Atlas America Series 25-2004 10-Q 14 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - Jun. 30, 2015 - shares	Total
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Entity Registrant Name	ATLAS AMERICA SERIES 25-2004 (B) L.P.
Entity Central Index Key	1,294,208
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding	0

CONDENSED BALANCE SHEETS

CONDENSED BALANCE SHEETS - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 0	$ 0
Accounts receivable trade–affiliate	43,800	78,100
Asset retirement receivable-affiliate	118,300	16,300
Current portion of derivative assets	8,400	8,000
Total current assets	170,500	102,400
Gas and oil properties, net	2,113,700	2,157,800
Long-term derivative assets	4,000	6,700
TOTAL ASSETS	2,288,200	2,266,900
Current liabilities:
Accounts payable trade-affiliate	205,500
Accrued liabilities	4,100	9,100
Current portion of put premiums payable-affiliate	5,700	5,100
Total current liabilities	215,300	14,200
Asset retirement obligations	3,700,500	3,597,600
Long-term put premiums payable-affiliate	$ 2,900	$ 5,900
Commitments and contingencies
Partners’ capital:
Managing general partner’s interest	$ (33,500)	$ 68,800
Limited partners’ interest (1,265.38 units)	(1,599,100)	(1,423,300)
Accumulated other comprehensive income	2,100	3,700
Total partners’ capital	(1,630,500)	(1,350,800)
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 2,288,200	$ 2,266,900

CONDENSED BALANCE SHEETS (Paren

CONDENSED BALANCE SHEETS (Parenthetical)	Jun. 30, 2015shares
Statement Of Financial Position [Abstract]
Limited partners' units	1,265.38

CONDENSED STATEMENTS OF OPERATI

CONDENSED STATEMENTS OF OPERATIONS - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES
Natural gas, oil and liquid	$ 71,600	$ 282,800	$ 204,100	$ 581,900
(Loss) gain on mark-to-market derivative	(2,100)		200
Total revenues	69,500	282,800	204,300	581,900
COSTS AND EXPENSES
Production	121,800	202,000	266,200	385,300
Depletion	20,900	53,000	44,100	98,800
Accretion of asset retirement obligation	51,500	35,400	102,900	70,700
General and administrative	33,200	33,100	69,200	71,600
Total costs and expenses	227,400	323,500	482,400	626,400
Net loss	(157,900)	(40,700)	(278,100)	(44,500)
Allocation of net loss:
Managing general partner	(57,000)	(13,000)	(102,300)	(13,100)
Limited partners	$ (100,900)	$ (27,700)	$ (175,800)	$ (31,400)
Net loss per limited partnership unit	$ (80)	$ (22)	$ (139)	$ (25)

CONDENSED STATEMENTS OF COMPREH

CONDENSED STATEMENTS OF COMPREHENSIVE LOSS - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (157,900)	$ (40,700)	$ (278,100)	$ (44,500)
Other comprehensive loss:
Unrealized holding gain (loss) on cash flow hedging contracts		600		(8,800)
Difference in estimated hedge gains receivable	1,100	(1,200)	2,400	15,800
Less: reclassification adjustment for realized gains of cash flow hedges in net loss	(1,900)	(300)	(4,000)	(10,300)
Total other comprehensive loss	(800)	(900)	(1,600)	(3,300)
Comprehensive loss	$ (158,700)	$ (41,600)	$ (279,700)	$ (47,800)

CONDENSED STATEMENT OF CHANGES

CONDENSED STATEMENT OF CHANGES IN PARTNERS' CAPITAL - 6 months ended Jun. 30, 2015 - USD ($)	Total	Managing General Partner	Limited Partners	Accumulated Other Comprehensive (Loss) Income
Beginning balance at Dec. 31, 2014	$ (1,350,800)	$ 68,800	$ (1,423,300)	$ 3,700
Participation in revenues, costs and expenses:
Net production expense	(62,100)	(23,000)	(39,100)
Gain on mark-to-market derivatives	200		200
Depletion	(44,100)	(19,100)	(25,000)
Accretion of asset retirement obligation	(102,900)	(36,000)	(66,900)
General and administrative	(69,200)	(24,200)	(45,000)
Net loss	(278,100)	(102,300)	(175,800)
Other comprehensive loss	(1,600)			(1,600)
Ending balance at Jun. 30, 2015	$ (1,630,500)	$ (33,500)	$ (1,599,100)	$ 2,100

CONDENSED STATEMENTS OF CASH FL

CONDENSED STATEMENTS OF CASH FLOWS - USD ($)	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net loss	$ (278,100)	$ (44,500)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	44,100	98,800
Non cash (gain) loss on derivative value	(1,800)	4,300
Accretion of asset retirement obligation	102,900	70,700
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable trade-affiliate	34,300	(21,400)
Increase in asset retirement receivable-affiliate	(102,000)	(5,000)
Increase in accounts payable trade-affiliate	205,600
Decrease in accrued liabilities	(4,900)	(2,100)
Decrease in payable to limited partners		(9,600)
Asset retirement obligations settled		(100)
Net cash provided by operating activities		91,100
Cash flows from financing activities:
Distributions to partners		(108,400)
Net cash used in financing activities		(108,400)
Net change in cash and cash equivalents		(17,300)
Cash and cash equivalents at beginning of period	0	17,300
Cash and cash equivalents at end of period	$ 0	$ 0

Description of Business

Description of Business	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
DESCRIPTION OF BUSINESS	NOTE 1 - DESCRIPTION OF BUSINESS Atlas America Series 25-2004 (B) 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 the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP). On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest. The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee and West Virginia. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, 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 intends to produce its wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling. The accompanying condensed financial statements, which are unaudited, except for the balance sheet at December 31, 2014, which 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, 2014. The results of operations for the three and six months ended June 30, 2015 may not necessarily be indicative of the results of operations for the year ended December 31, 2015.

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
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, 2014 filed with the Securities and Exchange Commission (“SEC”). Use of Estimates The preparation of the Partnership’s 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, 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 many 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 six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “ - Revenue Recognition”) Accounts Receivable Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, 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 June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable. Gas and Oil Properties Gas and oil properties are stated at cost. Maintenance and repairs which 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 gas and oil producing activities. Oil and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet. 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 $44,100 and $98,800 for the six months ended June 30, 2015 and 2014, respectively. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated 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 depletion within its balance sheets. The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, 2015 2014 Proved properties: Leasehold interests $ 898,600 $ 898,600 Wells and related equipment 41,682,000 41,682,000 Total natural gas and oil properties 42,580,600 42,580,600 Accumulated depletion and impairment (40,466,900 ) (40,422,800 ) Gas and oil properties, net $ 2,113,700 $ 2,157,800 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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. 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 and the carrying value of the assets. The determination of natural gas and oil 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. There was no gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $2,334,600. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement. 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, crude oil and NGLs at prevailing market prices. Typically, 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, crude oil and NGLs, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. 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. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, 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 (See “ - Use of Estimates Comprehensive Loss Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” on the Partnership’s financial statements and, at June 30, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive loss. Recently Issued Accounting Standards In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Property, Plant and Equipment, Intangibles – Goodwill and Other .

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 3 - ASSET RETIREMENT OBLIGATIONS The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells. 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 considers the estimated salvage value in the calculation of depletion. 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. The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of June 30, 2015, the MGP has withheld $118,300 of net production revenue for future plugging and abandonment costs. A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows: Three Months Ended Six Months Ended 2015 2014 2015 2014 Asset retirement obligation at beginning of period $ 3,649,000 $ 2,417,200 $ 3,597,600 $ 2,381,900 Asset retirement obligations settled - (100 ) - (100 ) Accretion expense 51,500 35,400 102,900 70,700 Asset retirement obligation at end of period $ 3,700,500 $ 2,452,500 $ 3,700,500 $ 2,452,500

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to New York Mercantile Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. 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. On January 1, 2015, the Partnership discontinued hedge accounting for its qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on the Partnership’s balance sheet, will be reclassified to the Partnership’s statements of operations in the future at the time the originally hedged physical transactions affect earnings. 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 sheets of $12,400 and $14,700 at June 30, 2015 and December 31, 2014, respectively. The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Three Months Ended Six Months Ended 2015 2014 2015 2014 Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues $ 1,900 $ 300 $ 4,000 $ 10,300 (Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives (2,100 ) - 200 - 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 been recorded at their fair values. At June 30, 2015, the Partnership had the following commodity derivatives: Natural Gas Put Options Production Period Ending December 31, Volumes Average Fair Value (2) (MMBtu) (1) (per MMBtu) (1) 2015 3,800 $ 4.00 $ 4,300 2016 7,700 4.15 8,100 $ 12,400 (1) “MMBtu” represents million British Thermal Units. (2) Fair value based on forward NYMEX natural gas prices, as applicable. 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 six months ended June 30, 2015 and 2014 for hedge ineffectiveness. Put Premiums Payable During June 2012, 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 June 30, 2015 and December 31, 2014, $5,700 and $5,100, respectively, of the put premiums were recorded as short-term payables to affiliate and $2,900 and $5,900, respectively, were recorded as long-term payables to affiliate. Accumulated Other Comprehensive Income As a result of the put options, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $2,100 as of June 30, 2015. During the six months ended June 30, 2015, $3,600 of net gains were recorded by the Partnership and allocated only to the limited partners. Of the remaining $2,100 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $1,700 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining $400 of gains in later periods.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
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. The fair values of 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 the pricing formula utilized in the derivative instrument. Information for assets measured at fair value at June 30, 2015 and December 31, 2014 was as follows: Level 1 Level 2 Level 3 Total As of June 30, 2015 Derivative assets, gross Commodity puts $ - $ 12,400 $ - $ 12,400 Level 1 Level 2 Level 3 Total As of December 31, 2014 Derivative assets, gross Commodity puts $ - $ 14,700 $ - $ 14,700 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The Partnership estimates the fair value of its asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding 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 six months ended June 30, 2015 and 2014.

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
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 expense in the Partnership’s statements of operations, are payable at $313 per well per month for operating and maintaining the wells. Well supervision fees are proportionately reduced to the extent the Partnership does not acquire 100% of the working interest in a well. Transportation fees are included in production expense in the Partnership’s statements of operations and are generally payable at 13% of the natural gas sales price. Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. The following table provides information with respect to these costs and the periods incurred: Three Months Ended Six Months Ended 2015 2014 2015 2014 Administrative fees $ 18,500 $ 25,400 $ 40,700 $ 49,600 Supervision fees 75,700 104,100 166,400 203,100 Transportation fees 7,600 34,500 22,300 68,200 Direct costs 53,200 71,100 106,000 136,000 Total $ 155,000 $ 235,100 $ 335,400 $ 456,900 The MGP and its affiliates perform all administrative and management functions for the Partnership, including billing revenues and paying expenses. Accounts payable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due to the MGP as of June 30, 2015. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP as of December 31, 2014.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
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 total outstanding 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 June 30, 2015, the MGP has withheld $118,300 of net production revenue for future plugging and abandonment 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. Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

Summary of Significant Accoun15

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Use of Estimates	Use of Estimates The preparation of the Partnership’s 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, 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 many 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 six months ended June 30, 2015 and 2014 represent actual results in all material respects (See “ - Revenue Recognition”)
Accounts Receivable	Accounts Receivable Accounts receivable on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of the Partnership’s accounts receivable, 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 June 30, 2015 and December 31, 2014, the MGP’s credit evaluation indicated that the Partnership had no need for an allowance for uncollectible accounts receivable.
Gas and Oil Properties	Gas and Oil Properties Gas and oil properties are stated at cost. Maintenance and repairs which 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 gas and oil producing activities. Oil and natural gas liquids (“NGLs”) are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six Mcf of natural gas. Mcf is defined as one thousand cubic feet. 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 $44,100 and $98,800 for the six months ended June 30, 2015 and 2014, respectively. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated 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 depletion within its balance sheets. The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, 2015 2014 Proved properties: Leasehold interests $ 898,600 $ 898,600 Wells and related equipment 41,682,000 41,682,000 Total natural gas and oil properties 42,580,600 42,580,600 Accumulated depletion and impairment (40,466,900 ) (40,422,800 ) Gas and oil properties, net $ 2,113,700 $ 2,157,800
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 gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. 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 and the carrying value of the assets. The determination of natural gas and oil 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. There was no gas and oil properties impairment recorded for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Partnership recognized an impairment charge of $2,334,600. This impairment relates to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2014. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.
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, crude oil and NGLs at prevailing market prices. Typically, 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, crude oil and NGLs, in which the Partnership has an interest with other producers are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. 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. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, 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 (See “ - Use of Estimates
Comprehensive Loss	Comprehensive Loss Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” on the Partnership’s financial statements and, at June 30, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive loss.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40) In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Property, Plant and Equipment, Intangibles – Goodwill and Other .

Summary of Significant Accoun16

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Summary of Gas and Oil Properties	The following is a summary of gas and oil properties at the dates indicated: June 30, December 31, 2015 2014 Proved properties: Leasehold interests $ 898,600 $ 898,600 Wells and related equipment 41,682,000 41,682,000 Total natural gas and oil properties 42,580,600 42,580,600 Accumulated depletion and impairment (40,466,900 ) (40,422,800 ) Gas and oil properties, net $ 2,113,700 $ 2,157,800

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows: Three Months Ended Six Months Ended 2015 2014 2015 2014 Asset retirement obligation at beginning of period $ 3,649,000 $ 2,417,200 $ 3,597,600 $ 2,381,900 Asset retirement obligations settled - (100 ) - (100 ) Accretion expense 51,500 35,400 102,900 70,700 Asset retirement obligation at end of period $ 3,700,500 $ 2,452,500 $ 3,700,500 $ 2,452,500

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges	The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated: Three Months Ended Six Months Ended 2015 2014 2015 2014 Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues $ 1,900 $ 300 $ 4,000 $ 10,300 (Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives (2,100 ) - 200 -
Commodity Derivatives	At June 30, 2015, the Partnership had the following commodity derivatives: Natural Gas Put Options Production Period Ending December 31, Volumes Average Fair Value (2) (MMBtu) (1) (per MMBtu) (1) 2015 3,800 $ 4.00 $ 4,300 2016 7,700 4.15 8,100 $ 12,400 (1) “MMBtu” represents million British Thermal Units. (2) Fair value based on forward NYMEX natural gas prices, as applicable.

Fair Value of Financial Instr19

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Assets Measured at Fair Value on a Recurring Basis	Information for assets measured at fair value at June 30, 2015 and December 31, 2014 was as follows: Level 1 Level 2 Level 3 Total As of June 30, 2015 Derivative assets, gross Commodity puts $ - $ 12,400 $ - $ 12,400 Level 1 Level 2 Level 3 Total As of December 31, 2014 Derivative assets, gross Commodity puts $ - $ 14,700 $ - $ 14,700

Certain Relationships and Rel20

Certain Relationships and Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Certain Relationships and Related Party Transactions	The following table provides information with respect to these costs and the periods incurred: Three Months Ended Six Months Ended 2015 2014 2015 2014 Administrative fees $ 18,500 $ 25,400 $ 40,700 $ 49,600 Supervision fees 75,700 104,100 166,400 203,100 Transportation fees 7,600 34,500 22,300 68,200 Direct costs 53,200 71,100 106,000 136,000 Total $ 155,000 $ 235,100 $ 335,400 $ 456,900

Description of Business (Detail

Description of Business (Details)	Feb. 27, 2015	Jun. 30, 2015
Description Of Business [Line Items]
Atlas America Series 25-2004 (B) L.P. Formation Date		Jan. 21, 2004
Atlas Energy Group | Atlas Energy | Spin Off
Description Of Business [Line Items]
Percentage of limited liability company interests distributed to unitholders	100.00%

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Allowance for Uncollectible Accounts Receivable	$ 0		$ 0		$ 0
Depletion of Oil and Gas Properties	20,900	$ 53,000	44,100	$ 98,800
Impairment	0	$ 0	$ 0	$ 0	2,334,600
Additional working interest			7.00%
Unbilled Revenues	$ 43,800		$ 43,800		89,900
Due to affiliate					$ 11,800

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Summary of Gas and Oil Properties) (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 42,580,600	$ 42,580,600
Accumulated depletion and impairment	(40,466,900)	(40,422,800)
Gas and oil properties, net	2,113,700	2,157,800
Leasehold interests
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	898,600	898,600
Wells and related equipment
Property Plant And Equipment [Line Items]
Total natural gas and oil properties	$ 41,682,000	$ 41,682,000

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details)	6 Months Ended
	Jun. 30, 2015USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Net production revenue for future plugging and abandonment costs	$ 118,300

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligations, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 3,649,000	$ 2,417,200	$ 3,597,600	$ 2,381,900
Asset retirement obligations settled		(100)		(100)
Accretion expense	51,500	35,400	102,900	70,700
Asset retirement obligation at end of period	$ 3,700,500	$ 2,452,500	$ 3,700,500	$ 2,452,500

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Derivative [Line Items]
Net derivative assets	$ 12,400		$ 12,400		$ 14,700
Gains (Losses) on Fair Value Hedge Ineffectiveness, Net	0	$ 0	0	$ 0
Current portion of put premiums payable-affiliate	5,700		5,700		5,100
Long-term put premiums payable-affiliate	2,900		2,900		5,900
Accumulated other comprehensive income	$ 2,100		2,100		$ 3,700
Other Comprehensive Income
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			1,700
Net Deferred Gain (Loss) to be Reclassified into Net Income in Later Periods			400
Allocation To Limited Partner Only | Other Comprehensive Income
Derivative [Line Items]
Net Derivative Gains (Losses) Limited Partner			$ 3,600

Derivative Instruments (Summary

Derivative Instruments (Summary of Gains or Losses Recognized Within Statements of Operations for Derivative Instruments Previously Designated as Cash Flow Hedges) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gains reclassified from accumulated other comprehensive income into natural gas and oil and liquids revenues	$ 1,900	$ 300	$ 4,000	$ 10,300
(Loss) gain subsequent to December 31, 2014 recognized in (loss) gain on mark-to-market derivatives	$ (2,100)		$ 200

Derivative Instruments (Commodi

Derivative Instruments (Commodity Derivatives) (Details)		6 Months Ended
		Jun. 30, 2015USD ($)MMBTU$ / MMBTU	Dec. 31, 2014USD ($)
Derivative [Line Items]
Fair Value Asset		$ 12,400	$ 14,700
Natural Gas Put Options
Derivative [Line Items]
Fair Value Asset	[1]	$ 12,400
Natural Gas Put Options | Production Period Ending December 31, 2015
Derivative [Line Items]
Volumes | MMBTU	[2]	3,800
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4
Fair Value Asset	[1]	$ 4,300
Natural Gas Put Options | Production Period Ending December 31, 2016
Derivative [Line Items]
Volumes | MMBTU	[2]	7,700
Average Fixed Price (per MMBtu) | $ / MMBTU	[2]	4.15
Fair Value Asset	[1]	$ 8,100
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	“MMBtu” represents million British Thermal Units.

Fair Value of Financial Instr29

Fair Value of Financial Instruments (Assets Measured at Fair Value on a Recurring Basis) (Details) - Commodity Puts - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 12,400	$ 14,700
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets, gross	$ 12,400	$ 14,700

Fair Value of Financial Instr30

Fair Value of Financial Instruments (Narrative) (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Fair Value Disclosures [Abstract]
Assets measured at fair value on nonrecurring basis	$ 0	$ 0
Liabilities measured at fair value on nonrecurring basis	$ 0	$ 0

Certain Relationships and Rel31

Certain Relationships and Related Party Transactions (Narrative) (Details) - 6 months ended Jun. 30, 2015 - MGP and Affiliates - $ / mo	Total
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%

Certain Relationships and Rel32

Certain Relationships and Related Party Transactions (Certain Relationships and Related Party Transactions) (Details) - MGP and Affiliates - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 155,000	$ 235,100	$ 335,400	$ 456,900
Administrative fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	18,500	25,400	40,700	49,600
Supervision fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	75,700	104,100	166,400	203,100
Transportation fees
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	7,600	34,500	22,300	68,200
Direct Costs
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 53,200	$ 71,100	$ 106,000	$ 136,000

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - 6 months ended Jun. 30, 2015	USD ($)$ / mo
Commitments And Contingencies Disclosure [Abstract]
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 | $ / mo	200
Net production revenue for future plugging and abandonment costs	$ 118,300