13,800				(13,800	)			-
	Total	$	82,800			$	(19,400	)		$	63,400

Offsetting Derivative Liabilities	'

	Offsetting Liabilities	Gross Amounts				Gross Amounts				Net Amount of Liabilities
		of Recognized				Offset in the				Presented in the Balance
		Liabilities				Balance Sheets				Sheets
	As of September 30, 2013
	Put premiums payable-affiliate	$	(5,600	)		$	5,600			$	-
	Long-term put premiums payable-affiliate		(12,700	)			3,000				(9,700	)
	Total	$	(18,300	)		$	8,600			$	(9,700	)

	As of December 31, 2012
	Put premiums payable-affiliate	$	(5,600	)		$	5,600			$	-
	Long-term put premiums payable-affiliate		(16,900	)			13,800				(3,100	)
	Total	$	(22,500	)		$	19,400			$	(3,100	)

Natural Gas Put OptionsbLimited Partners	'
Commodity Derivatives	'
	The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
	At September 30, 2013, the Partnership had the following commodity derivatives:
	Natural Gas Put Options—Limited Partners

	Production Period Ending	Volumes	Average				Fair Value
	December 31,	(MMBtu) ⁽¹⁾	Fixed Price				Asset ⁽²⁾
			(per MMBtu) ⁽¹⁾
	2013	2,900	$		3.45		$		100
	2014	9,800			3.80				2,900
	2015	7,800			4.00				3,300
	2016	7,800			4.15				4,200
							$		10,500

	(1) “MMBtu” represents million British Thermal Units.
	(2) Fair value based on forward New York Mercantile Exchange (“NYMEX”) natural gas prices, as applicable.

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	9 Months Ended
Fair Value of Financial Instruments (Tables)	Sep. 30, 2013
Schedule of Fair Value Derivative Instruments	'


	Information for assets and liabilities measured at fair value at September 30, 2013 and December 31, 2012 was as follows:

		Level 1		Level 2		Level 3		Total
	As of September 30, 2013
	Derivative assets, gross
	Commodity puts	$	-	$	10,500	$	-	$	10,500
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	10,500	$	-	$	10,500

	As of December 31, 2012
	Derivative assets, gross
	Commodity puts	$	-	$	15,100	$	-	$	15,100
	Derivative liabilities, gross
	Commodity puts		-		-		-		-
	Total derivative, fair value, net	$	-	$	15,100	$	-	$	15,100

Certain_Relationships_and_Rela1

Certain Relationships and Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2013
Costs Incurred From Related Party Transactions	'
	The following table provides information with respect to these costs and the periods incurred.

		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013		2012		2013			2012
	Administrative	$	22,500	$	25,000	$		67,600	$	73,800
	Supervision		92,900		103,600			279,100		305,100
	Transportation		33,700		42,700			100,400		103,100
	Total	$	149,100	$	171,300	$		447,100	$	482,000

Description_of_Business_Detail

Description of Business (Details)	9 Months Ended
Description of Business (Details)	Sep. 30, 2013
Atlas America Series 25-2004 (A) L.P Formation Date	21-Jan-04

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Schedule of Oil and Gas Properties) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Natural gas and oil properties	$35,829,500	$35,829,500
Less - Accumulated depletion and impairment	-33,200,300	-32,909,600
Oil and gas properties, net	2,629,200	2,919,900
Leaseholds interests	'	'
Natural gas and oil properties	716,500	716,500
Wells and related equipment	'	'
Natural gas and oil properties	$35,113,000	$35,113,000

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Allowance for Uncollectible Accounts Receivable	$0	'	$0	'	$0
Depletion of Oil and Gas Properties	104,500	112,600	290,700	286,100	'
Asset Impairment Charges	0	0	0	0	'
Additional working interest	'	'	7.00%	'	'
Unbilled Revenues	$155,400	'	$155,400	'	$218,100

Asset_Retirement_Obligation_De

Asset Retirement Obligation (Details) (USD $)	3 Months Ended		9 Months Ended
Asset Retirement Obligation (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Asset Retirement Obligation [Abstract]	'	'	'	'
Asset retirement obligation at beginning of period	$2,159,100	$2,120,400	$2,101,900	$2,067,700
Accretion expense	28,500	26,300	85,700	79,000
Asset retirement obligation at end of period	$2,187,600	$2,146,700	$2,187,600	$2,146,700

Derivative_Instruments_Commodi

Derivative Instruments (Commodity Derivatives) (Details) (USD $)

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Natural Gas Put OptionsbLimited Partners

Production Period Ending December 31, 2013

Production Period Ending December 31, 2014

Production Period Ending December 31, 2015

Production Period Ending December 31, 2016

Natural Gas Put OptionsbLimited Partners

MMBTU

Derivative [Line Items]

Volumes (MMBtu)

2,900

[1]

9,800

[1]

7,800

[1]

7,800

[1]

Average Fixed Price (per MMBtu)

3.45

[1]

3.8

[1]

4.15

[1]

Fair Value Asset

$10,500

$15,100

$10,500

[2]

$100

[2]

$2,900

[2]

$3,300

[2]

$4,200

[2]

[1]

bMMBtub represents million British Thermal Units.

[2]

Fair value based on forward New York Mercantile Exchange (bNYMEXb) natural gas prices, as applicable.

Derivative_Instruments_Effects

Derivative Instruments (Effects of Derivative Instruments on Statements of Operations) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'	'	'	'
Gains from cash flow hedges reclassified from accumulated other comprehensive income (loss) into natural gas, oil and liquids revenues	$4,700	$16,600	$14,700	$62,700

Derivative_Instruments_Offsett

Derivative Instruments (Offsetting Derivative Assets) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	$28,200	$82,800
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-8,600	-19,400
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	19,600	63,400
Accounts receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	25,200	69,000
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	-5,600	-5,600
Affiliate Balances, Offsetting Derivative Assets, Net Amount of Assets Presented in the Balance Sheets	19,600	63,400
Long-term receivable monetized gains-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	3,000	13,800
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts Offset in the Balance Sheets	($3,000)	($13,800)

Derivative_Instruments_Offsett1

Derivative Instruments (Offsetting Derivative Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	($18,300)	($22,500)
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	8,600	19,400
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	-9,700	-3,100
Put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-5,600	-5,600
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	5,600	5,600
Long-term put premiums payable-affiliate	'	'
Derivative [Line Items]	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts of Recognized Liabilities	-12,700	-16,900
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Offset in the Balance Sheets	3,000	13,800
Affiliate Balances, Offsetting Derivative Liabilities, Net Amount of Liabilities Presented in the Balance Sheets	($9,700)	($3,100)

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
Derivative Instruments (Narrative) (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Derivative [Line Items]	'	'	'	'	'
Fair Value Asset/(Liability)	$10,500	'	$10,500	'	$15,100
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	0	0	0	0	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	28,200	'	28,200	'	82,800
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	18,300	'	18,300	'	22,500
Accumulated other comprehensive loss	-8,100	'	-8,100	'	-7,900
Unrealized gains (losses) due to natural gas and oil property impairments	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Accumulated other comprehensive loss	-8,100	'	-8,100	'	'
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	'	'	-3,300	'	'
Net Deferred Gain To Be Reclassified Into Net Income In Later Periods	'	'	-4,800	'	'
Allocation To Limited Partner Only \| Other Comprehensive Income (Loss)	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Net Derivative Gains And Losses Limited Partner	'	'	-1,800	'	'
Allocation To MGP Only \| Other Comprehensive Income (Loss)	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Reclassification Adjustment For Gain Recognized On Property Impairments	'	'	28,500	'	'
Accounts receivable monetized gains-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	25,200	'	25,200	'	69,000
Accounts receivable monetized gains-affiliate \| Allocation To Limited Partner Only	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	25,200	'	25,200	'	69,000
Long-term receivable monetized gains-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	3,000	'	3,000	'	13,800
Long-term receivable monetized gains-affiliate \| Allocation To Limited Partner Only	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Assets, Gross Amounts of Recognized Assets	3,000	'	3,000	'	13,800
Put premiums payable-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	5,600	'	5,600	'	5,600
Put premiums payable-affiliate \| Allocation To Limited Partner Only	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	5,600	'	5,600	'	5,600
Long-term put premiums payable-affiliate	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	12,700	'	12,700	'	16,900
Long-term put premiums payable-affiliate \| Allocation To Limited Partner Only	'	'	'	'	'
Derivative [Line Items]	'	'	'	'	'
Affiliate Balances, Offsetting Derivative Liabilities, Gross Amounts Of Recognized Liabilities	$12,700	'	$12,700	'	$16,900

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative, Fair Value, Total	$10,500	$15,100
Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	10,500	15,100
Derivative liabilities, gross	'	'
Fair Value, Inputs, Level 1	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative, Fair Value, Total	'	'
Fair Value, Inputs, Level 1 \| Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Derivative liabilities, gross	'	'
Fair Value, Inputs, Level 2	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative, Fair Value, Total	10,500	15,100
Fair Value, Inputs, Level 2 \| Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	10,500	15,100
Derivative liabilities, gross	'	'
Fair Value, Inputs, Level 3	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative, Fair Value, Total	'	'
Fair Value, Inputs, Level 3 \| Commodity Puts	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Derivative assets, gross	'	'
Derivative liabilities, gross	'	'

Certain_Relationships_and_Rela2

Certain Relationships and Related Party Transactions (Schedule of Related Party Transactions) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$149,100	$171,300	$447,100	$482,000
Administrative	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	22,500	25,000	67,600	73,800
Supervision	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	92,900	103,600	279,100	305,100
Transportation	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'
Related Party Transaction, Expenses from Transactions with Related Party	$33,700	$42,700	$100,400	$103,100

Certain_Relationships_and_Rela3

Certain Relationships and Related Party Transactions (Details) (USD $)	9 Months Ended
	Sep. 30, 2013
Administrative	'
Related Party Transaction [Line Items]	'
Monthly Administrative Costs Per Well	$75
Supervision	'
Related Party Transaction [Line Items]	'
Monthly Supervision Fees Per Well	$313
Transportation	'
Related Party Transaction [Line Items]	'
Transportation Fee Rate As Percentage Of Natural Gas Sales Price	13.00%

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	9 Months Ended
Commitments and Contingencies (Details) (USD $)	Sep. 30, 2013
Disclosure - Commitments and Contingencies (Details) [Line Items]	'
Investor Partners Ownership Interest Presented For Purchase By The MGP, Maximum Percentage	5.00%
Operator Fee Per Well To Cover Estimated Future Plugging And Abandonment Costs, Monthly	$200