Atlas Energy 10-Q 10 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 04, 2015
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 Energy Group, LLC
Entity Central Index Key	1,623,595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Trading Symbol	ATLS
Entity Common Stock, Units Outstanding		26,010,766

COMBINED CONSOLIDATED BALANCE S

COMBINED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 40,077	$ 58,358
Accounts receivable	90,489	115,290
Advances to affiliates		4,389
Current portion of derivative asset	114,740	144,259
Subscriptions receivable	34,675	32,398
Prepaid expenses and other	25,016	26,789
Total current assets	304,997	381,483
Property, plant and equipment, net	2,392,656	2,419,289
Goodwill and intangible assets, net	14,213	14,330
Long-term derivative asset	150,180	130,602
Other assets, net	82,792	80,611
Total assets	2,944,838	3,026,315
Current liabilities:
Current portion of long-term debt	77,371	1,500
Accounts payable	110,789	123,670
Liabilities associated with drilling contracts		40,611
Current portion of derivative payable to Drilling Partnerships	1,441	932
Accrued interest	26,312	26,479
Accrued well drilling and completion costs	37,368	92,910
Deferred acquisition purchase price	39,167	105,000
Accrued liabilities	40,132	64,854
Total current liabilities	332,580	455,956
Long-term debt, less current portion	1,491,612	1,541,085
Asset retirement obligations and other	$ 120,287	$ 114,059
Commitments and contingencies
Unitholders’/owner’s equity:
Common unitholders’ equity	$ 105,649
Series A preferred equity	38,999
Owner’s equity		$ 147,308
Accumulated other comprehensive income	32,626	54,008
Unitholders'/owner's equity excluding non-controlling interests	177,274	201,316
Non-controlling interests	823,085	713,899
Total unitholders’/owner’s equity	1,000,359	915,215
Total liabilities and unitholders’/owner’s equity	$ 2,944,838	$ 3,026,315

COMBINED CONSOLIDATED STATEMENT

COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Gas and oil production	$ 99,077	$ 110,694	$ 205,637	$ 211,519
Well construction and completion	16,956	16,336	40,611	65,713
Gathering and processing	2,177	3,758	4,361	8,226
Administration and oversight	547	4,166	1,806	5,895
Well services	6,102	6,365	12,726	11,844
Gain (loss) on mark-to-market derivatives	(26,896)		78,689
Other, net	284	285	216	554
Total revenues	98,247	141,604	344,046	303,751
Costs and expenses:
Gas and oil production	43,619	43,828	89,608	82,586
Well construction and completion	14,745	14,206	35,315	57,142
Gathering and processing	2,516	4,273	4,933	8,686
Well services	2,139	2,426	4,337	4,908
General and administrative	18,405	24,797	60,333	46,188
Depreciation, depletion and amortization	43,276	60,406	87,732	112,445
Total costs and expenses	124,700	149,936	282,258	311,955
Operating income (loss)	(26,453)	(8,332)	61,788	(8,204)
Gain (loss) on asset sales and disposal	97	12	86	(1,591)
Interest expense	(33,187)	(16,074)	(67,938)	(32,051)
Net loss	(59,543)	(24,394)	(6,064)	(41,846)
(Income) loss attributable to non-controlling interests	38,745	18,383	(19,558)	28,691
Net loss attributable to unitholders’/owner’s interests	(20,798)	(6,011)	(25,622)	(13,155)
Allocation of net loss attributable to unitholders’/owner’s interests:
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)		(6,011)	(10,475)	(13,155)
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015)	(20,798)		(15,147)
Net loss attributable to unitholders’/owner’s interests	$ (20,798)	$ (6,011)	$ (25,622)	$ (13,155)
Net loss attributable to unitholders per common unit:
Basic	$ (0.80)		$ (0.58)
Diluted	$ (0.80)		$ (0.58)
Weighted average common units outstanding:
Basic	26,011		26,011
Diluted	26,011		26,011

COMBINED CONSOLIDATED STATEMEN4

COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	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	$ (59,543)	$ (24,394)	$ (6,064)	$ (41,846)
Other comprehensive income (loss):
Changes in fair value of derivative instruments accounted for as cash flow hedges		(28,840)		(65,094)
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss	(25,778)	9,522	(53,121)	24,091
Total other comprehensive loss	(25,778)	(19,318)	(53,121)	(41,003)
Comprehensive loss	(85,321)	(43,712)	(59,185)	(82,849)
Comprehensive loss attributable to non-controlling interests	51,130	32,242	12,182	56,039
Comprehensive loss attributable to unitholders’/owner’s interest	$ (34,191)	$ (11,470)	$ (47,003)	$ (26,810)

COMBINED CONSOLIDATED STATEMEN5

COMBINED CONSOLIDATED STATEMENT OF UNITHOLDERS'/OWNER'S EQUITY (Unaudited) - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands	Total	Series A Preferred Equity	Common Unitholders' Equity	Owner's Equity	Accumulated Other Comprehensive Income	Non-Controlling Interest
Balance at Dec. 31, 2014	$ 915,215			$ 147,308	$ 54,008	$ 713,899
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015	(10,475)			(10,475)
Net distribution to owner’s interest prior to the transfer of assets on February 27, 2015	(19,758)			(19,758)
Net assets contributed by owner to Atlas Energy Group, LLC			$ 117,075	$ (117,075)
Issuance of units , number of units		1,600,000	26,010,766
Issuance of units	40,000	$ 40,000
Distributions to non-controlling interests	(62,421)					(62,421)
Net issued and unissued units under incentive plan	5,110		$ 806			4,304
Non-controlling interests’ capital contributions	143,863					143,863
Distribution equivalent rights paid on unissued units under incentive plans	(410)					(410)
Distribution payable	3,937	(334)				4,271
Atlas Growth Partners, L.P.’s subscriptions receivable	34,675					34,675
Gain on sale from subsidiary unit issuances			2,915			(2,915)
Distributions paid to preferred equity unitholders	(667)	(667)
Other comprehensive loss	(53,121)				(21,382)	(31,739)
Net income (loss)	4,411		(15,147)			19,558
Balance at Jun. 30, 2015	$ 1,000,359	$ 38,999	$ 105,649		$ 32,626	$ 823,085
Balance units at Jun. 30, 2015		1,600,000	26,010,766

COMBINED CONSOLIDATED STATEMEN6

COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$ (6,064)	$ (41,846)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		87,732	112,445
Unrealized gain on derivatives	[1]	(71,808)
Amortization of deferred financing costs		15,670	4,329
Non-cash compensation expense		5,083	4,353
(Gain) loss on asset sales and disposal		(86)	1,591
Distributions paid to non-controlling interests		(62,831)	(66,709)
Equity income in unconsolidated companies		(154)	(476)
Distributions received from unconsolidated companies		838	686
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other		92,497	(9,809)
Accounts payable and accrued liabilities		(98,913)	(27,899)
Net cash used in operating activities		(38,036)	(23,335)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(82,609)	(106,229)
Net cash paid for acquisitions		(49,060)	(517,453)
Other		(2,079)	(2,171)
Net cash used in investing activities		(133,748)	(625,853)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities		589,348	838,000
Repayments under credit facilities		(570,203)	(676,750)
Net proceeds from subsidiary long term debt			97,500
Net proceeds from issuance of Series A units		40,000
Net proceeds from issuance of subsidiary units to the public		123,885	436,418
Net distributions to owner		(19,758)	(30,413)
Net distributions paid to unitholders		(667)
Deferred financing costs, distribution equivalent rights and other		(9,102)	(9,415)
Net cash provided by financing activities		153,503	655,340
Net change in cash and cash equivalents		(18,281)	6,152
Cash and cash equivalents, beginning of year		58,358	10,625
Cash and cash equivalents, end of period		$ 40,077	$ 16,777
[1]	Recognized in gain on mark-to-market derivatives.

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	NOTE 1—BASIS OF PRESENTATION Atlas Energy Group, LLC is a Delaware limited liability company formed in October 2011 (the “Company”). At June 30, 2015, the Company’s operations primarily consisted of its ownership interests in the following: · 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 25.0% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in Atlas Resource Partners, L.P. (“ARP”), a publicly traded Delaware master limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”), with operations in basins across the United States. As part of its exploration and production activities, ARP sponsors and manages tax-advantaged investment partnerships (“Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas and oil production activities; ● 80.0% general partner interest and a 1.2% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States. On June 30, 2015, AGP concluded a private placement offering, during which it issued $233.0 million of its common limited partner units. Of the $233.0 million of gross funds raised, the Company purchased $5.0 million common limited partner units; and ● 15.9% general partner interest and 12.0% limited partner interest in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, which incubate new MLPs and invest in existing MLPs. The accompanying combined consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2014 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 (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Company’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 full year ending 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 Principles of Consolidation and Combination The consolidated balance sheet at June 30, 2015 and the related combined consolidated statement of operations for the three and six months ended June 30, 2015, subsequent to the transfer of assets on February 27, 2015 include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the six months ended June 30, 2015 prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three and six months ended June 30, 2014 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates. In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment. The Company combines the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated. In accordance with established practice in the oil and gas industry, the Company’s combined consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. The Company’s combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics (see “ Property, Plant and Equipment Use of Estimates The preparation of the Company’s combined consolidated 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 disclosure of contingent assets and liabilities that exist at the date of the Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. 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 month’s 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” Receivables Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At June 30, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets. Inventory The Company had $8.5 million and $8.9 million of inventory at June 30, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method. Property, Plant and Equipment Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. 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. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Company’s results of operations. The Company’s subsidiaries follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet. The Company’s subsidiaries’ depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for 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 costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators. 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 Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. Impairment of Long-Lived Assets The Company and its subsidiaries review 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 for that asset to its estimated fair value if such carrying amount exceeds the fair value. The review of 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 Company’s subsidiaries’ plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Company’s subsidiaries estimate 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 particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. 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 Company and ARP cannot predict what reserve revisions may be required in future periods. ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partnership agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value. Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three and six months ended June 30, 2015 and 2014. Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Company recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Company for the three and six months ended June 30, 2015 and 2014. The impairment of proved properties during the year ended December 31, 2014 related to the carrying amounts of these gas and oil properties being in excess of the Company’s estimate of their fair values at December 31, 2014. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement. Capitalized Interest ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.6% and 6.0% for the three months ended June 30, 2015 and 2014, respectively, and 6.4% and 5.8% for the six months ended June 30, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $4.1 million and $3.1 million for the three months ended June 30, 2015 and 2014, respectively, and $8.0 million and $5.7 million for the six months ended June 30, 2015 and 2014, respectively. Intangible Assets ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives. The following table reflects the components of intangible assets being amortized at June 30, 2015 and December 31, 2014 (in thousands): June 30, December 31, Estimated 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,770 ) (13,653 ) Net Carrying Amount $ 574 $ 691 Amortization expense on intangible assets was $0.1 million for both the three and six months ended June 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2 Goodwill At June 30, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and six months ended June 30, 2015 and 2014. ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. Derivative Instruments ARP and AGP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. Asset Retirement Obligations The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company’s subsidiaries also recognize a liability for future asset retirement obligations in the current period 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 Company‘s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. ARP Preferred Units In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units, while the remaining 39,654 Class B ARP Preferred Units were converted into common units on July 25, 2015. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In April 2015, ARP issued 255,000 of its newly created 10.75% Class E ARP Preferred Units (“Class E ARP Preferred Units”). The initial quarterly distribution on the Class E ARP Preferred Units was $0.6793 per unit, representing the distribution for the period from April 14, 2015 through July 15, 2015. Subsequent to July 15, 2015, ARP will pay future quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference. Income Taxes The Company, ARP, AGP, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of June 30, 2015 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements. Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three and six months ended June 30, 2015 and 2014. The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of June 30, 2015. Net Income (Loss) Per Common Unit Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common unitholders units outstanding during the period. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Company’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands, except unit data): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Net loss $ (59,543 ) $ (24,394 ) $ (6,064 ) $ (41,846 ) Loss (income) attributable to non-controlling interests 38,745 18,383 (19,558 ) 28,691 Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — 6,011 10,475 13,155 Net loss utilized in the calculation of net income attributable to common unitholders per unit (1) $ (20,798 ) $ — $ (15,147 ) $ — (1) Net income attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. For the three months ended June 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 67,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the three and six months ended June 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. The following table sets forth the reconciliation of the Company’s weighted average number of common unitholder units used to compute basic net income (loss) attributable to common unitholders per unit with those used to compute diluted net income (loss) attributable to common unitholders per unit (in thousands): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Weighted average number of common unitholders per unit—basic 26,011 — 26,011 — Add effect of dilutive incentive awards (1) — — — — Add effect of dilutive convertible preferred units (1) — — — — Weighted average number of common unitholders per unit—diluted 26,011 — 26,011 — (1) For the three months ended June 30, 2015, 750,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2015, 567,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the three and six months ended June 30, 2015, potential common units issuable upon conversion of the Company’s Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. Revenue Recognition Natural gas and oil production . The Company’s subsidiaries’ gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, 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 poi

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Acquisitions	NOTE 3—ACQUISITIONS ARP’s Rangely Acquisition On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% senior notes due 2021 (“7.75% ARP Senior Notes”) (see Note 7) and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Company’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing. ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred. The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): Assets: Prepaid expenses and other $ 4,041 Property, plant and equipment 405,416 Other assets, net 2,888 Total assets acquired $ 412,345 Liabilities: Accrued liabilities 2,117 Asset retirement obligation 1,305 Total liabilities assumed 3,422 Net assets acquired $ 408,923 Other Acquisitions ARP’s Arkoma Acquisition On June 5, 2015, ARP completed the acquisition of the Company’s coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price through the issuance of 6,500,000 common limited partner units (see Note 12). The Arkoma Acquisition had an effective date of January 1, 2015. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control (see Note 2). ARP’s and AGP’s Eagle Ford Acquisition On November 5, 2014, ARP and AGP completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $343.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by AGP at closing, and approximately $140.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, AGP made its first installment payment of $35.0 million related to its Eagle Ford Acquisition. Prior to the March 31, 2015 installment, ARP, AGP, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, AGP paid $28.3 million and ARP issued $20.0 million of its Class D ARP Preferred Units (see Note 12) to satisfy the second installment related to the Eagle Ford Acquisition. On June 30, 2015, AGP paid $16.2 million and ARP paid $1.3 million to satisfy the third installment related to the Eagle Ford Acquisition. At June 30, 2015, ARP’s and AGP’s aggregate remaining deferred portion of the purchase price was $39.2 million, which consisted of $17.5 million and $21.7 million payments due on September 30, 2015 and December 31, 2015, respectively. ARP’s issuance of Class D ARP Preferred Units represents a non-cash transaction for statement of cash flow purposes during the six months ended June 30, 2015. ARP’s GeoMet Acquisition On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments (the “GeoMet Acquisition”), with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

Property, Plant and Equipment

Property, Plant and Equipment	6 Months Ended
	Jun. 30, 2015
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	NOTE 4—PROPERTY, PLANT AND EQUIPMENT The following is a summary of property, plant and equipment at the dates indicated (in thousands): June 30, December 31, Estimated 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 460,423 $ 535,893 Pre-development costs 9,067 7,378 Wells and related equipment 3,106,326 3,096,562 Total proved properties 3,575,816 3,639,833 Unproved properties 331,820 217,321 Support equipment 43,384 37,359 Total natural gas and oil properties 3,951,020 3,894,513 Pipelines, processing and compression facilities 50,738 49,547 2 – 40 Rights of way 829 830 20 – 40 Land, buildings and improvements 9,202 9,160 3 – 40 Other 18,245 17,936 3 – 10 4,030,034 3,971,986 Less – accumulated depreciation, depletion and amortization (1,637,378 ) (1,552,697 ) $ 2,392,656 $ 2,419,289 During the three and six months ended June 30, 2015, the Company recognized $0.1 million of gain on asset sales and disposals. During the six months ended June 30, 2014, the Company recognized $1.6 million of loss on asset sales and disposals, primarily related to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farm out agreement. There were no asset impairments for the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, the Company recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on the Company’s combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. These impairments related to the carrying amounts of gas and oil properties being in excess of the Company’s subsidiaries’ estimates of their fair values at December 31, 2014. The estimates of fair values of these gas and oil properties were impacted by, among other factors, the deterioration of commodity prices at the respective dates of measurement. During the six months ended June 30, 2015 and 2014, the Company recognized $29.0 million and $39.4 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Company’s combined consolidated statement of cash flows.

Other Assets

Other Assets	6 Months Ended
	Jun. 30, 2015
Other Assets Noncurrent Disclosure [Abstract]
Other Assets	NOTE 5—OTHER ASSETS The following is a summary of other assets at the dates indicated (in thousands): June 30, December 31, 2015 2014 Deferred financing costs, net of accumulated amortization of $36,345 and $20,675 at June 30, 2015 and December 31, 2014, respectively $ 47,277 $ 46,120 Investment in Lightfoot 20,523 21,123 Rabbi Trust 5,670 3,925 Security deposits 231 229 ARP notes receivable 3,886 3,866 Other 5,205 5,348 $ 82,792 $ 80,611 Deferred financing costs. Deferred financing costs are recorded at cost and amortized over the terms of the respective debt agreements (see Note 7). Amortization expense of the Company’s and its subsidiaries’ deferred financing costs was $3.0 million and $2.3 million for the three months ended June 30, 2015 and 2014, respectively, and $6.2 million and $4.3 million for the six months ended June 30, 2015 and 2014, respectively, which was recorded within interest expense on the Company’s combined consolidated statements of operations. During the six months ended June 30, 2015, the Company recognized $5.2 million for accelerated amortization of deferred financing costs associated with Atlas Energy, L.P.’s credit facility and term loan. There was no accelerated amortization of deferred financing costs for the Company during the three months ended June 30, 2015 and 2014 and the six months ended June 30, 2014. During the six months ended June 30, 2015, ARP recognized $4.3 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility. There was no accelerated amortization of deferred financing costs for ARP during the three months ended June 30, 2015 and 2014 and during the six months ended June 30, 2014. ARP notes receivable. At June 30, 2015 and December 31, 2014, ARP had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Company’s combined consolidated balance sheets. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain closing conditions, including an extension fee of 1.0% of the outstanding principal balance. The Company recognized interest income within other, net on the Company’s combined consolidated statements of operations of approximately $22,000 and $23,000, respectively, for the three months ended June 30, 2015 and 2014, and approximately $43,000 and $46,000 for the six months ended June 30, 2015 and 2014, respectively. At June 30, 2015 and December 31, 2014, ARP recorded no allowance for credit losses within the Company’s combined consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the ARP notes receivable. Investment in Lightfoot. At June 30, 2015, the Company had an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the Board. Lightfoot L.P. focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt. The Company accounts for its investment in Lightfoot under the equity method of accounting. During both the three months ended June 30, 2015 and 2014, the Company recognized equity income of approximately $0.3 million within other, net on the Company’s combined consolidated statements of operations. During the six months ended June 30, 2015 and 2014, the Company recognized equity income of approximately $0.2 million and $0.5 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the three months ended June 30, 2015 and 2014, the Company received net cash distributions of approximately $0.4 million and $0.3 million, respectively. During the six months ended June 30, 2015 and 2014, the Company received net cash distributions of approximately $0.8 million and $0.7 million, respectively.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	NOTE 6—ASSET RETIREMENT OBLIGATIONS The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of their respective gas and oil wells and related facilities. The Company’s subsidiaries also recognize a liability for their respective 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 Company’s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. The estimated liability for asset retirement obligations was based on 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 was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Company’s subsidiaries have no assets legally restricted for purposes of settling asset retirement obligations. Except for the Company’s subsidiaries’ gas and oil properties, there were no other material retirement obligations associated with tangible long-lived assets. ARP proportionately consolidates its ownership interest of the asset retirement obligations of its Drilling Partnerships. At June 30, 2015, the Drilling Partnerships had $45.4 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintains the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of June 30, 2015, ARP has withheld approximately $3.3 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP 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, ARP’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 ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP will assume the related asset retirement obligations of the limited partners. A reconciliation of the Company’s subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): Three Months Ended Six Months Ended 2015 2014 2015 2014 Asset retirement obligations, beginning of period $ 109,504 $ 92,927 $ 108,101 $ 91,214 Liabilities incurred 47 7,345 216 7,947 Liabilities settled (199 ) (332 ) (546 ) (549 ) Accretion expense 1,585 1,515 3,166 2,843 Asset retirement obligations, end of period $ 110,937 $ 101,455 $ 110,937 $ 101,455 The above accretion expense was included in depreciation, depletion and amortization in the Company’s combined consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations and other in the Company’s combined consolidated balance sheets. During the year ended December 31, 2014, AGP incurred $0.1 million of future plugging and abandonment liabilities within purchase accounting related to the acquisition it consummated during the period. During the year ended December 31, 2014, ARP incurred $7.0 million of future plugging and abandonment liabilities within purchase accounting related to the acquisitions it consummated during the period (see Note 3). During the three and six months ended June 30, 2014, ARP incurred $6.6 million of future plugging and abandonment liabilities within purchase accounting for the Rangely and GeoMet acquisitions it consummated during the period (see Note 3). No future plugging and abandonment liabilities related to consummated acquisitions were incurred during the three and six months ended June 30, 2015.

Debt

Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Debt	NOTE 7—DEBT Total debt consists of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Term loan facilities $ 77,371 $ 148,125 ARP revolving credit facility 550,000 696,000 ARP term loan facility 243,033 — ARP 7.75% Senior Notes—due 2021 374,581 374,544 ARP 9.25% Senior Notes—due 2021 323,998 323,916 Total debt 1,568,983 1,542,585 Less current maturities (77,371 ) (1,500 ) Total long-term debt $ 1,491,612 $ 1,541,085 Term Loan Facilities On February 27, 2015, the Company entered into a credit agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provides for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million (the “Interim Term Loan Facility”) and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million (the “Term Loan A Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). The proceeds from the issuance of the Term Loan Facilities were used to fund a portion of the Company’s $150.0 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s term loan (see Note 2). At June 30, 2015, $77.4 million was outstanding under the Term Loan Facilities, net of $5.3 million of unamortized discount. The Interim Term Loan Facility matures on August 27, 2015 and the Term Loan A Facility matures on February 26, 2016. The Company’s obligations under the Term Loan Facilities are secured on a first priority basis by security interests in substantially all of the assets of the Company and its material subsidiaries, including all equity interests directly held by the Company, New Atlas Holdings, LLC, or any other guarantor, and all tangible and intangible property. Borrowings under the Term Loan Facilities bear interest, at the Company’s option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. The Company has the right at any time to prepay any borrowings outstanding under the Term Loan Facilities, without premium or penalty, provided the Interim Term Loan Facility is repaid prior to the Term Loan A Facility. Subject to certain exceptions, the Company may also be required to prepay all or a portion of the Term Loan Facilities in certain instances, including the following: if, at any time, the Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, the Company if the Company the Company if the Company the Company if the Company it The Credit Agreement contains customary covenants that limit the Company’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. The Company was in compliance with these covenants as of June 30, 2015. Based on the definitions contained in the Credit Agreement, at June 30, 2015, the Company’s Total Leverage Ratio was 2.7 to 1.0. In June 2015, the Company prepaid $33.1 million on the Term Loan Facilities in connection with the Arkoma Acquisition (see Note 3). Atlas Energy Term Loan Facility On July 31, 2013, Atlas Energy entered into a $240.0 million secured term loan facility with a group of outside investors (the “Term Facility”). At December 31, 2014, $148.1 million of the Term Facility was attributable to the Company. The Term Facility had a maturity date of July 31, 2019. Borrowings under the Term Facility bore interest, at Atlas Energy’s election, at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance was due. At December 31, 2014, the weighted average interest rate on outstanding borrowings under the Term Facility was 6.5%. In connection with Atlas Energy’s merger with Targa, the Term Facility was repaid in full on February 27, 2015. ARP Credit Facility ARP is a party to a Second Amended and Restated Credit Agreement dated July 31, 2013, as amended, with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “ARP Credit Agreement”), which provides for a senior secured revolving credit facility with a borrowing base of $750.0 million as of June 30, 2015. ARP’s borrowing base is scheduled for semi-annual redeterminations on July 1, 2015 and November 1, 2015 and thereafter on May 1 and November 1 of each year. In July 2015, the scheduled determination by the lenders reaffirmed ARP’s $750.0 million borrowing base. The ARP Credit Agreement also provides that ARP’s borrowing base will be reduced by 25% of the stated amount of any senior notes issued, or additional second lien debt incurred, after July 1, 2015. At June 30, 2015, $550.0 million was outstanding under the credit facility. Up to $20.0 million of the revolving credit facility may be in the form of standby letters of credit, of which $4.3 million was outstanding at June 30, 2015. ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor. Borrowings under the credit facility bear interest, at ARP’s election, at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00% ) The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance 5.25 ARP Term Loan Facility On February 23, 2015, ARP entered into a Second Lien Credit Agreement with certain lenders and Wilmington Trust, National Association, as administrative agent. The Second Lien Credit Agreement provides for a second lien term loan in an original principal amount of $250.0 million (the “ARP Term Loan Facility”). The ARP Term Loan Facility matures on February 23, 2020. The ARP Term Loan Facility is presented net of unamortized discount of $7.0 million at June 30, 2015. ARP has the option to prepay the ARP Term Loan Facility at any time, and is required to offer to prepay the ARP Term Loan Facility with 100% of the net cash proceeds from the issuance or incurrence of any debt and 100% of the excess net cash proceeds from certain asset sales and condemnation recoveries. ARP is also required to offer to prepay the ARP Term Loan Facility upon the occurrence of a change of control. All prepayments are subject to the following premiums, plus accrued and unpaid interest: · the make-whole premium (plus an additional amount if such prepayment is optional and funded with proceeds from the issuance of equity) for prepayments made during the first 12 months after the closing date; · 4.5% of the principal amount prepaid for prepayments made between 12 months and 24 months after the closing date; · 2.25% of the principal amount prepaid for prepayments made between 24 months and 36 months after the closing date; and · no premium for prepayments made following 36 months after the closing date. ARP’s obligations under the ARP Term Loan Facility are secured on a second priority basis by security interests in all of its assets and those of its restricted subsidiaries (the “Loan Parties”) that guarantee ARP’s existing first lien revolving credit facility. In addition, the obligations under the ARP Term Loan Facility are guaranteed by ARP’s material restricted subsidiaries. Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans. At June 30, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%. The Second Lien Credit Agreement contains customary covenants that limit ARP’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in ARP’s existing first lien revolving credit facility, including, among others, restrictions on swap agreements, debt of unrestricted subsidiaries, drilling and operating agreements and the sale or discount of receivables. ARP was in compliance with these covenants as of June 30, 2015. Under the Second Lien Credit Agreement, ARP may elect to add one or more incremental term loan tranches to the ARP Term Loan Facility so long as the aggregate outstanding principal amount of the ARP Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020. Senior Notes At June 30, 2015, ARP had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% ARP Senior Notes”). The 7.75% ARP Senior Notes were presented net of a $0.4 million unamortized discount as of June 30, 2015. Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 7.75% ARP Senior Notes. At June 30, 2015, ARP had $324.0 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% ARP Senior Notes”). The 9.25% ARP Senior Notes were presented net of a $ 1.0 In connection with the issuance of $75.0 million of 9.25% ARP Senior Notes on October 14, 2014, ARP entered into a registration rights agreement whereby it agreed to (a) file an exchange offer registration statement with the SEC to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 11, 2015. On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015 and expired on May 13, 2015. The 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are guaranteed by certain of ARP’s material subsidiaries. The guarantees under the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes are full and unconditional and joint and several and any subsidiaries of ARP, other than the subsidiary guarantors, are minor. There are no restrictions on ARP’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries. The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets. ARP was in compliance Cash payments for interest by the Company and its subsidiaries on their respective borrowings were $51.7 million and $30.9 million for the six months ended June 30, 2015 and 2014, respectively.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments	NOTE 8—DERIVATIVE INSTRUMENTS AGP and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. AGP and ARP enter 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 or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, AGP and ARP receive or pay a fixed price and receive or remit 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. On January 1, 2015, ARP 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 Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, are being reclassified to the Company’s combined consolidated statements of operations at the time the originally hedged physical transactions settle. AGP and ARP enter 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 Company’s combined consolidated 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 Company’s combined consolidated balance sheets as the initial value of the options. AGP and ARP enter into commodity future option and collar contracts to achieve more predictable cash flows by hedging their exposure to changes in commodity prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“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. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index. Derivatives are recorded on the Company’s combined consolidated balance sheets as assets or liabilities at fair value. The Company reflected net derivative assets on its combined consolidated balance sheets of $264.9 million and $274.9 million at June 30, 2015 and December 31, 2014, respectively. Of the $32.6 million of net gain in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet related to derivatives at June 30, 2015, the Company will reclassify $17.9 million of gains to its combined consolidated statement of operations over the next twelve month period as these contracts expire with the remaining gains of $14.7 million gains being reclassified to the Company’s combined consolidated statements of operations in later periods as the remaining contracts expire. During the three and six months ended June 30, 2014, no amounts were reclassified from other comprehensive loss related to derivative instruments entered into during that same period. The following table summarizes the commodity derivative activity for the three and six months ended June 30, 2015 (in thousands): Three Months Ended Six Months Ended Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ (25,778 ) $ (53,121 ) Portion of settlements attributable to subsequent mark to market gains (14,922 ) (30,125 ) Total cash settlements on commodity derivative contracts (40,700 ) (83,246 ) 2015 Unrealized gains prior to settlement (2) 3,678 6,881 Unrealized gain (loss) on open derivative contracts at June 30, 2015, net of amounts recognized in income in prior year (2) (30,574 ) 71,808 Gains (losses) on mark-to-market derivatives $ (26,896 ) $ 78,689 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. The Company had $40.7 million and $9.5 million of cash settlements during the three months ended June 30, 2015 and 2014, respectively, and $83.2 million and $24.1 million of cash settlements during the six months ended June 30, 2015 and 2014, respectively. As the underlying prices and terms in the Company’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. Atlas Growth At May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of the date hereof, the lenders under the credit facility have no commitment to lend to AGP under the credit facility but AGP and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. The credit facility may be amended in the future if AGP and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit the ability of AGP and its subsidiaries to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. AGP was in compliance with these covenants as of June 30, 2015. In addition, AGP’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions. AGP has elected not to utilize hedge accounting for its derivative instruments. The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined consolidated balance sheets as of the dates indicated (in thousands): Gross Gross Net Amount of Offsetting Derivative Assets As of June 30, 2015 Current portion of derivative assets $ 31 $ (1 ) $ 30 Long-term portion of derivative assets 18 — 18 Total derivative assets $ 49 $ (1 ) $ 48 As of December 31, 2014 Current portion of derivative assets $ — $ — $ — Long-term portion of derivative assets — — — Total derivative assets $ — $ — $ — Gross Gross Net Amount of Offsetting Derivative Liabilities As of June 30, 2015 Current portion of derivative liabilities $ (1 ) $ 1 $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ (1 ) $ 1 $ — As of December 31, 2014 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — At June 30, 2015, AGP had the following commodity derivatives: Crude Oil – Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (2) 2015 27,000 $ 61.000 $ 17 2016 18,000 $ 63.150 19 2017 9,000 $ 65.000 12 AGP’s net assets $ 48 (1) (2) Atlas Resource The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined consolidated balance sheets as of the dates indicated (in thousands): Gross Gross Net Amount of Offsetting Derivative Assets As of June 30, 2015 Current portion of derivative assets $ 114,982 $ (272 ) $ 114,710 Long-term portion of derivative assets 150,601 (439 ) 150,162 Total derivative assets $ 265,583 $ (711 ) $ 264,872 As of December 31, 2014 Current portion of derivative assets $ 144,357 $ (98 ) $ 144,259 Long-term portion of derivative assets 130,972 (370 ) 130,602 Total derivative assets $ 275,329 $ (468 ) $ 274,861 Gross Gross Net Amount of Offsetting Derivative Liabilities As of June 30, 2015 Current portion of derivative liabilities $ (272 ) $ 272 $ — Long-term portion of derivative liabilities (439 ) 439 — Total derivative liabilities $ (711 ) $ 711 $ — As of December 31, 2014 Current portion of derivative liabilities $ (98 ) $ 98 $ — Long-term portion of derivative liabilities (370 ) 370 — Total derivative liabilities $ (468 ) $ 468 $ — At June 30, 2015, ARP had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 26,832,200 $ 4.193 $ 34,433 2016 53,546,300 $ 4.229 55,981 2017 49,920,000 $ 4.219 41,808 2018 40,800,000 $ 4.170 28,491 2019 15,960,000 $ 4.017 7,636 $ 168,349 Natural Gas – Costless Collars Production Option Type Volumes Average Floor Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 1,560,000 $ 4.157 $ 1,996 2015 Calls sold 1,560,000 $ 5.002 (4 ) $ 1,992 Natural Gas – Put Options – Drilling Partnerships Production Option Type Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 720,000 $ 4.000 $ 795 2016 Puts purchased 1,440,000 $ 4.150 1,519 $ 2,314 Natural Gas – WAHA Basis Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (7) 2015 2,400,000 $ (0.090 ) $ 41 $ 41 Natural Gas Liquids – Natural Gasoline Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (8) 2015 2,520,000 $ 1.936 $ 1,758 $ 1,758 Natural Gas Liquids – Propane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (4) 2015 4,032,000 $ 1.016 $ 2,133 $ 2,133 Natural Gas Liquids – Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (5) 2015 756,000 $ 1.248 $ 467 $ 467 Natural Gas Liquids – Iso Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (6) 2015 756,000 $ 1.263 $ 460 $ 460 Natural Gas Liquids – Crude Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 84,000 $ 85.651 $ 1,960 2017 60,000 $ 83.780 1,183 $ 3,143 Crude Oil – Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 966,000 $ 87.653 $ 26,301 2016 1,557,000 $ 81.471 29,889 2017 1,140,000 $ 77.285 15,237 2018 1,080,000 $ 76.281 11,561 2019 540,000 $ 68.371 993 $ 83,981 Crude Oil – Costless Collars Production Option Type Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 Puts purchased 9,750 $ 83.846 $ 234 2015 Calls sold 9,750 $ 110.654 — $ 234 ARP’s net assets $ 264,872 (1) (2) (3) (4) (5) (6) (7) (8) . In June 2012, ARP entered into natural gas put option contracts which related to future natural gas production of the Drilling Partnerships. Therefore, a portion of any unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At June 30, 2015, net unrealized derivative assets of $2.3 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. During the three months and six months ended June 30, 2015, the Company received approximately $ 4.9 8 At June 30, 2015, ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships have the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under its revolving credit facility (see Note 7), ARP is required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. Each participating Drilling Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the general partner of the Drilling Partnership. ARP, as general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnerships’ ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets.

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 9—FAIR VALUE OF FINANCIAL INSTRUMENTS The Company and its subsidiaries have established a hierarchy to measure their financial instruments at fair value which requires them 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 Company’s and its subsidiaries’ 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 Company and its subsidiaries use a market approach fair value methodology to value the assets and liabilities for their outstanding derivative contracts (see Note 8) and the Company’s rabbi trust assets (see Note 14). ARP and AGP manage and report derivative assets and liabilities on the basis of their exposure to market risks and credit risks by counterparty. ARP’s and AGP’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. Investments held in the Company’s rabbi trust are publicly traded equity and debt securities and are therefore defined as Level 1 fair value measurements. Information for the Company and its subsidiaries’ assets and liabilities measured at fair value at June 30, 2015 and December 31, 2014 was as follows (in thousands): Level 1 Level 2 Level 3 Total As of June 30, 2015 Assets, gross Rabbi trust $ 5,670 $ — $ — $ 5,670 ARP Commodity swaps — 261,039 — 261,039 ARP Commodity puts — 2,314 — 2,314 ARP Commodity options — 2,230 — 2,230 AGP Commodity swaps — 49 — 49 Total assets, gross 5,670 265,632 — 271,302 Liabilities, gross ARP Commodity swaps — (707 ) — (707 ) ARP Commodity options — (4 ) — (4 ) AGP Commodity swaps — (1 ) — (1 ) Total derivative liabilities, gross — (712 ) — (712 ) Total assets, fair value, net $ 5,670 $ 264,920 $ — $ 270,590 As of December 31, 2014 Assets, gross Rabbi trust $ 3,925 $ — $ — $ 3,925 ARP Commodity swaps — 267,242 — 267,242 ARP Commodity puts — 2,767 — 2,767 ARP Commodity options — 5,320 — 5,320 Total assets, gross 3,925 275,329 — 279,254 Liabilities, gross ARP Commodity swaps — (401 ) — (401 ) ARP Commodity options — (67 ) — (67 ) Total derivative liabilities, gross — (468 ) — (468 ) Total assets, fair value, net $ 3,925 $ 274,861 $ — $ 278,786 Other Financial Instruments The estimated fair values of the Company’s and its subsidiaries’ other financial instruments have been determined based upon their assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Company and its subsidiaries could realize upon the sale or refinancing of such financial instruments. The Company’s and its subsidiaries’ other current assets and liabilities on its combined consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of the Company’s and ARP’s debt at June 30, 2015 and December 31, 2014, which consist principally of ARP’s senior notes, borrowings under the Company’s term loan facilities, and borrowings under ARP’s term loan and revolving credit facilities, were $1,390.4 million and $1,363.4 million, respectively, compared with the carrying amounts of $1,569.0 million and $1,542.6 million, respectively. The carrying values of outstanding borrowings under the respective revolving and term loan credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP senior notes were based upon the market approach and calculated using the yields of the ARP senior notes as provided by financial institutions and thus were categorized as Level 3 values. Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis The Company’s subsidiaries estimate the fair value of their respective 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 Company’s subsidiaries and estimated inflation rates (see Note 6). Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2015 and 2014 was as follows (in thousands): Three Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 47 $ 47 $ 7,345 $ 7,345 Total $ 47 $ 47 $ 7,345 $ 7,345 Six Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 216 $ 216 $ 7,947 $ 7,947 Total $ 216 $ 216 $ 7,947 $ 7,947 The Company’s subsidiaries estimate the fair value of their long-lived assets in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances. No impairments were recognized during the three and six months ended June 30, 2015 and 2014. During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and AGP completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford Acquisition as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of June 30, 2015 are subject to change as the final valuations have not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Company’s subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuation and are subject to change.

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 10—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with Drilling Partnerships . ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 11—COMMITMENTS AND CONTINGENCIES General Commitments ARP is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. ARP has structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally for Drilling Partnerships with this structure, ARP is not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP may immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it does not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on its historical experience, as of June 30, 2015, the management of ARP believes that any such estimated liability for redemptions of limited partner interests in Drilling Partnerships which allow such transactions would not be material. While its historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the three months ended June 30, 2015 and 2014, $0.5 million and $0.4 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. For the six months ended June 30, 2015 and 2014, $1.1 million and $3.8 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses. In connection with the Eagle Ford Acquisition (see Note 3), ARP guaranteed the timely payment of the deferred portion of the purchase price that is to be paid by AGP. Pursuant to the agreement between ARP and AGP, ARP will have the right to receive some or all of the assets acquired by AGP in the event of its failure to contribute its portion of any deferred payments. ARP’s and AGP’s deferred purchase obligations are included within deferred acquisition purchase price on the Company’s combined consolidated balance sheets at June 30, 2015 and December 31, 2014 (see Note 3). In connection with ARP’s GeoMet Acquisition (see Note 3), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of June 30, 2015 were as follows: 2015— $2.3 million; 2016— $2.3 million; 2017— $1.9 million; 2018— $1.8 million; 2019— $1.8 million; thereafter— $6.5 million. In connection with ARP’s acquisition of assets from EP Energy E&P Company, L.P. on July 31, 2013 (the “EP Energy Acquisition”), ARP acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of ARP’s firm transportation obligations as of June 30, 2015 were as follows: 2015— $4.2 million; 2016— $2.1 million; and 2017 to 2019— none. As of June 30, 2015, the Company’s subsidiaries are committed to expend approximately $10.9 million on drilling and completion expenditures. Legal Proceedings The Company and its subsidiaries are parties to various routine legal proceedings arising out of the ordinary course of its business. Management of the Company and its subsidiaries believe that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company’s financial condition or results of operations.

Issuances of Units

Issuances of Units	6 Months Ended
	Jun. 30, 2015
Proceeds From Issuance Or Sale Of Equity [Abstract]
Issuances of Units	NOTE 12—ISSUANCES OF UNITS The Company recognizes gains on ARP’s and AGP’s equity transactions as credits to unitholders’ equity on its combined consolidated balance sheets rather than as income on its combined consolidated statements of operations. These gains represent the Company’s portion of the excess net offering price per unit of each of ARP’s and AGP’s common units over the book carrying amount per unit (see Note 2). On February 27, 2015 the Company issued and sold an aggregate of 1.6 million of its newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of the Company’s management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively or (ii) the monthly equivalent of any cash distribution declared by the Company to holders of the Company’s common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units will be convertible into the Company’s units at the option of the holder at any time following the later of (i) the one year anniversary of the distribution and (ii) receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company. Atlas Resource Partners In May 2015, in connection with the Arkoma Acquisition (see Note 3), ARP issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of approximately $49.5 million. ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s revolving credit facility. In April 2015, ARP issued 255,000 of its 10.75% Class E ARP Preferred Units at a public offering price of $25.00 per unit for net proceeds of approximately $6.0 million. ARP pays distributions on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00. In October 2014, in connection with the Eagle Ford Acquisition (see Note 3), ARP issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition. On March 31, 2015, to partially pay its portion of the quarterly installment related to the Eagle Ford Acquisition, ARP issued an additional 800,000 Class D ARP Preferred Units to the seller at a value of $25.00 per unit. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 13). ARP pays cumulative distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. The Class D and Class E ARP Preferred Units rank senior to ARP’s common units and Class C ARP Preferred Units with respect to the payment of distributions and distributions upon a liquidation event. The Class D and Class E ARP Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by ARP or converted into its common units in connection with a change in control. At any time on or after October 15, 2019 for the Class D ARP Preferred Units and April 15, 2020 for the ARP Class E Preferred Units, ARP may, at its option, redeem the such preferred units in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, ARP may redeem such preferred units following certain changes of control, as described in the respective Certificates of Designation. If ARP does not exercise this redemption option upon a change of control, then holders of such preferred units will have the option to convert the preferred units into a number of ARP common units as set forth in the respective Certificates of Designation. If ARP exercises any of its redemption rights relating to such preferred units, the holders will not have the conversion right described above with respect to the preferred units called for redemption. In August 2014, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP may sell from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the existing trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP will pay each of the Agents a commission, which in each case shall not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP may also sell common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal would be pursuant to the terms of a separate terms agreement between ARP and such Agent. During the six months ended June 30, 2015, ARP issued 2,885,824 common limited partner units under the equity distribution program for net proceeds of $21.4 million, net of $0.6 million in commissions paid. In May 2014, in connection with the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million. In March 2014, in connection with the GeoMet Acquisition (see Note 3), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million. Atlas Growth Partners Through June 30, 2015, AGP issued approximately $233.0 million of its common limited partner units through a private placement offering. Of the $233.0 million of gross funds raised, we purchased $5.0 million common limited partner units during the offering. In connection with the issuance of ARP’s and AGP’s unit offerings during the six months ended June 30, 2015, the Company recorded gains of $2.9 million within unitholders’ equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheet and combined consolidated statement of unitholders’/owner’s equity. For the year ended December 31, 2014, the Company recorded gains of $40.5 million within equity and a corresponding decrease in non-controlling interests on its combined consolidated balance sheets and combined consolidated statement of equity.

Cash Distributions

Cash Distributions	6 Months Ended
	Jun. 30, 2015
Distributions Made To Members Or Limited Partners [Abstract]
Cash Distributions	NOTE 13—CASH DISTRIBUTIONS The Company’s Cash Distributions. The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders. Distributions declared by the Company related to its Class A preferred units were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Total Cash Total Cash May 15, 2015 March 31, 2015 $ — $ 333 June 12, 2015 April 30, 2015 $ — $ 334 July 15, 2015 May 31, 2015 $ — $ 334 On July 22, 2015, the Company declared a monthly distribution of $0.3 ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter. If ARP’s common unit distributions in any quarter exceed specified target levels, the Company will receive between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP pays quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the liquidation preference. ARP will pay distributions on the Class E ARP Preferred Units at a rate of 10.75% per annum of the stated liquidation preference of $25.00, or $0.671875 per unit paid on a quarterly basis. Distributions declared by ARP from January 1, 2014 through June 30, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Cash Total Cash Total Cash (1) Total Cash March 17, 2014 January 31, 2014 $ 0.1933 $ 12,718 $ 1,467 $ 1,055 April 14, 2014 February 28, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,055 May 15, 2014 March 31, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,054 June 13, 2014 April 30, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 July 15, 2014 May 31, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 August 14, 2014 June 30, 2014 $ 0.1966 $ 16,029 $ 1,492 $ 1,377 September 12, 2014 July 31, 2014 $ 0.1966 $ 16,028 $ 1,493 $ 1,378 October 15, 2014 August 31, 2014 $ 0.1966 $ 16,032 $ 1,491 $ 1,378 November 14, 2014 September 30, 2014 $ 0.1966 $ 16,032 $ 1,492 $ 1,378 December 15, 2014 October 31, 2014 $ 0.1966 $ 16,033 $ 1,491 $ 1,378 January 14, 2015 November 30, 2014 $ 0.1966 $ 16,779 $ 745 (1) $ 1,378 February 13, 2015 December 31, 2014 $ 0.1966 $ 16,782 $ 745 (1) $ 1,378 March 17, 2015 January 31, 2015 $ 0.1083 $ 9,284 $ 643 (1) $ 203 April 14, 2015 February 28, 2015 $ 0.1083 $ 9,347 $ 643 (1) $ 204 May 15, 2015 March 31, 2015 $ 0.1083 $ 9,444 $ 643 (1) $ 206 June 12, 2015 April 30, 2015 $ 0.1083 $ 10,179 $ 642 (1) $ 221 July 15, 2015 May 31, 2015 $ 0.1083 $ 10,304 $ 643 (1) $ 223 (1) Includes payments for the Class B and Class C preferred unit monthly distributions. Date Cash Distribution Paid For the Period Cash Total Cash Total Cash January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.616927 $ 1,974 $ — April 15, 2015 Quarter Ended March 31, 2015 $ 0.539063 $ 2,156 $ — At June 30, 2015, ARP had 4.0 million of its 8.625% Class D ARP Preferred Units outstanding (see Note 12). On July 15, 2015, ARP paid a quarterly distribution of $0.5390625 per unit, or $2.2 million, for the second quarter of 2015 to holders of record as of July 1, 2015. On July 22, 2015, ARP declared a monthly distribution of $ $ On July 15, 2015, ARP paid an initial quarterly distribution of $0.6793 per Class E ARP Preferred Unit, or $0.2 million, for the second quarter of 2015 to Class E ARP Preferred Unitholders of record as of July 1, 2015.

Benefit Plans

Benefit Plans	6 Months Ended
	Jun. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Benefit Plans	NOTE 14—BENEFIT PLANS 2015 Long-Term Incentive Plan The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Company. The 2015 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”). Under the 2015 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,250,000 units. At June 30, 2015, the Company had 2,764,210 phantom units and unit options outstanding under the 2015 LTIP, with 2,485,790 phantom units and unit options available for grant. In the case of awards held by eligible employees, following a “change in control”, as defined in the 2015 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2015 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. In connection with a change in control, the LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, subject to the terms of any award agreements and employment agreements to which the Company (or any affiliate) and any Participant are party, may take one or more of the following actions (with discretion to differentiate between individual Participants and awards for any reason): · cause awards to be assumed or substituted by the surviving entity (or a parent, subsidiary or affiliate of such surviving entity); · accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards shall vest (and, with respect to options, become exercisable) as to the units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; · provide for the payment of cash or other consideration to Participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); · terminate all or some awards upon the consummation of the change-in-control transaction, but only if the LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and · make such other modifications, adjustments or amendments to outstanding awards as the LTIP Committee deems necessary or appropriate. 2015 Phantom Units. A phantom unit entitles a Participant to receive a Company common unit or its then-Fair Market Value in cash or other securities or property, upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Distribution Equivalent Rights (“DERs”), which are the right to receive cash, securities, or property per phantom unit in an amount equal to, and at the same time as, the cash distributions or other distributions of securities or property the Company makes on a common unit during the period such phantom unit is outstanding. Generally, phantom units to be granted to employees under the 2015 LTIP will vest over a designated period of time and phantom units granted to non-employee directors generally vest over a four year period, 25% per year. Of the phantom units outstanding under the 2015 LTIP at June 30, 2015, there are 906,663 units that will vest within the following twelve months. The director phantom units outstanding under the 2015 LTIP at June 30, 2015 include DERs. No amounts were paid during the three and six months ended June 30, 2015 and 2014 with respect to DERs. The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 68,910 $ 9.07 — $ — Granted 2,695,300 6.43 — — Vested (1) — — — — Forfeited — — — — Outstanding, end of period (2)(3)(4) 2,764,210 $ 6.50 — $ — Non-cash compensation expense recognized (in thousands) $ 926 $ — Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year — $ — — $ — Granted 2,764,210 6.50 — — Vested (1) — — — — Forfeited — — — — Outstanding, end of period (2)(3)(4) 2,764,210 $ 6.50 — $ — Non-cash compensation expense recognized (in thousands) $ 946 $ — (1) (2) The aggregate intrinsic value of phantom unit awards outstanding at June 30, 2015 was approximately $13.8 million. (3) At June 30, 2015, the Company had approximately $16.7 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awards 2015 Unit Options. A unit option entitles a Participant to receive a common unit of the Company upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option shall not be less than the fair market value of the Company’s common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time. There are no unit options outstanding under the 2015 LTIP at June 30, 2015. No cash was received from the exercise of options for the three and six months ended June 30, 2015 and 2014, respectively. Restricted Units Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. Rabbi Trust In 2011, the Company established an excess 401(k) plan relating to certain executives. In connection with the plan, the Company established a “rabbi” trust for the contributed amounts. At June 30, 2015 and December 31, 2014, the Company reflected $5.7 million and $3.9 million, respectively, related to the value of the rabbi trust within other assets, net on its combined consolidated balance sheets, and recorded corresponding liabilities of $5.7 million and $3.9 million as of those same dates within asset retirement obligations and other on its combined consolidated balance sheets. During the three and six months ended June 30, 2015 and 2014, no distributions were made to participants related to the rabbi trust. ARP Long-Term Incentive Plan ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under ARP’s 2012 LTIP, the ARP LTIP Committee may grant awards of phantom units, restricted units, or unit options for an aggregate of 2,900,000 common limited partner units of ARP. At June 30, 2015, ARP had 1,864,057 phantom units, restricted units and unit options outstanding under the ARP LTIP with 134,308 phantom units, restricted units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value. In the case of awards held by eligible employees, following a “change in control”, as defined in the ARP LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the ARP LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full. In connection with a change in control, the ARP LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any participant, but subject to the terms of any award agreements and employment agreements to which the Company, as general partner, (or any affiliate) and any participant are party, may take one or more of the following actions (with discretion to differentiate between individual participants and awards for any reason): · cause awards to be assumed or substituted by the surviving entity (or affiliate of such surviving entity); · accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards will vest (and, with respect to options, become exercisable) as to ARP’s common units that otherwise would have been unvested so that participants (as holders of awards granted under the new equity plan) may participate in the transaction; · provide for the payment of cash or other consideration to participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards); · terminate all or some awards upon the consummation of the change-in-control transaction, but only if the ARP LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and · make such other modifications, adjustments or amendments to outstanding awards or the new equity plan as the ARP LTIP Committee deems necessary or appropriate. ARP Phantom Units . Phantom units represent rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units are subject to terms and conditions determined by the ARP LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee may grant DERs, which are the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by ARP with respect to a common unit during the period that the underlying phantom unit is outstanding. Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant. Of the phantom units outstanding under the ARP LTIP at June 30, 2015, 191,408 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at June 30, 2015 include DERs. During the three months ended June 30, 2015 and 2014, ARP paid $0.2 million and $0.4 million, respectively, with respect to the ARP LTIP’s DERs. During the six months ended June 30, 2015 and 2014, ARP paid $0.5 million and $1.1 million, respectively, with respect to the ARP LTIP’s DERs. These amounts were recorded as reductions of equity on the Company’s combined consolidated balance sheets. The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 632,010 $ 22.37 812,308 $ 24.35 Granted 9,730 8.50 223,523 20.29 Vested and issued (1) (222,358 ) 24.07 (131,374 ) 24.69 Forfeited (8,125 ) 23.04 (3,250 ) 24.80 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 803 $ 1,590 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 799,192 $ 22.70 839,808 $ 24.31 Granted 9,730 8.50 227,023 20.30 Vested and issued (1) (389,540 ) 24.02 (146,874 ) 24.48 Forfeited (8,125 ) 23.04 (18,750 ) 23.00 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 3,317 $ 3,321 (1) The intrinsic values of phantom unit awards vested and issued during the three months ended June 30, 2015 and 2014 were $2.0 million and $2.5 million, respectively, and $3.6 million and $2.9 million during the six months ended June 30, 2015 and 2014, respectively. (2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2015 2.6 (3) There were approximately $24,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 (4) The intrinsic values of phantom unit awards vested, but not yet issued at June 30, 2015 and 2014 were $0.2 million and $1.5 million, respectively. At June 30, 2015, ARP had approximately $3.2 million in unrecognized compensation expense related to unvested phantom units outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.8 years. ARP Unit Options . A unit option is the right to purchase an ARP common unit in the future at a predetermined price (the exercise price). The exercise price of each ARP unit option is determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of ARP’s common unit on the date of grant of the option. The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant. There were 106,949 unit options outstanding under the ARP LTIP at June 30, 2015 that will vest within the following twelve months. No cash was received from the exercise of options for the three and six months ended June 30, 2015 and 2014. The following table sets forth the ARP LTIP unit option activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 1,453,300 $ 24.66 1,472,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (500 ) 25.14 (3,750 ) 24.67 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 61 $ 420 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 1,458,300 $ 24.66 1,482,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (5,500 ) 24.71 (13,750 ) 24.40 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 892 $ 1,033 (1) No options were exercised during the three and six months ended June 30, 2015 and 2014. (2) The weighted average remaining contractual life for outstanding options at June 30, 2015 was 6.9 (3) There was no aggregate intrinsic value of options outstanding at June 30, 2015. The aggregate intrinsic value of options outstanding at June 30, 2014 was approximately $2,000. (4) The weighted average remaining contractual life for exercisable options at June 30, 2015 was 6.9 no At June 30, 2015, ARP had approximately $0.1 million in unrecognized compensation expense related to unvested unit options outstanding under the ARP LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.8 years. ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted. Restricted Units Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the ARP LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the ARP LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units.

Operating Segment Information

Operating Segment Information	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Operating Segment Information	NOTE 15—OPERATING SEGMENT INFORMATION The Company’s operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Atlas Resource: Revenues $ 96,125 $ 138,897 $ 339,714 $ 300,254 Operating costs and expenses (75,822 ) (85,342 ) (163,640 ) (190,153 ) Depreciation, depletion and amortization expense (42,494 ) (59,680 ) (85,485 ) (111,499 ) Gain (loss) on asset sales and disposal 97 9 86 (1,594 ) Interest expense (24,716 ) (13,263 ) (49,913 ) (26,451 ) Segment income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Atlas Growth: Revenues $ 1,865 $ 2,457 $ 4,176 $ 3,025 Operating costs and expenses (3,243 ) (2,889 ) (8,312 ) (4,737 ) Depreciation, depletion and amortization expense (782 ) (726 ) (2,247 ) (946 ) Segment loss $ (2,160 ) $ (1,158 ) $ (6,383 ) $ (2,658 ) Corporate and other: Revenues $ 257 $ 250 $ 156 $ 472 General and administrative (2,359 ) (1,299 ) (22,574 ) (4,620 ) Gain on asset sales and disposal — 3 — 3 Interest expense (8,471 ) (2,811 ) (18,025 ) (5,600 ) Segment loss $ (10,573 ) $ (3,857 ) $ (40,443 ) $ (9,745 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Atlas Resource $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Atlas Growth (2,160 ) (1,158 ) (6,383 ) $ (2,658 ) Corporate and other (10,573 ) $ (3,857 ) $ (40,443 ) $ (9,745 ) Net loss $ (59,543 ) $ (24,394 ) $ (6,064 ) $ (41,846 ) Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource $ 96,125 $ 138,897 $ 339,714 $ 300,254 Atlas Growth 1,865 2,457 4,176 $ 3,025 Corporate and other 257 250 156 $ 472 Total revenues $ 98,247 $ 141,604 $ 344,046 $ 303,751 Capital expenditures: Atlas Resource $ 26,993 $ 54,718 $ 69,491 $ 94,649 Atlas Growth 3,175 7,092 13,118 11,580 Corporate and other — — — — Total capital expenditures $ 30,168 $ 61,810 $ 82,609 $ 106,229 June 30, December 31, 2015 2014 Balance sheet: Goodwill: Atlas Resource $ 13,639 $ 13,639 Atlas Growth — — Corporate and other — — $ 13,639 $ 13,639 Total assets: Atlas Resource $ 2,701,094 $ 2,791,553 Atlas Growth 229,981 190,161 Corporate and other 13,763 44,601 $ 2,944,838 $ 3,026,315

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	NOTE 16—SUBSEQUENT EVENTS The Company On July 22, 2015, the Company declared a monthly cash distribution of $0.3 Atlas Resource Cash Distributions. On July 22, 2015, ARP declared a monthly distribution of $ 0.1083 per common unit for the month of June 30, 2015. The $ 11.2 million distribution, including $0.2 million and $0.6 million to the general partner and preferred limited partners, respectively, will be paid on August 14, 2015 to unitholders of record at the close of business on August 7, 2015. On July15, 2015, ARP paid a quarterly distribution of $0.5390625 per Class D ARP Preferred Unit, or $2.2 million, for the second quarter of 2015 to Class D ARP Preferred Unitholders of record as of July 1, 2015. On July 15, 2015, ARP paid an initial quarterly distribution of $0.6793 per Class E ARP Preferred Unit, or $0.2 million, for the period from April 14, 2015 through July 15, 2015 of 2015 to Class E ARP Preferred Unitholders of record as of July 1, 2015.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Principles of Consolidation and Combination	Principles of Consolidation and Combination The consolidated balance sheet at June 30, 2015 and the related combined consolidated statement of operations for the three and six months ended June 30, 2015, subsequent to the transfer of assets on February 27, 2015 include the accounts of the Company and its subsidiaries. The Company’s combined consolidated balance sheet at December 31, 2014, the combined consolidated statement of operations for the six months ended June 30, 2015 prior to the transfer of assets on February 27, 2015, and the combined consolidated statement of operations for the three and six months ended June 30, 2014 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, Atlas Energy’s net investment in the Company is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive the financial statements of the Company. Actual balances and results could be different from those estimates. Transactions between the Company and other Atlas Energy operations have been identified in the combined consolidated financial statements as transactions between affiliates. In connection with Atlas Energy’s merger with Targa and the concurrent Separation, the Company was required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with generally accepted accounting principles, the Company included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within its historical financial statements. Atlas Energy’s other historical borrowings were allocated to the Company’s historical financial statements in the same ratio. The Company used proceeds from the issuance of its Series A preferred units (see Note 12) and borrowings under its term loan credit facilities (see Note 7) to fund the $150.0 million payment. The Company combines the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interest as equity investments, as the Company controls these entities through its general partnership interests therein. As such, the non-controlling interests in ARP and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated. In accordance with established practice in the oil and gas industry, the Company’s combined consolidated financial statements include its pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest. Such interests generally approximate 30%. The Company’s combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of ARP’s Drilling Partnerships. Rather, ARP calculates these items specific to its own economics (see “ Property, Plant and Equipment
Use of Estimates	Use of Estimates The preparation of the Company’s combined consolidated 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 disclosure of contingent assets and liabilities that exist at the date of the Company’s combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Company’s combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired and liabilities assumed. Such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive the historical financial statements of the Company. 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 month’s 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”
Receivables	Receivables Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. In evaluating the realizability of accounts receivable, management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness, as determined by management’s review of customers’ credit information. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At June 30, 2015 and December 31, 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.
Inventory	Inventory The Company had $8.5 million and $8.9 million of inventory at June 30, 2015 and December 31, 2014, respectively, which were included within prepaid expenses and other current assets on its combined consolidated balance sheets. The Company values inventories at the lower of cost or market. The Company’s inventories, which consist primarily of ARP’s materials, pipes, supplies and other inventories, were principally determined using the average cost method.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. 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. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the Company’s results of operations. The Company’s subsidiaries follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet. The Company’s subsidiaries’ depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for 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 costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators. 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 Company’s combined consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s combined consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s combined consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets The Company and its subsidiaries review 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 for that asset to its estimated fair value if such carrying amount exceeds the fair value. The review of 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 Company’s subsidiaries’ plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Company’s subsidiaries estimate 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 particular, ARP’s reserve estimates for its investment in the Drilling Partnerships are based on its own assumptions rather than its proportionate share of the limited partnerships’ reserves. These assumptions include ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. ARP’s lower operating and administrative costs result from the limited partners in the Drilling Partnerships paying to ARP operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions could result in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. 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 Company and ARP cannot predict what reserve revisions may be required in future periods. ARP’s method of calculating its reserves may result in reserve quantities and values which are greater than those which would be calculated by the Drilling Partnerships, which ARP sponsors and owns an interest in but does not control. ARP’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may be unable to recover due to the Drilling Partnerships’ legal structure. ARP may have to pay additional consideration in the future as a Drilling Partnership’s wells become uneconomic to the Drilling Partnership under the terms of the Drilling Partnership’s drilling and operating agreement in order to recover these excess reserves, in addition to ARP becoming responsible for paying associated future operating, development and plugging costs of the well interests acquired, and to acquire any additional residual interests in the wells held by the Drilling Partnership’s limited partners. The acquisition of any such uneconomic well interest from the Drilling Partnership by ARP is governed under the Drilling Partnership’s limited partnership agreement. In general, ARP will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon ARP’s determination of fair market value. Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate that the Company’s subsidiaries will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. There were no impairments of unproved gas and oil properties recorded on the Company’s combined consolidated statements of operations for the three and six months ended June 30, 2015 and 2014. Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2014, the Company recognized $562.6 million of asset impairment related to oil and gas properties within property, plant and equipment, net on its combined consolidated balance sheet primarily for ARP’s Appalachian and mid-continent operations, which was reduced by $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. Asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. There were no impairments of proved gas and oil properties recorded by the Company for the three and six months ended June 30, 2015 and 2014. The impairment of proved properties during the year ended December 31, 2014 related to the carrying amounts of these gas and oil properties being in excess of the Company’s estimate of their fair values at December 31, 2014. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of commodity prices at the date of measurement.
Capitalized Interest	Capitalized Interest ARP capitalizes interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.6% and 6.0% for the three months ended June 30, 2015 and 2014, respectively, and 6.4% and 5.8% for the six months ended June 30, 2015 and 2014, respectively. The amounts of interest capitalized by ARP were $4.1 million and $3.1 million for the three months ended June 30, 2015 and 2014, respectively, and $8.0 million and $5.7 million for the six months ended June 30, 2015 and 2014, respectively.
Intangible Assets	Intangible Assets ARP has recorded intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. ARP amortizes contracts acquired on a declining balance method over their respective estimated useful lives. The following table reflects the components of intangible assets being amortized at June 30, 2015 and December 31, 2014 (in thousands): June 30, December 31, Estimated 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,770 ) (13,653 ) Net Carrying Amount $ 574 $ 691 Amortization expense on intangible assets was $0.1 million for both the three and six months ended June 30, 2015 and 2014. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2015 - $0.2
Goodwill	Goodwill At June 30, 2015 and December 31, 2014, the Company had $13.6 million of goodwill recorded in connection with ARP’s prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three and six months ended June 30, 2015 and 2014. ARP tests goodwill for impairment at each year end by comparing its reporting unit estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units. ARP’s management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ARP’s, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest. Therefore, once the above fair value calculations have been determined, ARP also considers the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in ARP’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in ARP’s industry to determine whether those valuations appear reasonable in management’s judgment. ARP’s management will continue to evaluate goodwill at least annually or when impairment indicators arise. As a result of its goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on the Company’s combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014.
Derivative Instruments	Derivative Instruments ARP and AGP enter into certain financial contracts to manage their exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the combined consolidated balance sheets are measured as either an asset or liability at fair value. Changes in the fair value of derivative instruments are recognized currently in the Company’s combined consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Company and ARP discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Company’s combined consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the combined consolidated statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on the Company’s consolidated balance sheets and reclassified to the Company’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.
Asset Retirement Obligations	Asset Retirement Obligations The Company’s subsidiaries recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities (see Note 6). The Company’s subsidiaries also recognize a liability for future asset retirement obligations in the current period 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 Company‘s subsidiaries also consider the estimated salvage value in the calculation of depreciation, depletion and amortization.
ARP Preferred Units	ARP Preferred Units In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million newly created convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units, while the remaining 39,654 Class B ARP Preferred Units were converted into common units on July 25, 2015. In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million newly created convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution. In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of its 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP will pay quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference. In April 2015, ARP issued 255,000 of its newly created 10.75% Class E ARP Preferred Units (“Class E ARP Preferred Units”). The initial quarterly distribution on the Class E ARP Preferred Units was $0.6793 per unit, representing the distribution for the period from April 14, 2015 through July 15, 2015. Subsequent to July 15, 2015, ARP will pay future quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference.
Income Taxes	Income Taxes The Company, ARP, AGP, Lightfoot and the respective subsidiaries thereof are not subject to U.S. federal and most state income taxes. The partners of these entities are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the accompanying combined consolidated financial statements. Certain corporate subsidiaries of ARP are subject to federal and state income tax. The federal and state income taxes related to the Company and these corporate subsidiaries were immaterial to the combined consolidated financial statements as of June 30, 2015 and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for these corporate subsidiaries in the accompanying combined consolidated financial statements. Each of the entities which comprise the Company evaluates tax positions taken or expected to be taken in the course of preparing their respective tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Company’s management does not believe it has any tax positions taken within its combined consolidated financial statements that would not meet this threshold. The Company’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Company has not recognized any such potential interest or penalties in its combined consolidated financial statements for the three and six months ended June 30, 2015 and 2014. The entities comprising the Company file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the entities comprising the Company are no longer subject to income tax examinations by major tax authorities for years prior to 2011 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of June 30, 2015.
Net Income (Loss) Per Common Unit	Net Income (Loss) Per Common Unit Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities, if applicable, by the weighted average number of common unitholders units outstanding during the period. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. The Company’s phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plans and incentive compensation agreements (see Note 14), contain non-forfeitable rights to distribution equivalents of the Company. The participation rights result in a non-contingent transfer of value each time the Company declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands, except unit data): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Net loss $ (59,543 ) $ (24,394 ) $ (6,064 ) $ (41,846 ) Loss (income) attributable to non-controlling interests 38,745 18,383 (19,558 ) 28,691 Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — 6,011 10,475 13,155 Net loss utilized in the calculation of net income attributable to common unitholders per unit (1) $ (20,798 ) $ — $ (15,147 ) $ — (1) Net income attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. For the three months ended June 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 67,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the three and six months ended June 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. The following table sets forth the reconciliation of the Company’s weighted average number of common unitholder units used to compute basic net income (loss) attributable to common unitholders per unit with those used to compute diluted net income (loss) attributable to common unitholders per unit (in thousands): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Weighted average number of common unitholders per unit—basic 26,011 — 26,011 — Add effect of dilutive incentive awards (1) — — — — Add effect of dilutive convertible preferred units (1) — — — — Weighted average number of common unitholders per unit—diluted 26,011 — 26,011 — (1) For the three months ended June 30, 2015, 750,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2015, 567,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the three and six months ended June 30, 2015, potential common units issuable upon conversion of the Company’s Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.
Revenue Recognition	Revenue Recognition Natural gas and oil production . The Company’s subsidiaries’ gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, 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 Company’s subsidiaries have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty. ARP’s Drilling Partnerships . Certain energy activities are conducted by ARP through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP is deployed to drill and complete wells included within the partnership. As ARP deploys Drilling Partnership investor capital, it recognizes certain management fees it is entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP has Drilling Partnership investor capital that has not yet been deployed, it will recognize a current liability titled “Liabilities Associated with Drilling Contracts” on the Company’s combined consolidated balance sheets. After the Drilling Partnership well is completed and turned in line, ARP is entitled to receive additional operating and management fees, which are included within well services and administration and oversight revenue, respectively, on a monthly basis while the well is operating. In addition to the management fees it is entitled to receive for services provided, ARP is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximate 30%. ARP recognizes its Drilling Partnership management fees in the following manner: • Well construction and completion • Administration and oversight • Well services. While the historical structure has varied, ARP has generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment falls below the agreed upon rate, ARP recognizes subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that will achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflect that the agreed upon limited partner investment return will be achieved during the subordination period, ARP will recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. ARP’s gathering and processing revenue . Gathering and processing revenue includes gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charges a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby ARP remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charges the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. The Company’s subsidiaries’ gas and oil production operations accrue 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 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” for further description). The Company had unbilled revenues at June 30, 2015 and December 31, 2014 of $52.9 million and $85.5 million, respectively, which were included in accounts receivable within its combined consolidated balance sheets.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) includes net income (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 income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Company’s combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 8). The Company does not have any other type of transaction which would be included within other comprehensive income (loss).
Recently Issued Accounting Standards	Recently Issued Accounting Standards In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-06, Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions In March 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30) require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts The recognition and measurement guidance for debt issuance costs would not be affected by the amendments in Update 2015-03. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In January 2015, the FASB issued ASU 2015-01, Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815) – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share is More Akin to Debt or to Equity Certain classes of shares include features that entitle the holders to preferences and rights (such as conversion rights, redemption rights, voting powers, and liquidation and dividend payment preferences) over the other shareholders. Shares that include embedded derivative features are referred to as hybrid financial instruments, which must be separated from the host contract and accounted for as a derivative if certain criteria are met under Subtopic 815-10. One criterion requires evaluating whether the nature of the host contract is more akin to debt or to equity and whether the economic characteristics and risks of the embedded derivative feature are “clearly and closely related” to the host contract. In making that evaluation, an issuer or investor may consider all terms and features in a hybrid financial instrument including the embedded derivative feature that is being evaluated for separate accounting or may consider all terms and features in the hybrid financial instrument except for the embedded derivative feature that is being evaluated for separate accounting. The use of different methods can result in different accounting outcomes for economically similar hybrid financial instruments. Additionally, there is diversity in practice with respect to the consideration of redemption features in relation to other features when determining whether the nature of a host contract is more akin to debt or to equity. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements Going Concern (Subtopic 205-40) In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) 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
Derivatives, Methods of Accounting, Derivative Types	AGP and ARP use a number of different derivative instruments, principally swaps, collars, and options, in connection with their commodity and interest rate price risk management activities. AGP and ARP enter 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 or interest payments on the underlying debt instrument are due. Under commodity-based swap agreements, AGP and ARP receive or pay a fixed price and receive or remit 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.
Derivatives, Methods of Accounting, Hedge Effectiveness	On January 1, 2015, ARP 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 Company’s combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet, are being reclassified to the Company’s combined consolidated statements of operations at the time the originally hedged physical transactions settle.
Derivatives, Basis and Use of Derivatives, Use of Derivatives	AGP and ARP enter 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 Company’s combined consolidated 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 Company’s combined consolidated balance sheets as the initial value of the options.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Schedule of the Components of Intangible Assets Being Amortized	The following table reflects the components of intangible assets being amortized at June 30, 2015 and December 31, 2014 (in thousands): June 30, December 31, Estimated 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,770 ) (13,653 ) Net Carrying Amount $ 574 $ 691
Reconciliation of Net Income (Loss)	The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands, except unit data): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Net loss $ (59,543 ) $ (24,394 ) $ (6,064 ) $ (41,846 ) Loss (income) attributable to non-controlling interests 38,745 18,383 (19,558 ) 28,691 Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — 6,011 10,475 13,155 Net loss utilized in the calculation of net income attributable to common unitholders per unit (1) $ (20,798 ) $ — $ (15,147 ) $ — (1) Net income attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. For the three months ended June 30, 2015, net loss attributable common unitholders per unit is not allocated to approximately 69,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the six months ended June 30, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 67,000 phantom units, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the three and six months ended June 30, 2015, distributions on the Company’s Series A preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.
Reconciliation of the Company's Weighted Average Number of Common Unit holder Units	The following table sets forth the reconciliation of the Company’s weighted average number of common unitholder units used to compute basic net income (loss) attributable to common unitholders per unit with those used to compute diluted net income (loss) attributable to common unitholders per unit (in thousands): Three Months Ended Six Months Ended June 30, 2015 2014 2015 2014 Weighted average number of common unitholders per unit—basic 26,011 — 26,011 — Add effect of dilutive incentive awards (1) — — — — Add effect of dilutive convertible preferred units (1) — — — — Weighted average number of common unitholders per unit—diluted 26,011 — 26,011 — (1) For the three months ended June 30, 2015, 750,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the six months ended June 30, 2015, 567,000 phantom units were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive. For the three and six months ended June 30, 2015, potential common units issuable upon conversion of the Company’s Series A preferred units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2015
Rangely Acquisition
Assets Acquired and Liabilities Assumed in Acquisition	The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands): Assets: Prepaid expenses and other $ 4,041 Property, plant and equipment 405,416 Other assets, net 2,888 Total assets acquired $ 412,345 Liabilities: Accrued liabilities 2,117 Asset retirement obligation 1,305 Total liabilities assumed 3,422 Net assets acquired $ 408,923

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	6 Months Ended
	Jun. 30, 2015
Property Plant And Equipment [Abstract]
Summary of Property, Plant and Equipment	The following is a summary of property, plant and equipment at the dates indicated (in thousands): June 30, December 31, Estimated 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 460,423 $ 535,893 Pre-development costs 9,067 7,378 Wells and related equipment 3,106,326 3,096,562 Total proved properties 3,575,816 3,639,833 Unproved properties 331,820 217,321 Support equipment 43,384 37,359 Total natural gas and oil properties 3,951,020 3,894,513 Pipelines, processing and compression facilities 50,738 49,547 2 – 40 Rights of way 829 830 20 – 40 Land, buildings and improvements 9,202 9,160 3 – 40 Other 18,245 17,936 3 – 10 4,030,034 3,971,986 Less – accumulated depreciation, depletion and amortization (1,637,378 ) (1,552,697 ) $ 2,392,656 $ 2,419,289

Other Assets (Tables)

Other Assets (Tables)	6 Months Ended
	Jun. 30, 2015
Other Assets Noncurrent Disclosure [Abstract]
Summary of Other Assets	The following is a summary of other assets at the dates indicated (in thousands): June 30, December 31, 2015 2014 Deferred financing costs, net of accumulated amortization of $36,345 and $20,675 at June 30, 2015 and December 31, 2014, respectively $ 47,277 $ 46,120 Investment in Lightfoot 20,523 21,123 Rabbi Trust 5,670 3,925 Security deposits 231 229 ARP notes receivable 3,886 3,866 Other 5,205 5,348 $ 82,792 $ 80,611

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of Liability for Well Plugging and Abandonment Costs	A reconciliation of the Company’s subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): Three Months Ended Six Months Ended 2015 2014 2015 2014 Asset retirement obligations, beginning of period $ 109,504 $ 92,927 $ 108,101 $ 91,214 Liabilities incurred 47 7,345 216 7,947 Liabilities settled (199 ) (332 ) (546 ) (549 ) Accretion expense 1,585 1,515 3,166 2,843 Asset retirement obligations, end of period $ 110,937 $ 101,455 $ 110,937 $ 101,455

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Total debt consists of the following at the dates indicated (in thousands): June 30, December 31, 2015 2014 Term loan facilities $ 77,371 $ 148,125 ARP revolving credit facility 550,000 696,000 ARP term loan facility 243,033 — ARP 7.75% Senior Notes—due 2021 374,581 374,544 ARP 9.25% Senior Notes—due 2021 323,998 323,916 Total debt 1,568,983 1,542,585 Less current maturities (77,371 ) (1,500 ) Total long-term debt $ 1,491,612 $ 1,541,085

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivatives Fair Value [Line Items]
Summary of Commodity Derivative Activity	The following table summarizes the commodity derivative activity for the three and six months ended June 30, 2015 (in thousands): Three Months Ended Six Months Ended Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ (25,778 ) $ (53,121 ) Portion of settlements attributable to subsequent mark to market gains (14,922 ) (30,125 ) Total cash settlements on commodity derivative contracts (40,700 ) (83,246 ) 2015 Unrealized gains prior to settlement (2) 3,678 6,881 Unrealized gain (loss) on open derivative contracts at June 30, 2015, net of amounts recognized in income in prior year (2) (30,574 ) 71,808 Gains (losses) on mark-to-market derivatives $ (26,896 ) $ 78,689 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives.
Fair Value of Derivative Instruments Table	The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined consolidated balance sheets as of the dates indicated (in thousands): Gross Gross Net Amount of Offsetting Derivative Assets As of June 30, 2015 Current portion of derivative assets $ 31 $ (1 ) $ 30 Long-term portion of derivative assets 18 — 18 Total derivative assets $ 49 $ (1 ) $ 48 As of December 31, 2014 Current portion of derivative assets $ — $ — $ — Long-term portion of derivative assets — — — Total derivative assets $ — $ — $ — Gross Gross Net Amount of Offsetting Derivative Liabilities As of June 30, 2015 Current portion of derivative liabilities $ (1 ) $ 1 $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ (1 ) $ 1 $ — As of December 31, 2014 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ —
Commodity Derivative Instruments by Type Table	At June 30, 2015, AGP had the following commodity derivatives: Crude Oil – Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (2) 2015 27,000 $ 61.000 $ 17 2016 18,000 $ 63.150 19 2017 9,000 $ 65.000 12 AGP’s net assets $ 48 (1) (2)
Atlas Resource Partners, L.P.
Derivatives Fair Value [Line Items]
Fair Value of Derivative Instruments Table	The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s combined consolidated balance sheets as of the dates indicated (in thousands): Gross Gross Net Amount of Offsetting Derivative Assets As of June 30, 2015 Current portion of derivative assets $ 114,982 $ (272 ) $ 114,710 Long-term portion of derivative assets 150,601 (439 ) 150,162 Total derivative assets $ 265,583 $ (711 ) $ 264,872 As of December 31, 2014 Current portion of derivative assets $ 144,357 $ (98 ) $ 144,259 Long-term portion of derivative assets 130,972 (370 ) 130,602 Total derivative assets $ 275,329 $ (468 ) $ 274,861 Gross Gross Net Amount of Offsetting Derivative Liabilities As of June 30, 2015 Current portion of derivative liabilities $ (272 ) $ 272 $ — Long-term portion of derivative liabilities (439 ) 439 — Total derivative liabilities $ (711 ) $ 711 $ — As of December 31, 2014 Current portion of derivative liabilities $ (98 ) $ 98 $ — Long-term portion of derivative liabilities (370 ) 370 — Total derivative liabilities $ (468 ) $ 468 $ —
Commodity Derivative Instruments by Type Table	At June 30, 2015, ARP had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 26,832,200 $ 4.193 $ 34,433 2016 53,546,300 $ 4.229 55,981 2017 49,920,000 $ 4.219 41,808 2018 40,800,000 $ 4.170 28,491 2019 15,960,000 $ 4.017 7,636 $ 168,349 Natural Gas – Costless Collars Production Option Type Volumes Average Floor Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 1,560,000 $ 4.157 $ 1,996 2015 Calls sold 1,560,000 $ 5.002 (4 ) $ 1,992 Natural Gas – Put Options – Drilling Partnerships Production Option Type Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2015 Puts purchased 720,000 $ 4.000 $ 795 2016 Puts purchased 1,440,000 $ 4.150 1,519 $ 2,314 Natural Gas – WAHA Basis Swaps Production Volumes Average Fair Value (MMBtu) (1) (per MMBtu) (1) (in thousands) (7) 2015 2,400,000 $ (0.090 ) $ 41 $ 41 Natural Gas Liquids – Natural Gasoline Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (8) 2015 2,520,000 $ 1.936 $ 1,758 $ 1,758 Natural Gas Liquids – Propane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (4) 2015 4,032,000 $ 1.016 $ 2,133 $ 2,133 Natural Gas Liquids – Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (5) 2015 756,000 $ 1.248 $ 467 $ 467 Natural Gas Liquids – Iso Butane Fixed Price Swaps Production Volumes Average Fair Value (Gal) (1) (per Gal) (1) (in thousands) (6) 2015 756,000 $ 1.263 $ 460 $ 460 Natural Gas Liquids – Crude Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 84,000 $ 85.651 $ 1,960 2017 60,000 $ 83.780 1,183 $ 3,143 Crude Oil – Fixed Price Swaps Production Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 966,000 $ 87.653 $ 26,301 2016 1,557,000 $ 81.471 29,889 2017 1,140,000 $ 77.285 15,237 2018 1,080,000 $ 76.281 11,561 2019 540,000 $ 68.371 993 $ 83,981 Crude Oil – Costless Collars Production Option Type Volumes Average Fair Value (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2015 Puts purchased 9,750 $ 83.846 $ 234 2015 Calls sold 9,750 $ 110.654 — $ 234 ARP’s net assets $ 264,872 (1) (2) (3) (4) (5) (6) (7) (8) .

Fair Value of Financial Instr31

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Company, ARP Assets and Liabilities Measured at Fair Value	Information for the Company and its subsidiaries’ assets and liabilities measured at fair value at June 30, 2015 and December 31, 2014 was as follows (in thousands): Level 1 Level 2 Level 3 Total As of June 30, 2015 Assets, gross Rabbi trust $ 5,670 $ — $ — $ 5,670 ARP Commodity swaps — 261,039 — 261,039 ARP Commodity puts — 2,314 — 2,314 ARP Commodity options — 2,230 — 2,230 AGP Commodity swaps — 49 — 49 Total assets, gross 5,670 265,632 — 271,302 Liabilities, gross ARP Commodity swaps — (707 ) — (707 ) ARP Commodity options — (4 ) — (4 ) AGP Commodity swaps — (1 ) — (1 ) Total derivative liabilities, gross — (712 ) — (712 ) Total assets, fair value, net $ 5,670 $ 264,920 $ — $ 270,590 As of December 31, 2014 Assets, gross Rabbi trust $ 3,925 $ — $ — $ 3,925 ARP Commodity swaps — 267,242 — 267,242 ARP Commodity puts — 2,767 — 2,767 ARP Commodity options — 5,320 — 5,320 Total assets, gross 3,925 275,329 — 279,254 Liabilities, gross ARP Commodity swaps — (401 ) — (401 ) ARP Commodity options — (67 ) — (67 ) Total derivative liabilities, gross — (468 ) — (468 ) Total assets, fair value, net $ 3,925 $ 274,861 $ — $ 278,786
Schedule of Assets and Liabilities Measured on Non Recurring Basis	Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three and six months ended June 30, 2015 and 2014 was as follows (in thousands): Three Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 47 $ 47 $ 7,345 $ 7,345 Total $ 47 $ 47 $ 7,345 $ 7,345 Six Months Ended June 30, 2015 2014 Level 3 Total Level 3 Total Asset retirement obligations $ 216 $ 216 $ 7,947 $ 7,947 Total $ 216 $ 216 $ 7,947 $ 7,947

Cash Distribution (Distribution

Cash Distribution (Distributions Declared) (Tables)	6 Months Ended
	Jun. 30, 2015
Atlas Resource Partners, L.P.
Schedule of Distributions Made by Partnership	Distributions declared by the Company related to its Class A preferred units were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Total Cash Total Cash May 15, 2015 March 31, 2015 $ — $ 333 June 12, 2015 April 30, 2015 $ — $ 334 July 15, 2015 May 31, 2015 $ — $ 334 Distributions declared by ARP from January 1, 2014 through June 30, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Cash Total Cash Total Cash (1) Total Cash March 17, 2014 January 31, 2014 $ 0.1933 $ 12,718 $ 1,467 $ 1,055 April 14, 2014 February 28, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,055 May 15, 2014 March 31, 2014 $ 0.1933 $ 12,719 $ 1,466 $ 1,054 June 13, 2014 April 30, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 July 15, 2014 May 31, 2014 $ 0.1933 $ 15,752 $ 1,466 $ 1,279 August 14, 2014 June 30, 2014 $ 0.1966 $ 16,029 $ 1,492 $ 1,377 September 12, 2014 July 31, 2014 $ 0.1966 $ 16,028 $ 1,493 $ 1,378 October 15, 2014 August 31, 2014 $ 0.1966 $ 16,032 $ 1,491 $ 1,378 November 14, 2014 September 30, 2014 $ 0.1966 $ 16,032 $ 1,492 $ 1,378 December 15, 2014 October 31, 2014 $ 0.1966 $ 16,033 $ 1,491 $ 1,378 January 14, 2015 November 30, 2014 $ 0.1966 $ 16,779 $ 745 (1) $ 1,378 February 13, 2015 December 31, 2014 $ 0.1966 $ 16,782 $ 745 (1) $ 1,378 March 17, 2015 January 31, 2015 $ 0.1083 $ 9,284 $ 643 (1) $ 203 April 14, 2015 February 28, 2015 $ 0.1083 $ 9,347 $ 643 (1) $ 204 May 15, 2015 March 31, 2015 $ 0.1083 $ 9,444 $ 643 (1) $ 206 June 12, 2015 April 30, 2015 $ 0.1083 $ 10,179 $ 642 (1) $ 221 July 15, 2015 May 31, 2015 $ 0.1083 $ 10,304 $ 643 (1) $ 223 (1) Includes payments for the Class B and Class C preferred unit monthly distributions. Date Cash Distribution Paid For the Period Cash Total Cash Total Cash January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.616927 $ 1,974 $ — April 15, 2015 Quarter Ended March 31, 2015 $ 0.539063 $ 2,156 $ —

Benefit Plans (Tables)

Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2015
2015 Long Term Incentive Plan
Defined Benefit Plan Disclosure [Line Items]
Phantom Unit Activity	The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 68,910 $ 9.07 — $ — Granted 2,695,300 6.43 — — Vested (1) — — — — Forfeited — — — — Outstanding, end of period (2)(3)(4) 2,764,210 $ 6.50 — $ — Non-cash compensation expense recognized (in thousands) $ 926 $ — Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year — $ — — $ — Granted 2,764,210 6.50 — — Vested (1) — — — — Forfeited — — — — Outstanding, end of period (2)(3)(4) 2,764,210 $ 6.50 — $ — Non-cash compensation expense recognized (in thousands) $ 946 $ — (1) (2) The aggregate intrinsic value of phantom unit awards outstanding at June 30, 2015 was approximately $13.8 million. (3)
ARP Long Term Incentive Plan
Defined Benefit Plan Disclosure [Line Items]
Phantom Unit Activity	The following table sets forth the ARP LTIP phantom unit activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 632,010 $ 22.37 812,308 $ 24.35 Granted 9,730 8.50 223,523 20.29 Vested and issued (1) (222,358 ) 24.07 (131,374 ) 24.69 Forfeited (8,125 ) 23.04 (3,250 ) 24.80 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 803 $ 1,590 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 799,192 $ 22.70 839,808 $ 24.31 Granted 9,730 8.50 227,023 20.30 Vested and issued (1) (389,540 ) 24.02 (146,874 ) 24.48 Forfeited (8,125 ) 23.04 (18,750 ) 23.00 Outstanding, end of period (2)(3) 411,257 $ 21.10 901,207 $ 23.29 Vested and not yet issued (4) 24,750 $ 20.39 74,850 $ 24.49 Non-cash compensation expense recognized (in thousands) $ 3,317 $ 3,321 (1) The intrinsic values of phantom unit awards vested and issued during the three months ended June 30, 2015 and 2014 were $2.0 million and $2.5 million, respectively, and $3.6 million and $2.9 million during the six months ended June 30, 2015 and 2014, respectively. (2) The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2015 2.6 (3) There were approximately $24,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 (4) The intrinsic values of phantom unit awards vested, but not yet issued at June 30, 2015 and 2014 were $0.2 million and $1.5 million, respectively.
Unit Option Activity	The following table sets forth the ARP LTIP unit option activity for the periods indicated: Three Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of period 1,453,300 $ 24.66 1,472,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (500 ) 25.14 (3,750 ) 24.67 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 61 $ 420 Six Months Ended June 30, 2015 2014 Number Weighted Number Weighted Outstanding, beginning of year 1,458,300 $ 24.66 1,482,675 $ 24.66 Granted — — — — Exercised (1) — — — — Forfeited (5,500 ) 24.71 (13,750 ) 24.40 Outstanding, end of period (2)(3) 1,452,800 $ 24.66 1,468,925 $ 24.66 Options exercisable, end of period (4) 1,342,976 $ 24.67 734,400 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 892 $ 1,033 (1) No options were exercised during the three and six months ended June 30, 2015 and 2014. (2) The weighted average remaining contractual life for outstanding options at June 30, 2015 was 6.9 (3) There was no aggregate intrinsic value of options outstanding at June 30, 2015. The aggregate intrinsic value of options outstanding at June 30, 2014 was approximately $2,000. (4) The weighted average remaining contractual life for exercisable options at June 30, 2015 was 6.9 no

Operating Segment Information (

Operating Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Operating Segment Data	The Company’s operations include three reportable operating segments: ARP, AGP, and corporate and other. These operating segments reflect the way the Company manages its operations and makes business decisions. Corporate and other includes the Company’s equity investment in Lightfoot (see Note 1), as well as its general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Atlas Resource: Revenues $ 96,125 $ 138,897 $ 339,714 $ 300,254 Operating costs and expenses (75,822 ) (85,342 ) (163,640 ) (190,153 ) Depreciation, depletion and amortization expense (42,494 ) (59,680 ) (85,485 ) (111,499 ) Gain (loss) on asset sales and disposal 97 9 86 (1,594 ) Interest expense (24,716 ) (13,263 ) (49,913 ) (26,451 ) Segment income (loss) $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Atlas Growth: Revenues $ 1,865 $ 2,457 $ 4,176 $ 3,025 Operating costs and expenses (3,243 ) (2,889 ) (8,312 ) (4,737 ) Depreciation, depletion and amortization expense (782 ) (726 ) (2,247 ) (946 ) Segment loss $ (2,160 ) $ (1,158 ) $ (6,383 ) $ (2,658 ) Corporate and other: Revenues $ 257 $ 250 $ 156 $ 472 General and administrative (2,359 ) (1,299 ) (22,574 ) (4,620 ) Gain on asset sales and disposal — 3 — 3 Interest expense (8,471 ) (2,811 ) (18,025 ) (5,600 ) Segment loss $ (10,573 ) $ (3,857 ) $ (40,443 ) $ (9,745 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Atlas Resource $ (46,810 ) $ (19,379 ) $ 40,762 $ (29,443 ) Atlas Growth (2,160 ) (1,158 ) (6,383 ) $ (2,658 ) Corporate and other (10,573 ) $ (3,857 ) $ (40,443 ) $ (9,745 ) Net loss $ (59,543 ) $ (24,394 ) $ (6,064 ) $ (41,846 ) Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource $ 96,125 $ 138,897 $ 339,714 $ 300,254 Atlas Growth 1,865 2,457 4,176 $ 3,025 Corporate and other 257 250 156 $ 472 Total revenues $ 98,247 $ 141,604 $ 344,046 $ 303,751 Capital expenditures: Atlas Resource $ 26,993 $ 54,718 $ 69,491 $ 94,649 Atlas Growth 3,175 7,092 13,118 11,580 Corporate and other — — — — Total capital expenditures $ 30,168 $ 61,810 $ 82,609 $ 106,229 June 30, December 31, 2015 2014 Balance sheet: Goodwill: Atlas Resource $ 13,639 $ 13,639 Atlas Growth — — Corporate and other — — $ 13,639 $ 13,639 Total assets: Atlas Resource $ 2,701,094 $ 2,791,553 Atlas Growth 229,981 190,161 Corporate and other 13,763 44,601 $ 2,944,838 $ 3,026,315

Basis of Presentation (Narrativ

Basis of Presentation (Narrative) (Details) - USD ($) $ in Millions	Feb. 27, 2015	Jun. 30, 2015
Basis Of Presentation [Line Items]
Percentage of interest represented by common units which is effected by pro rata distribution	100.00%
Lightfoot Capital Partners, LP
Basis Of Presentation [Line Items]
General partner ownership interest		15.90%
Common limited partner ownership interest		12.00%
Atlas Resource Partners, L.P.
Basis Of Presentation [Line Items]
General partner ownership interest		100.00%
Common limited partner ownership interest		25.00%
Common limited partner interest in ARP, units		20,962,485
Atlas Resource Partners, L.P. | Preferred Limited Partner Units
Basis Of Presentation [Line Items]
Common limited partner interest in ARP, units		3,749,986
Atlas Growth Partners, L.P
Basis Of Presentation [Line Items]
General partner ownership interest		80.00%
Common limited partner ownership interest		1.20%
Common limited partner units issued		$ 233
Common limited partner units purchased		$ 5

Summary of Significant Accoun36

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	Jul. 25, 2015	Jul. 15, 2015	Jan. 14, 2015	Dec. 23, 2014	Jul. 31, 2013	Apr. 30, 2015	Mar. 31, 2015	Oct. 31, 2014	Jul. 15, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities												$ 570,203,000	$ 676,750,000
Pro-rata share in Drilling Partnerships												30.00%
Allowance for Doubtful Accounts Receivable										$ 0		$ 0		$ 0
Materials, supplies and other inventory										8,500,000		8,500,000		8,900,000
Impairments of Unproved Gas and Oil Properties										0	$ 0	0	0
Asset impairment										0	0	0	0
Future Hedge Gains														82,300,000
Impairments of Proved Gas And Oil Properties										$ 0	$ 0	$ 0	$ 0
Weighted Average Interest Rate Used To Capitalize Interest										6.60%	6.00%	6.40%	5.80%
Interest Costs Capitalized										$ 4,100,000	$ 3,100,000	$ 8,000,000	$ 5,700,000
Amortization of Intangible Assets										100,000	100,000	100,000	100,000
Future Amortization Expense, remainder of 2015										200,000		200,000
Future Amortization Expense, 2016										100,000		100,000
Future Amortization Expense, 2017										100,000		100,000
Future Amortization Expense, 2018										100,000		100,000
Future Amortization Expense, 2019										100,000		100,000
Goodwill										13,639,000		13,639,000		13,639,000
Changes in carrying amount of goodwill										0	$ 0	$ 0	$ 0
Partners unit, issued												2,885,824
Percentage of Preferred Unit Regular Quarterly Cash Distributions												10.75%
Deferred income tax benefit												$ 0
Proportion of amount received on cost incurred to drill												15.00%
Monthly administrative fee per well												$ 75
Gathering Fee Percentage												16.00%
Gathering Fee Percentage Net Margin												3.00%
Unbilled Contracts Receivable										$ 52,900,000		$ 52,900,000		85,500,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Recognition period to receive fees												60 days
Amount of fixed fees received by each well drilled												$ 100,000
Monthly operating fee paid per well												$ 1,000
Return on unhedged revenue percentage												10.00%
Period of return on unhedged revenue												5 years
Maximum
Summary Of Significant Accounting Policies [Line Items]
Recognition period to receive fees												270 days
Amount of fixed fees received by each well drilled												$ 500,000
Monthly operating fee paid per well												$ 2,000
Percentage on unhedged revenue												50.00%
Return on unhedged revenue percentage												12.00%
Period of return on unhedged revenue												8 years
Class E Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued						255,000
Partners' Capital Account, Units, Percentage						10.75%
Preferred Unit Regular Quarterly Cash Distributions Per Unit									$ 0.6793
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after										$ 25		$ 25
Percentage of Preferred Unit Regular Quarterly Cash Distributions						10.75%
Subsequent Event | Class E Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after		$ 2.6875							$ 2.6875
ARP Acquisitions
Summary Of Significant Accounting Policies [Line Items]
Goodwill										$ 13,600,000		$ 13,600,000		13,600,000
Goodwill, Impairment Loss														18,100,000
Preferred stock participation rights												While outstanding, the Class C ARP Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution.
ARP Acquisitions | Class B Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Conversion of Class B preferred units (units)				3,796,900
ARP Acquisitions | Class C Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued					3,700,000
ARP Acquisitions | Class C Preferred Units | Minimum
Summary Of Significant Accounting Policies [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit					$ 0.51
ARP Acquisitions | Preferred class D
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued							800,000	3,200,000
Partners' Capital Account, Units, Percentage								8.625%
Preferred Unit Regular Quarterly Cash Distributions Per Unit			$ 0.616927
Preferred Unit Regular Quarterly Cash Distributions Per Unit there after			$ 2.15625
Percentage of Preferred Unit Regular Quarterly Cash Distributions			8.625%
ARP Acquisitions | Subsequent Event | Class B Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Conversion of Class B preferred units (units)	39,654
Atlas Resource Partners, L.P.
Summary Of Significant Accounting Policies [Line Items]
Asset impairment														562,600,000
Atlas Resource Partners, L.P. | Preferred class D
Summary Of Significant Accounting Policies [Line Items]
Non-controlling interests										$ 103,500,000		$ 103,500,000		$ 78,000,000
Atlas Resource Partners, L.P. | Subsequent Event | Class E Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit		$ 0.6793
Atlas Resource Partners, L.P. | Titan Acquisition
Summary Of Significant Accounting Policies [Line Items]
Preferred stock participation rights												While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution.
Atlas Resource Partners, L.P. | Titan Acquisition | Class B Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued												3,800,000
Atlas Resource Partners, L.P. | Titan Acquisition | Class B Preferred Units | Minimum
Summary Of Significant Accounting Policies [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit												$ 0.40
Drilling Partnership wells
Summary Of Significant Accounting Policies [Line Items]
Gathering Fee Percentage												13.00%
Secured Term Facility
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities												$ 150,000,000
Credit facility					$ 240,000,000
Series A Preferred Units | Secured Term Facility
Summary Of Significant Accounting Policies [Line Items]
Proceeds from Issuance of Convertible Preferred Stock												$ 150,000,000

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Gross Carrying Amount	$ 14,344	$ 14,344
Accumulated Amortization	(13,770)	(13,653)
Net Carrying Amount	$ 574	$ 691
Estimated Useful Lives In Years	13 years

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reconciliation Of Net Income [Line Items]
Net loss	$ (59,543)	$ (24,394)	$ (6,064)	$ (41,846)
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015		(6,011)	$ (10,475)	(13,155)
Antidilutive Phantom Unit Securities Excluded from Computation of Diluted Earnings Attributable to Common Unit Holders Outstanding Units	69,000		67,000
Continuing Operations
Reconciliation Of Net Income [Line Items]
Loss (income) attributable to non-controlling interests	$ 38,745	18,383	$ (19,558)	28,691
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015		$ 6,011	10,475	$ 13,155
Net loss utilized in the calculation of net income attributable to common unitholders per unit	$ (20,798)		$ (15,147)

Summary of Significant Accoun39

Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details) - Jun. 30, 2015 - shares	Total	Total
Accounting Policies [Abstract]
Weighted average number of common unitholders per unit—basic	26,011,000	26,011,000
Weighted average number of common unitholders per unit—diluted	26,011,000	26,011,000
Antidilutive Securities Excluded From Computation Of Diluted Net Income (Loss) Attributable To Common Limited Partners Outstanding Units	750,000	567,000

Acquisitions (Rangely Acquisiti

Acquisitions (Rangely Acquisition) (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	Jun. 30, 2014	May. 31, 2014	Jun. 30, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Partners unit, issued			2,885,824
Rangely Acquisition
Business Acquisition [Line Items]
Partners unit, issued		15,525,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Business Acquisition [Line Items]
Debt instrument, interest rate, stated percentage			7.75%	7.75%
Atlas Resource Partners, L.P. | Rangely Acquisition
Business Acquisition [Line Items]
Business acquisition, percentage of voting interests acquired	25.00%
Business acquisition, cost of acquired entity, cash paid	$ 408.9
Debt instrument, maturity date	Aug. 15, 2021
Business acquisition, effective date of acquisition	Apr. 1, 2014
Business acquisition, purchase price allocation, methodology	ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9).
Business acquisition, purchase price allocation, status	In conjunction with the issuance of ARP’s common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on the Company’s combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.
Business acquisition, cost of acquired entity, transaction costs				$ 11.6
Atlas Resource Partners, L.P. | Rangely Acquisition | 7.75% Senior Notes
Business Acquisition [Line Items]
Proceed from additional senior notes	$ 100
Debt instrument, interest rate, stated percentage	7.75%
Partners unit, issued	15,525,000

Acquisitions (Rangely Acquisi41

Acquisitions (Rangely Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) - Rangely Acquisition $ in Thousands	Jun. 30, 2014USD ($)
Business Acquisition [Line Items]
Prepaid expenses and other	$ 4,041
Property, plant and equipment	405,416
Other assets, net	2,888
Total assets acquired	412,345
Accrued liabilities	2,117
Asset retirement obligation	1,305
Total liabilities assumed	3,422
Net assets acquired	$ 408,923

Acquisitions (Other Acquisition

Acquisitions (Other Acquisition) (Narrative) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Jun. 05, 2015	Mar. 31, 2015	Dec. 31, 2014	Nov. 05, 2014	May. 12, 2014	May. 31, 2015	Mar. 31, 2014	Jun. 30, 2015
Business Acquisition [Line Items]
Partners unit, issued											2,885,824
Arkoma Acquisition
Business Acquisition [Line Items]
Partners unit, issued									6,500,000
ARP’s and AGP’s Eagle Ford Acquisition
Business Acquisition [Line Items]
Business acquisition, date of acquisition agreement											Nov. 5, 2014
Net cash acquired							$ 343
Deferred portion of purchase price							140
Deferred portion of purchase price payable in quarterly installments, beginning date											Dec. 31, 2014
Purchase price represent non-cash transaction			$ 39.2
ARP’s and AGP’s Eagle Ford Acquisition | Scenario Forecast
Business Acquisition [Line Items]
Deferred portion of purchase price	$ 21.7	$ 17.5
ARP’s Geomet Acquisition
Business Acquisition [Line Items]
Partners unit, issued										6,325,000
Business acquisition, effective date of acquisition								Jan. 1, 2014
Cash consideration								$ 97.9
Business acquisition, description of acquired entity								The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.
Atlas Resource Partners, L.P. | Arkoma Acquisition
Business Acquisition [Line Items]
Business acquisition, cost of acquired entity, cash paid				$ 31.5
Partners unit, issued											6,500,000
Business acquisition, effective date of acquisition											Jan. 1, 2015
Atlas Resource Partners, L.P. | ARP’s and AGP’s Eagle Ford Acquisition
Business Acquisition [Line Items]
Cash consideration			1.3				183.1
Atlas Resource Partners, L.P. | ARP’s and AGP’s Eagle Ford Acquisition | Class D Preferred Units
Business Acquisition [Line Items]
Business acquisition, cost of acquired entity, equity interests issued and issuable					$ 20
Atlas Growth Partners, L.P | ARP’s and AGP’s Eagle Ford Acquisition
Business Acquisition [Line Items]
Cash consideration			$ 16.2		$ 28.3		$ 19.9
Deferred portion of purchase price						$ 35

Property, Plant and Equipment43

Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Property Plant And Equipment [Abstract]
Proved properties: Leasehold interests	$ 460,423	$ 535,893
Proved properties: Pre-development costs	9,067	7,378
Proved properties: Wells and related equipment	3,106,326	3,096,562
Total proved properties	3,575,816	3,639,833
Unproved properties	331,820	217,321
Support equipment	43,384	37,359
Total natural gas and oil properties	3,951,020	3,894,513
Pipelines, processing and compression facilities	50,738	49,547
Rights of way	829	830
Land, buildings and improvements	9,202	9,160
Other	18,245	17,936
Total gross property, plant and equipment	4,030,034	3,971,986
Less – accumulated depreciation, depletion and amortization	(1,637,378)	(1,552,697)
Property, plant and equipment, Net, Total	$ 2,392,656	$ 2,419,289

Property, Plant and Equipment44

Property, Plant and Equipment (Useful Life Narrative) (Details)	6 Months Ended
	Jun. 30, 2015
Pipelines, processing and compression facilities | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	2 years
Pipelines, processing and compression facilities | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	40 years
Rights of way | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	20 years
Rights of way | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	40 years
Land, buildings and improvements | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	3 years
Land, buildings and improvements | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	40 years
Other | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	3 years
Other | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	10 years

Property, Plant and Equipment45

Property, Plant and Equipment (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
Property Plant And Equipment [Line Items]
Gain (loss) on asset sales and disposal	$ 97,000	$ 12,000	$ 86,000	$ (1,591,000)
Asset impairment	$ 0	$ 0	0	0
Future Hedge Gains					$ 82,300,000
Non-cash property, plant and equipment additions			$ 29,000,000	$ 39,400,000
Atlas Resource Partners, L.P.
Property Plant And Equipment [Line Items]
Asset impairment					$ 562,600,000

Other Assets (Summary of Other

Other Assets (Summary of Other Assets) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Other Assets [Line Items]
Deferred financing costs, net of accumulated amortization of $36,345 and $20,675 at June 30, 2015 and December 31, 2014, respectively	$ 47,277	$ 46,120
Rabbi Trust	5,670	3,925
Security deposits	231	229
Other	5,205	5,348
Total Other Assets	82,792	80,611
Lightfoot
Other Assets [Line Items]
Investment in Lightfoot	20,523	21,123
Atlas Resource Partners, L.P.
Other Assets [Line Items]
ARP notes receivable	$ 3,886	$ 3,866

Other Assets (Narrative) (Detai

Other Assets (Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Other Assets [Line Items]
Accumulated amortization	$ 36,345,000		$ 36,345,000		$ 20,675,000
Amortization of financing costs	3,000,000	$ 2,300,000	6,200,000	$ 4,300,000
Accelerated amortization of deferred financing costs	$ 0	0	5,200,000	0
Distributions received from unconsolidated companies			$ 838,000	686,000
Lightfoot LP
Other Assets [Line Items]
Equity method investment ownership percentage	12.00%		12.00%
Distributions received from unconsolidated companies	$ 400,000	300,000	$ 800,000	700,000
Lightfoot GP
Other Assets [Line Items]
Equity method investment ownership percentage	15.90%		15.90%
Lightfoot
Other Assets [Line Items]
Equity income in joint ventures	$ 300,000	300,000	$ 200,000	500,000
Atlas Resource Partners, L.P.
Other Assets [Line Items]
Accelerated amortization of deferred financing costs	0	0	4,300,000	0
Allowance for credit loss	0		$ 0		$ 0
Atlas Resource Partners, L.P. | Note Agreement, Option to Extend Maturity Date
Other Assets [Line Items]
Senior notes, maturity date			Mar. 31, 2027
Note agreement extension fee percent			1.00%
Atlas Resource Partners, L.P. | Notes Receivable
Other Assets [Line Items]
Senior notes, maturity date			Mar. 31, 2022
Note agreement interest rate per annum			2.25%
Other interest and dividend income	$ 22,000	$ 23,000	$ 43,000	$ 46,000

Asset Retirement Obligations (R

Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (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	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 110,937,000	$ 101,455,000	$ 110,937,000	$ 101,455,000	$ 108,101,000	$ 109,504,000	$ 92,927,000	$ 91,214,000
Limited Partner Interest | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent	0		0
Relationship With Drilling Partnerships
Asset Retirement Obligations [Line Items]
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships			3,300,000
Relationship With Drilling Partnerships | Limited Partner Interest
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 45,400,000		$ 45,400,000
Atlas Growth Partners, L.P | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent					100,000
Atlas Resource Partners, L.P. | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent		$ 6,600,000		$ 6,600,000	$ 7,000,000

Asset Retirement Obligations 49

Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligation Roll Forward Analysis Roll Forward
Asset retirement obligations, beginning of period	$ 109,504	$ 92,927	$ 108,101	$ 91,214
Liabilities incurred	47	7,345	216	7,947
Liabilities settled	(199)	(332)	(546)	(549)
Accretion expense	1,585	1,515	3,166	2,843
Asset retirement obligations, end of period	$ 110,937	$ 101,455	$ 110,937	$ 101,455

Debt (Schedule of Total Debt Ou

Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total debt	$ 1,568,983	$ 1,542,585
Less current maturities	(77,371)	(1,500)
Total long-term debt	$ 1,491,612	1,541,085
9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.25%
Atlas Energy | Term Loan
Debt Instrument [Line Items]
Term loan facilities	$ 77,371	148,125
Atlas Resource Partners, L.P.
Debt Instrument [Line Items]
Term loan facilities	243,033
Revolving credit facility	550,000	696,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$ 374,581	$ 374,544
Debt instrument, interest rate, stated percentage	7.75%	7.75%
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$ 323,998	$ 323,916
Debt instrument, interest rate, stated percentage	9.25%	9.25%

Debt (Term Loan Facilities) (De

Debt (Term Loan Facilities) (Details) - USD ($)	Feb. 27, 2015	Jun. 30, 2015	Jun. 30, 2014	Jul. 31, 2013
Debt Instrument [Line Items]
Line of Credit Facility, initiation date		Feb. 27, 2015
Repayments under credit facilities		$ 570,203,000	$ 676,750,000
Secured Term Facility
Debt Instrument [Line Items]
Line of Credit Facility, aggregate principal amount				$ 240,000,000
Repayments under credit facilities		$ 150,000,000
Secured Term Loan Facilities
Debt Instrument [Line Items]
Outstanding Term Facility, weighted average interest rate		8.50%
Term Loan
Debt Instrument [Line Items]
Recognized value ratio, description		Recognized Value Ratio (as defined in the Credit Agreement) is less than 2.00 to 1.00, the Company must prepay the Term Loan Facilities and any revolving loans outstanding in an aggregate principal amount necessary to achieve a Recognized Value Ratio of greater than 2.00 to 1.00; the Recognized Value Ratio is equal to the ratio of the Recognized Value
Net cash proceeds from disposition of assets		100.00%
Leverage ratio under condition one		3.75%
Leverage ratio under condition two		3.50%
Total leverage ratio		2.70%
Term Loan | Arkoma Acquisition
Debt Instrument [Line Items]
Prepayment of debt		$ 33,100,000
Term Loan | Maximum
Debt Instrument [Line Items]
Recognized value ratio		2.00%
Term Loan | Minimum
Debt Instrument [Line Items]
Recognized value ratio		2.00%
London Interbank Offered Rate (LIBOR) | Secured Term Loan Facilities
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	7.50%
Federal Funds Effective Swap Rate | Secured Term Loan Facilities
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.50%
One Month L I B O R | Secured Term Loan Facilities
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.00%
Base Rate | Secured Term Loan Facilities
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.00%
Alternate Base Rate | Secured Term Loan Facilities
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	6.50%
Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility interest rate description		Borrowings under the Term Loan Facilities bear interest, at the Company’s option, at either (i) LIBOR plus 7.5% (“Eurodollar Loans”) or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, in each case plus 6.5% (an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. At June 30, 2015, the weighted average interest rate on outstanding borrowings under the term loan facilities was 8.5%.
Credit Agreement | Interim Term Loan Facility
Debt Instrument [Line Items]
Line of Credit Facility, aggregate principal amount	$ 30,000,000
Line of Credit Facility, expiration date		Aug. 27, 2015
Credit Agreement | Term A Loan Facility
Debt Instrument [Line Items]
Line of Credit Facility, aggregate principal amount	$ 97,800,000
Line of Credit Facility, expiration date		Feb. 26, 2016
Atlas Energy
Debt Instrument [Line Items]
Line of Credit Facility, initiation date		Jul. 31, 2013
Line of Credit Facility, aggregate principal amount				$ 240,000,000
Line of Credit Facility, expiration date		Jul. 31, 2019
Outstanding Term Facility, weighted average interest rate		6.50%
Atlas Energy | Term Loan
Debt Instrument [Line Items]
Term Loan Facilities, outstanding		$ 77,400,000
Term Loan Facilities, unamortized discount		$ 5,300,000

Debt (Atlas Energy Term Loan Fa

Debt (Atlas Energy Term Loan Facility) (Details) - USD ($)	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2013
Debt Instrument [Line Items]
Line of Credit Facility, initiation date	Feb. 27, 2015
Atlas Energy
Debt Instrument [Line Items]
Line of Credit Facility, initiation date	Jul. 31, 2013
Credit facility		$ 240,000,000
Line of Credit Facility, expiration date	Jul. 31, 2019
Senior Notes interest payment dates and terms	Borrowings under the Term Facility bore interest, at Atlas Energy’s election, at either an adjusted LIBOR rate plus an applicable margin of 5.50% per annum or the alternate base rate (as defined in the Term Facility) (“ABR”) plus an applicable margin of 4.50% per annum. Interest was generally payable quarterly for ABR loans and, for LIBOR loans at the interest periods selected by Atlas Energy. Atlas Energy was required to repay principal at the rate of $0.6 million per quarter commencing December 31, 2013 and continuing until the maturity date when the remaining balance was due.
Line of Credit Facility, additional margin rates in excess of LIBOR	5.50%
Line of Credit Facility, borrowing base additional rate	4.50%
Line of Credit Facility, principal repayment rate per quarter	$ 600,000
Outstanding Term Facility, weighted average interest rate	6.50%

Debt (ARP Credit Facility) (Det

Debt (ARP Credit Facility) (Details) - USD ($)	3 Months Ended	6 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Revolving credit facility		$ 550,000,000	$ 696,000,000
Revolving Credit Facility
Line Of Credit Facility [Line Items]
Line of Credit Facility, current borrowing capacity		750,000,000
Revolving credit facility		550,000,000
Letters of credit outstanding maximum		20,000,000
Letters of credit outstanding amount		$ 4,300,000
Line of Credit Facility collateral		ARP’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets. Additionally, obligations under the facility are guaranteed by certain of ARP’s material subsidiaries, and any non-guarantor subsidiaries of ARP are minor.
Line of Credit Facility interest rate description		at either an adjusted LIBOR rate plus an applicable margin between 1.50% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.50% and 1.75% per annum. If the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, the applicable margin on Eurodollar loans and ABR loans will be increased by 0.25%. ARP is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.375% per annum if less than 50% of the borrowing base is utilized and 0.5% if 50% or more of the borrowing base is utilized, which is included within interest expense on the Company’s combined consolidated statements of operations. At June 30, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 2.5%.
Line of Credit Facility, weighted average interest rate		2.50%
Line Of Credit Facility covenant terms		The ARP Credit Agreement contains customary covenants that limit ARP’s ability to incur additional indebtedness (excluding second lien debt in an aggregate principal amount of up to $300.0 million), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. ARP was in compliance with these covenants as of June 30, 2015. The ARP Credit Agreement also requires that ARP maintain a ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than (i) 5.25 to 1.0 as of the last day of the quarters ending on March 31, 2015, June 30, 2015, September 30, 2015, December 31, 2015 and March 31, 2016, (ii) 5.00 to 1.0 as of the last day of the quarters ending on June 30, 2016, September 30, 2016 and December 31, 2016, (iii) 4.50 to 1.0 as of the last day of the quarter ending on March 31, 2017 and (iv) 4.00 to 1.0 as of the last day of each quarter thereafter, and a ratio of current assets (as defined in the ARP Credit Agreement) to current liabilities (as defined in the ARP Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.
Line of Credit Facility, Covenant Compliance		ARP was in compliance with these covenants as of June 30, 2015.
Required Total Funded Debt to EBITDA ratio	5.25%
Required current assets to current liabilities ratio		1.00%
Current assets to current liabilities ratio		2.00%
Total Funded Debt to EBITDA ratio		4.50%
Revolving Credit Facility | Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Percentage of stated amount of senior notes or additional second lien debt that borrowing base reduced		25.00%
Aggregate principal amount of second lien debt		$ 300,000,000
Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Fifteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Fifteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Fifteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.25%
Revolving Credit Facility | Quarter Ended June Thirty Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.00%
Revolving Credit Facility | Quarter Ended September Thirty Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.00%
Revolving Credit Facility | Quarter Ended December Thirty First Two Thousand And Sixteen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		5.00%
Revolving Credit Facility | Quarter Ended March Thirty First Two Thousand And Seventeen
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		4.50%
Revolving Credit Facility | Fiscal quarters ending thereafter
Line Of Credit Facility [Line Items]
Required Total Funded Debt to EBITDA ratio		4.00%
Revolving Credit Facility | Maximum | Borrowing base utilization is less than 90% | Atlas Resource Partners, L.P.
Line Of Credit Facility [Line Items]
Percentage of borrowing base utilized		90.00%

Debt (ARP Term Loan Facility) (

Debt (ARP Term Loan Facility) (Details) - USD ($)	Feb. 23, 2015	Jun. 30, 2015
Debt Instrument, Redemption, Period Two
Debt Instrument [Line Items]
Principal amount prepaid for repayments	4.50%
Debt Instrument, Redemption, Period Three
Debt Instrument [Line Items]
Principal amount prepaid for repayments	2.25%
Second Lien Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility interest rate description		Borrowings under the ARP Term Loan Facility bear interest, at ARP’s option, at either (i) LIBOR plus 9.0% or (ii) the highest of (a) the prime rate, (b) the federal funds rate plus 0.50%, (c) one-month LIBOR plus 1.0% and (d) 2.0%, each plus 8.0% (an “ABR Loan”). Interest is generally payable at the applicable maturity date for Eurodollar loans and quarterly for ABR loans.
Line of Credit Facility, weighted average interest rate		10.00%
Principal amount of term loan facility	$ 300,000,000
Second Lien Credit Agreement | Incremental Term Loan
Debt Instrument [Line Items]
Line of Credit Facility, expiration date		Feb. 23, 2020
Second Lien Credit Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	9.00%
Second Lien Credit Agreement | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.50%
Second Lien Credit Agreement | One Month L I B O R
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.00%
Second Lien Credit Agreement | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.00%
Second Lien Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	8.00%
Second Lien Credit Agreement | Debt Instrument, Redemption, Period Four
Debt Instrument [Line Items]
Principal amount prepaid for repayments	0.00%
Atlas Resource Partners, L.P. | Second Lien Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility, aggregate principal amount	$ 250,000,000
Line of Credit Facility, expiration date		Feb. 23, 2020
Term Loan Facilities, unamortized discount		$ 7,000,000
Net cash proceeds from the issuance or incurrence of debt	100.00%
Excess net cash proceeds from certain asset sales and condemnation recoveries	100.00%

Debt (Senior Notes) (Details)

Debt (Senior Notes) (Details) - USD ($)	Oct. 14, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Debt instrument, restrictive covenants		The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants, including limitations of ARP’s ability to incur certain liens, incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase, or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all of ARP’s assets.
Debt instrument, covenant compliance		ARP was in compliance with these covenants as of June 30, 2015.
Cash paid on accrued interest on debt		$ 51,700,000	$ 30,900,000
7.75% Senior Notes
Debt Instrument [Line Items]
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor		0
9.25% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt	$ 75,000,000	$ 324,000,000
Senior Notes, maturity		2,021
Debt instrument, interest rate, stated percentage		9.25%
Term Loan Facilities, unamortized discount		$ 1,000,000
Senior Notes interest payment dates and terms		Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15
Debt instrument, call feature		At any time prior to August 15, 2017, ARP may redeem the 9.25% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, ARP may redeem some or all of the 9.25% ARP Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, ARP may redeem some or all of the 9.25% ARP Senior Notes at the redemption price of 100.0%. Under certain conditions, including if ARP sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, ARP must offer to repurchase the 9.25% ARP Senior Notes.
Registration rights agreement, description and terms		On April 15, 2015, the registration statement relating to the exchange offer for the 9.25% ARP Senior Notes was declared effective, and the exchange offer was subsequently launched on April 15, 2015 and expired on May 13, 2015.
Debt instrument, issuance date	Oct. 14, 2014
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt		$ 374,600,000
Senior Notes, maturity		2,021
Debt instrument, interest rate, stated percentage		7.75%		7.75%
Term Loan Facilities, unamortized discount		$ 400,000
Senior Notes interest payment dates and terms		Interest on the 7.75% ARP Senior Notes is payable semi-annually on January 15 and July 15.
Repurchase, make whole and redemption terms and description		At any time prior to January 15, 2016, the 7.75% ARP Senior Notes are redeemable for up to 35% of the outstanding principal amount with the net cash proceeds of equity offerings at the redemption price of 107.75%. The 7.75% ARP Senior Notes are also subject to repurchase at a price equal to 101% of the principal amount, plus accrued and unpaid interest, upon a change of control. At any time prior to January 15, 2017, ARP may redeem the 7.75% ARP Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the notes plus the Applicable Premium (as defined in the governing indenture), plus accrued and unpaid interest, if any. On and after January 15, 2017, the 7.75% ARP Senior Notes are redeemable, in whole or in part, at a redemption price of 103.875%, decreasing to 101.938% on January 15, 2018 and 100% on January 15, 2019
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		9.25%		9.25%

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 Instruments Gain Loss [Line Items]
Cash flow hedges derivative assets at fair value, net	$ 264,900,000		$ 264,900,000		$ 274,900,000
Net gain in accumulated other comprehensive income	32,600,000		32,600,000
Cash flow hedge gain (losses) to be reclassified within twelve months			17,900,000
Cash flow hedge gain (loss) to be reclassified in later periods			14,700,000
Derivative instruments, gains reclassified from accumulated OCI into income, effective portion		$ 0		$ 0
Cash settlements on commodity derivative contracts	40,700,000	9,500,000	83,246,000	24,100,000
Gain (loss) recognized for hedge Ineffectiveness or as a result of discontinuance of cash flow hedges	0	$ 0	0	$ 0
Atlas Resource Partners, L.P.
Derivative Instruments Gain Loss [Line Items]
Net unrealized derivative assets payable to limited partners	2,300,000		2,300,000
Atlas Resource Partners, L.P. | Crude Oil and Natural Gas
Derivative Instruments Gain Loss [Line Items]
Proceeds from early termination of commodity derivatives	$ 4,900,000		$ 4,900,000

Derivative Instruments (Summary

Derivative Instruments (Summary of Commodity Derivative Activity) (Details) - USD ($) $ in Thousands		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]
Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets	[1]	$ (25,778)		$ (53,121)
Portion of settlements attributable to subsequent mark to market gains		(14,922)		(30,125)
Total cash settlements on commodity derivative contracts		(40,700)	$ (9,500)	(83,246)	$ (24,100)
2015 Unrealized gains prior to settlement	[2]	3,678		6,881
Unrealized gain (loss) on open derivative contracts at June 30, 2015, net of amounts recognized in income in prior year	[2]	(30,574)		71,808
Gains (losses) on mark-to-market derivatives		$ (26,896)		$ 78,689
[1]	Recognized in gas and oil production revenue.
[2]	Recognized in gain on mark-to-market derivatives.

Derivative Instruments (Fair Va

Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	$ 271,302	$ 279,254
Gross Amounts of Recognized Liabilities	(712)	(468)
Atlas Resource Partners, L.P. | Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(272)	(98)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	272	98
Atlas Resource Partners, L.P. | Long-term portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(439)	(370)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	439	370
Atlas Resource Partners, L.P. | Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(711)	(468)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	711	468
Atlas Resource Partners, L.P. | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	114,982	144,357
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(272)	(98)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	114,710	144,259
Atlas Resource Partners, L.P. | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	150,601	130,972
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(439)	(370)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	150,162	130,602
Atlas Resource Partners, L.P. | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	265,583	275,329
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(711)	(468)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	$ 264,872	$ 274,861

Derivative Instruments (The Com

Derivative Instruments (The Company's Commodity Derivative Instruments by Type Table) (Details) - Jun. 30, 2015 - Atlas Growth Partners, L.P - Natural Gas Liquids – Crude Oil Fixed Price Swaps $ in Thousands		USD ($)bbl$ / bbl
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[1]	$ 48
Production Period Ending December 31 2015
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[2]	27,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[3]	61
Fair Value Asset / (Liability)	[1]	$ 17
Production Period Ending December 31 2016
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[2]	18,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[3]	63.150
Fair Value Asset / (Liability)	[1]	$ 19
Production Period Ending December 31 2017
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[2]	9,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[3]	65
Fair Value Asset / (Liability)	[1]	$ 12
[1]	Fair value based on forward WTI crude oil prices, as applicable.
[2]	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.
[3]	“Bbl” represents barrels.

Derivative Instruments (Fair 60

Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	$ 271,302	$ 279,254
Gross Amounts of Recognized Liabilities	(712)	$ (468)
Atlas Growth Partners, L.P | Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(1)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	1
Atlas Growth Partners, L.P | Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(1)
Gross Amounts Offset in the Combined Consolidated Balance Sheets	1
Atlas Growth Partners, L.P | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	31
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(1)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	30
Atlas Growth Partners, L.P | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	18
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	18
Atlas Growth Partners, L.P | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts of Recognized Assets	49
Gross Amounts Offset in the Combined Consolidated Balance Sheets	(1)
Net Amount of Assets Presented in the Combined Consolidated Balance Sheets	$ 48

Derivative Instruments (ARP's C

Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) - Jun. 30, 2015 - Atlas Resource Partners, L.P. $ in Thousands		USD ($)bblMMBTUgal$ / bbl$ / MMBTU$ / gal
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[1]	$ 168,349
Natural Gas Costless Collars
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[1]	1,992
Natural Gas Put Options Drilling Partnership
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[1]	2,314
Natural Gas - WAHA Basis Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[2]	41
Natural Gas Liquids Natural Gasoline Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[3]	1,758
Natural Gas Liquids Propane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[4]	2,133
Natural Gas Liquids - Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[5]	467
Natural Gas Liquids Iso Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[6]	460
Natural Gas Liquids Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[7]	3,143
Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[7]	83,981
Crude Oil - Costless Collars
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[7]	234
Total ARP Net Liability
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	[7]	$ 264,872
Production Period Ending December 31 2015 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	26,832,200
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4.193
Fair Value Asset / (Liability)	[1]	$ 34,433
Production Period Ending December 31 2015 | Natural Gas Costless Collars | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	1,560,000
Fair Value Asset / (Liability)	[1]	$ 1,996
Average Floor and Cap | $ / MMBTU	[8]	4.157
Production Period Ending December 31 2015 | Natural Gas Costless Collars | Calls Sold
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	1,560,000
Fair Value Asset / (Liability)	[1]	$ (4)
Average Floor and Cap | $ / MMBTU	[8]	5.002
Production Period Ending December 31 2015 | Natural Gas Put Options Drilling Partnership | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	720,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4
Fair Value Asset / (Liability)	[1]	$ 795
Production Period Ending December 31 2015 | Natural Gas - WAHA Basis Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	2,400,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	(0.090)
Fair Value Asset / (Liability)	[2]	$ 41
Production Period Ending December 31 2015 | Natural Gas Liquids Natural Gasoline Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	[8]	2,520,000
Derivative, Swap Type, Average Fixed Price | $ / gal	[8]	1.936
Fair Value Asset / (Liability)	[3]	$ 1,758
Production Period Ending December 31 2015 | Natural Gas Liquids Propane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	[8]	4,032,000
Derivative, Swap Type, Average Fixed Price | $ / gal	[8]	1.016
Fair Value Asset / (Liability)	[4]	$ 2,133
Production Period Ending December 31 2015 | Natural Gas Liquids - Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	[8]	756,000
Derivative, Swap Type, Average Fixed Price | $ / gal	[8]	1.248
Fair Value Asset / (Liability)	[5]	$ 467
Production Period Ending December 31 2015 | Natural Gas Liquids Iso Butane Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | gal	[8]	756,000
Derivative, Swap Type, Average Fixed Price | $ / gal	[8]	1.263
Fair Value Asset / (Liability)	[6]	$ 460
Production Period Ending December 31 2015 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	966,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	87.653
Fair Value Asset / (Liability)	[7]	$ 26,301
Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl		9,750
Fair Value Asset / (Liability)	[7]	$ 234
Average Floor and Cap | $ / bbl		83.846
Production Period Ending December 31 2015 | Crude Oil - Costless Collars | Calls Sold
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl		9,750
Average Floor and Cap | $ / bbl		110.654
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	53,546,300
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4.229
Fair Value Asset / (Liability)	[1]	$ 55,981
Production Period Ending December 31 2016 | Natural Gas Put Options Drilling Partnership | Puts Purchased
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	1,440,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4.150
Fair Value Asset / (Liability)	[1]	$ 1,519
Production Period Ending December 31 2016 | Natural Gas Liquids Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	84,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	85.651
Fair Value Asset / (Liability)	[7]	$ 1,960
Production Period Ending December 31 2016 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	1,557,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	81.471
Fair Value Asset / (Liability)	[7]	$ 29,889
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	49,920,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4.219
Fair Value Asset / (Liability)	[1]	$ 41,808
Production Period Ending December 31 2017 | Natural Gas Liquids Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	60,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	83.780
Fair Value Asset / (Liability)	[7]	$ 1,183
Production Period Ending December 31 2017 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	1,140,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	77.285
Fair Value Asset / (Liability)	[7]	$ 15,237
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	40,800,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4.170
Fair Value Asset / (Liability)	[1]	$ 28,491
Production Period Ending December 31 2018 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	1,080,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	76.281
Fair Value Asset / (Liability)	[7]	$ 11,561
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	[8]	15,960,000
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	[8]	4.017
Fair Value Asset / (Liability)	[1]	$ 7,636
Production Period Ending December 31 2019 | Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	[8]	540,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	[8]	68.371
Fair Value Asset / (Liability)	[7]	$ 993
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	Fair value based on forward WAHA natural gas prices, as applicable
[3]	Fair value based on forward Mt. Belvieu natural gasoline prices, as applicable.
[4]	Fair value based on forward Mt. Belvieu propane prices, as applicable.
[5]	Fair value based on forward Mt. Belvieu butane prices, as applicable.
[6]	Fair value based on forward Mt. Belvieu iso butane prices, as applicable.
[7]	Fair value based on forward WTI crude oil prices, as applicable.
[8]	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

Fair Value of Financial Instr62

Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	$ 271,302	$ 279,254
Liabilities, gross	(712)	(468)
Total assets, fair value, net	270,590	278,786
Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	5,670	3,925
Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	5,670	3,925
Total assets, fair value, net	5,670	3,925
Level 1 | Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	5,670	3,925
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	265,632	275,329
Liabilities, gross	(712)	(468)
Total assets, fair value, net	264,920	274,861
Atlas Resource Partners, L.P. | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,314	2,767
Atlas Resource Partners, L.P. | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	261,039	267,242
Liabilities, gross	(707)	(401)
Atlas Resource Partners, L.P. | Commodity Options
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,230	5,320
Liabilities, gross	(4)	(67)
Atlas Resource Partners, L.P. | Level 2 | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,314	2,767
Atlas Resource Partners, L.P. | Level 2 | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	261,039	267,242
Liabilities, gross	(707)	(401)
Atlas Resource Partners, L.P. | Level 2 | Commodity Options
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,230	5,320
Liabilities, gross	(4)	$ (67)
Atlas Growth Partners, L.P | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	49
Liabilities, gross	(1)
Atlas Growth Partners, L.P | Level 2 | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	49
Liabilities, gross	$ (1)

Fair Value of Financial Instr63

Fair Value of Financial 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
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 1,390,400,000		$ 1,390,400,000		$ 1,363,400,000
Long-term debt	1,569,000,000		1,569,000,000		$ 1,542,600,000
Asset impairment	$ 0	$ 0	$ 0	$ 0
Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Business acquisition, purchase price allocation, status			During the year ended December 31, 2014, ARP completed the Eagle Ford, Rangely and GeoMet acquisitions and AGP completed the Eagle Ford Acquisition (see Note 3). The fair value measurements of assets acquired and liabilities assumed for each of these acquisitions are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimated fair values of the assets acquired and liabilities assumed in the Eagle Ford Acquisition as of the acquisition date, which are reflected in the Company’s combined consolidated balance sheet as of June 30, 2015 are subject to change as the final valuations have not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the Company’s subsidiaries’ existing methodology for recognizing an estimated liability for the plugging and abandonment of their gas and oil wells (see Note 6). These inputs require significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuation and are subject to change.

Fair Value of Financial Instr64

Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	$ 47	$ 7,345	$ 216	$ 7,947
Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	47	7,345	216	7,947
Asset Retirement Obligations
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	47	7,345	216	7,947
Asset Retirement Obligations | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	$ 47	$ 7,345	$ 216	$ 7,947

Certain Relationships and Rel65

Certain Relationships and Related Party Transactions (Narrative) (Details)	6 Months Ended
	Jun. 30, 2015
Relationship With Drilling Partnerships
Related Party Transaction [Line Items]
Related party transaction, description of transaction	ARP conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. ARP serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, ARP is liable for the Drilling Partnerships’ liabilities and can be liable to limited partners of the Drilling Partnerships if it breaches its responsibilities with respect to the operations of the Drilling Partnerships. ARP is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.

Commitments and Contingencies (

Commitments and Contingencies (General Commitments) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Percentage of present value of future cash flows			10.00%
Net partnership revenues subordinated	$ 500,000	$ 400,000	$ 1,100,000	$ 3,800,000
Commitment to expend			10,900,000
ARP’s Geomet Acquisition
Contractual obligation, due remainder of the fiscal year	2,300,000		2,300,000
Contractual obligation, due in second year	2,300,000		2,300,000
Contractual obligation, due in third year	1,900,000		1,900,000
Contractual obligation, due in fourth year	1,800,000		1,800,000
Contractual obligation, due in fifth year	1,800,000		1,800,000
Contractual obligation, due in thereafter	6,500,000		6,500,000
EP Energy Acquisition
Contractual obligation, due remainder of the fiscal year	4,200,000		4,200,000
Contractual obligation, due in second year	2,100,000		2,100,000
Contractual obligation, due in third year	0		0
Contractual obligation, due in fourth year	0		0
Contractual obligation, due in fifth year	$ 0		$ 0
Minimum
Partnership obligations to purchase units from investor partners			5.00%
Investor partners return on investment			10.00%
Maximum
Partnership obligations to purchase units from investor partners			10.00%
Percentage on unhedged revenue			50.00%
Investor partners return on investment			12.00%

Issuances of Units (Preferred U

Issuances of Units (Preferred Unit Purchase Agreement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Feb. 27, 2015	Jun. 30, 2015
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions		10.75%
Percentage Of Common Unit Regular Quarterly Cash Distributions	2.00%
Series A Convertible Preferred Units
Capital Unit [Line Items]
Partners Capital Account Units Date Of Sale		February 27, 2015
Partners' Capital Account, Units, Sold in Private Placement	1.6
Redemption price per unit		$ 25
Subsidiary or Equity Method Investee, Price-Per-Share		$ 25
Partners' Capital Account, Private Placement of Units		$ 40
Cash consideration		$ 150
Percentage of Preferred Unit Regular Quarterly Cash Distributions	2.00%
Conversion price policy description		The conversion price will be equal to the greater of (i) $8.00 per common unit of the Company; and (ii) the lower of (a) 110.0% of the volume weighted average price for the Company’s common units on the NYSE over the 30 trading days following the distribution date; and (b) $16.00 per common unit of the Company.
Volume weighted average price	110.00%
Series A Convertible Preferred Units | Maximum
Capital Unit [Line Items]
Conversion per unit	$ 16
Series A Convertible Preferred Units | Minimum
Capital Unit [Line Items]
Conversion per unit	$ 8
Series A Convertible Preferred Units | Private Placement | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	10.00%
Series A Convertible Preferred Units | Private Placement | First Anniversary | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	12.00%
Series A Convertible Preferred Units | Private Placement | Second Anniversary | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	14.00%
Series A Convertible Preferred Units | Private Placement | Third Anniversary | Maximum
Capital Unit [Line Items]
Percentage of Preferred Unit Regular Quarterly Cash Distributions	16.00%

Issuances of Units (Atlas Resou

Issuances of Units (Atlas Resource Partners) (Details) - USD ($)

Jun. 30, 2015

Jan. 15, 2015

May. 31, 2015

Apr. 30, 2015

Oct. 31, 2014

Aug. 31, 2014

May. 31, 2014

Mar. 31, 2014

Jul. 15, 2015

Mar. 31, 2015

Jan. 14, 2015

Jun. 30, 2015

Dec. 31, 2014

Capital Unit [Line Items]

Partners unit, issued

2,885,824

Percentage of Preferred Unit Regular Quarterly Cash Distributions

10.75%

Aggregate Offering Price Of Common Units (Maximum)

$ 100,000,000

Agent commission, maximum percentage, of the gross sales price of common limited partner units sold.

2.00%

Proceeds from Issuance of Common Limited Partners Units

$ 21,400,000

Payments for Commissions

600,000

Atlas Growth Partners, L.P

Capital Unit [Line Items]

Common limited partner units issued

233,000,000

Common limited partner units purchased

5,000,000

Atlas Resource Partners, L.P.

Capital Unit [Line Items]

Gain on sale of subsidiary unit issuances

$ 2,900,000

$ 40,500,000

Preferred class D

Capital Unit [Line Items]

Partners unit, issued

4,000,000

Partners' Capital Account, Units, Percentage

8.625%

Tentative date for preferred stock redemption

Oct. 15, 2019

Preferred class D | Atlas Resource Partners, L.P.

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

8.625%

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.616927

$ 0.5390625

Preferred class E

Capital Unit [Line Items]

Tentative date for preferred stock redemption

Apr. 15, 2020

Preferred class E | Atlas Resource Partners, L.P.

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

10.75%

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.671875

Preferred class D and E

Capital Unit [Line Items]

Redemption price per unit

$ 25

$ 25

Class E Preferred Units

Capital Unit [Line Items]

Partners Capital Account Units Date Of Sale

April 2,015

Partners unit, issued

255,000

Partners Capital Account Sale Of Units

$ 6,000,000

Partners' Capital Account, Units, Percentage

10.75%

Redemption price per unit

$ 25

Percentage of Preferred Unit Regular Quarterly Cash Distributions

10.75%

Preferred Unit Regular Quarterly Cash Distributions Per Unit there after

$ 25

$ 25

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.6793

Arkoma Acquisition

Capital Unit [Line Items]

Partners Capital Account Units Date Of Sale

May 2,015

Partners unit, issued

6,500,000

Subsidiary or Equity Method Investee, Price-Per-Share

$ 7.97

Partners Capital Account Sale Of Units

$ 49,500,000

Arkoma Acquisition | Atlas Resource Partners, L.P.

Capital Unit [Line Items]

Partners unit, issued

6,500,000

Eagle Ford Acquisition | Class D Preferred Units

Capital Unit [Line Items]

Partners Capital Account Units Date Of Sale

October 2,014

Partners unit, issued

3,200,000

800,000

Subsidiary or Equity Method Investee, Price-Per-Share

$ 25

$ 25

Partners Capital Account Sale Of Units

$ 77,300,000

Partners' Capital Account, Units, Percentage

8.625%

Percentage of Preferred Unit Regular Quarterly Cash Distributions

8.625%

Preferred Unit Regular Quarterly Cash Distributions Per Unit there after

$ 2.15625

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.616927

Rangely Acquisition

Capital Unit [Line Items]

Partners Capital Account Units Date Of Sale

May 2,014

Partners unit, issued

15,525,000

Subsidiary or Equity Method Investee, Price-Per-Share

$ 19.90

Partners Capital Account Sale Of Units

$ 297,300,000

Rangely Acquisition | Over Allotment Units Issued

Capital Unit [Line Items]

Partners unit, issued

2,025,000

ARP’s Geomet Acquisition

Capital Unit [Line Items]

Partners Capital Account Units Date Of Sale

2014-03

Partners unit, issued

6,325,000

Subsidiary or Equity Method Investee, Price-Per-Share

$ 21.18

Partners Capital Account Sale Of Units

$ 129,000,000

ARP’s Geomet Acquisition | Over Allotment Units Issued

Capital Unit [Line Items]

Partners unit, issued

825,000

Cash Distributions - Additional

Cash Distributions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions

Jul. 31, 2015

Jul. 22, 2015

Jul. 15, 2015

Jun. 30, 2015

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Mar. 31, 2015

Jan. 14, 2015

Jun. 30, 2015

Distribution Made To Limited Partner [Line Items]

Partners unit, issued

2,885,824

Preferred Limited Partners' Interest

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.539063

$ 0.616927

Preferred class D

Distribution Made To Limited Partner [Line Items]

Partners' Capital Account, Units, Percentage

8.625%

Partners unit, issued

4,000,000

Subsequent Event | Preferred class D

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.5390625

Preferred Unit Regular Quarterly Cash Distributions

$ 2.2

Distribution Made to Limited Partner, Date of Record

Jul. 1, 2015

Subsequent Event | Preferred class E

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.6793

Preferred Unit Regular Quarterly Cash Distributions

$ 0.2

Distribution Made to Limited Partner, Date of Record

Jul. 1, 2015

Cash Distribution Declared | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Jul. 22, 2015

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

Cash Distribution Declared | Series A Preferred Units | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Jul. 22, 2015

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 0.3

Cash Distribution Paid | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 11.2

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Distribution Made to Member or Limited Partner, Date of Record

Aug. 7, 2015

Cash Distribution Paid | Subsequent Event | General Partner

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 0.2

Cash Distribution Paid | Series A Preferred Units | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Distribution Made to Member or Limited Partner, Date of Record

Aug. 7, 2015

Atlas Energy

Distribution Made To Limited Partner [Line Items]

Distribution Policy, Members or Limited Partners, Description

The Company has a cash distribution policy under which it distributes, within 50 days following the end of each calendar quarter, all of its available cash (as defined in its limited liability company agreement) for that quarter to its unitholders.

Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

Distribution Policy, Members or Limited Partners, Description

ARP Cash Distributions. In January 2014, ARP’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program whereby it distributes all of its available cash (as defined in ARP’s partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, ARP paid quarterly cash distributions within 45 days from the end of each calendar quarter.

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1933

$ 0.1933

$ 0.1933

$ 0.1933

$ 0.1933

Atlas Resource Partners, L.P. | Minimum

Distribution Made To Limited Partner [Line Items]

Percentage of Distributions in Excess of Targets

13.00%

Atlas Resource Partners, L.P. | Maximum

Distribution Made To Limited Partner [Line Items]

Percentage of Distributions in Excess of Targets

48.00%

Atlas Resource Partners, L.P. | Preferred Class B

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Monthly Cash Distributions Per Unit

$ 0.1333

Atlas Resource Partners, L.P. | Preferred Class B | Minimum

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

0.40

Atlas Resource Partners, L.P. | Class C Preferred Units

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Monthly Cash Distributions Per Unit

0.17

Atlas Resource Partners, L.P. | Class C Preferred Units | Minimum

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

0.51

Atlas Resource Partners, L.P. | Preferred class D

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.616927

0.5390625

Preferred Unit Regular Cash Distributions Per Unit

$ 2.15625

Partners' Capital Account, Units, Percentage

8.625%

Atlas Resource Partners, L.P. | Preferred class E

Distribution Made To Limited Partner [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.671875

Preferred Unit Regular Cash Distributions Per Unit

$ 25

Partners' Capital Account, Units, Percentage

10.75%

Atlas Resource Partners, L.P. | Cash Distribution Declared | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Jul. 22, 2015

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 11.2

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Distribution Made to Member or Limited Partner, Date of Record

Aug. 7, 2015

Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | General Partner

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 0.2

Atlas Resource Partners, L.P. | Cash Distribution Paid | Subsequent Event | Preferred Limited Partners' Interest

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 0.6

Cash Distributions (Schedule of

Cash Distributions (Schedule of Distributions Declared by Partnership) (Details) - USD ($) $ / shares in Units, $ in Thousands

1 Months Ended

3 Months Ended

6 Months Ended

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Mar. 31, 2015

Jan. 14, 2015

Jun. 30, 2015

Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1933

$ 0.1933

$ 0.1933

$ 0.1933

$ 0.1933

Month Ended March 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

May 15, 2015

Month Ended April 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jun. 12, 2015

Month Ended May 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jul. 15, 2015

Month Ended January 31, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Mar. 17, 2014

Month Ended February 28, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 14, 2014

Month Ended March 31, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

May 15, 2014

Month Ended April 30, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jun. 13, 2014

Month Ended May 31, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jul. 15, 2014

Month Ended June 30, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2014

Month Ended July 31, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Sep. 12, 2014

Month Ended August 31, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Oct. 15, 2014

Month Ended September 30, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Nov. 14, 2014

Month Ended October 30, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Dec. 15, 2014

Month Ended November 30, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jan. 14, 2015

Month Ended December 31, 2014

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Feb. 13, 2015

Month Ended January 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Mar. 17, 2015

Month Ended February 28, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 14, 2015

October 2, 2014 to January 14, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jan. 15, 2015

Quarter Ended March 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 15, 2015

Limited Partner Interest | Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 10,304

$ 10,179

$ 9,444

$ 9,347

$ 9,284

$ 16,782

$ 16,779

$ 16,033

$ 16,032

$ 16,032

$ 16,028

$ 16,029

$ 15,752

$ 15,752

$ 12,719

$ 12,719

$ 12,718

Preferred Limited Partners' Interest

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.539063

$ 0.616927

Preferred Limited Partners' Interest | Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

[1]

643

642

643

643

643

745

745

1,491

1,492

1,491

1,493

1,492

1,466

1,466

1,466

1,466

1,467

General Partner | Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

223

221

206

$ 204

$ 203

$ 1,378

$ 1,378

$ 1,378

$ 1,378

$ 1,378

$ 1,378

$ 1,377

$ 1,279

$ 1,279

$ 1,054

$ 1,055

$ 1,055

Class D Preferred Limited Partners

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

[1]

$ 2,156

$ 1,974

Class A Preferred Units | Month Ended March 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

May 15, 2015

Class A Preferred Units | Month Ended April 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jun. 12, 2015

Class A Preferred Units | Month Ended May 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jul. 15, 2015

Class A Preferred Units | Preferred Unitholders

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 334

$ 334

$ 333

[1]

Includes payments for the Class B and Class C preferred unit monthly distributions.

Benefit Plans (2015 Long Term I

Benefit Plans (2015 Long Term Incentive Plan Narrative) (Details) - Jun. 30, 2015 - 2015 Long Term Incentive Plan - shares	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Description	The Board of Directors of the Company approved and adopted the Company’s 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to officers, employees and managing board members of the Company and its affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for the Company. The 2015 LTIP is administered by a committee consisting of the Board or committee of the Board or board of an affiliate appointed by the Board (the “LTIP Committee”).
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	5,250,000
Phantom Units, Restricted Units and Unit Options Outstanding	2,764,210
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	2,485,790

Benefit Plans (2015 LTIP Phanto

Benefit Plans (2015 LTIP Phantom Unit Activity) (Details) - 2015 Phantom Units - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights				Generally, phantom units to be granted to employees under the 2015 LTIP will vest over a designated period of time
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage				25.00%
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months		906,663		906,663
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans		$ 0	$ 0		$ 0
Outstanding, beginning of year (Units)		68,910
Granted (Units)		2,695,300		2,764,210
Outstanding, end of period (Units)	[1],[2]	2,764,210		2,764,210
Outstanding, beginning of year		$ 9.07
Granted		6.43		$ 6.50
Outstanding, end of period	[1],[2]	$ 6.50		$ 6.50
Non-cash compensation expense recognized		$ 926,000		$ 946,000
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value		0	$ 0	0	$ 0
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value		13,800,000		13,800,000
Liabilities Related to Outstanding Phantom Units		$ 100,000		$ 100,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities		68,910		68,910
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities		$ 9.07		$ 9.07
Unrecognized compensation expense related to unvested phantom units		$ 16,700,000		$ 16,700,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition				2 years
Non Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period				4 years
[1]	The aggregate intrinsic value of phantom unit awards outstanding at June 30, 2015 was approximately $13.8 million.
[2]	There was approximately $0.1 million recognized as liabilities on the Company’s consolidated balance sheet at June 30, 2015 representing 68,910 units, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $9.07 at June 30, 2015.

Benefit Plans (2015 Unit Option

Benefit Plans (2015 Unit Option Activity) (Details) - 2015 Unit Options - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights			The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time.
Years From Date Of Grant Unit Option Awards Expire			10 years
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months	0		0
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	$ 0	$ 0	$ 0	$ 0

Benefit Plans (Rabbi Trust Narr

Benefit Plans (Rabbi Trust Narrative) (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Rabbi Trust	$ 5,670,000		$ 5,670,000		$ 3,925,000
Rabbi trust liabilities recorded	5,700,000		5,700,000		$ 3,900,000
Partnership distributed to participants			667,000
Rabbi trust
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Partnership distributed to participants	$ 0	$ 0	$ 0	$ 0

Benefit Plans (ARP Long Term In

Benefit Plans (ARP Long Term Incentive Plan Narrative) (Details) - Jun. 30, 2015 - ARP Long Term Incentive Plan - shares	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Description	ARP’s 2012 Long-Term Incentive Plan (the “ARP LTIP”), effective March 2012, provides incentive awards to officers, employees and directors as well as employees of the Company and its affiliates, consultants and joint venture partners who perform services for ARP. The ARP LTIP is administered by the board of the Company, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”).
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	2,900,000
Phantom Units, Restricted Units and Unit Options Outstanding	1,864,057
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	134,308

Benefit Plans (ARP LTIP Phantom

Benefit Plans (ARP LTIP Phantom Unit Activity) (Details) - ARP Phantom Units - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, beginning of year (Units)		632,010	812,308	799,192	839,808
Granted (Units)		9,730	223,523	9,730	227,023
Vested and issued (Units)	[1]	(222,358)	(131,374)	(389,540)	(146,874)
Forfeited (Units)		(8,125)	(3,250)	(8,125)	(18,750)
Outstanding, end of period (Units)	[2],[3]	411,257	901,207	411,257	901,207
Vested and not yet issued (Units)	[4]	24,750	74,850	24,750	74,850
Outstanding, beginning of year		$ 22.37	$ 24.35	$ 22.70	$ 24.31
Granted		8.50	20.29	8.50	20.30
Vested and issued	[1]	24.07	24.69	24.02	24.48
Forfeited		23.04	24.80	23.04	23
Outstanding, end of period	[2],[3]	21.10	23.29	21.10	23.29
Vested and not yet issued	[4]	$ 20.39	$ 24.49	$ 20.39	$ 24.49
Non-cash compensation expense recognized		$ 803,000	$ 1,590,000	$ 3,317,000	$ 3,321,000
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value		2,000,000	2,500,000	3,600,000	2,900,000
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value		2,600,000		2,600,000
Liabilities Related to Outstanding Phantom Units		$ 24,000	$ 200,000	$ 24,000	$ 200,000	$ 100,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities		14,005	25,432	14,005	25,432	26,579
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities		$ 13.39	$ 21.38	$ 13.39	$ 21.38	$ 21.16
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested But Not Yet Been Issued In Period Intrinsic Value				$ 200,000	$ 1,500,000
Unrecognized compensation expense related to unvested phantom units		$ 3,200,000		$ 3,200,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition				1 year 9 months 18 days
Atlas Resource Partners, L.P.
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights				Phantom units granted under the ARP LTIP generally will vest 25% of the original granted amount on each of the four anniversaries of the date of grant.
Share Based Compensation Arrangement By Share Based Payment Award Number Of Outstanding Units To Vest Within Next Twelve Months		191,408		191,408
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans		$ 200,000	$ 400,000	$ 500,000	$ 1,100,000
Atlas Resource Partners, L.P. | Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Award Other Than Options Vesting Period Percentage				25.00%
[1]	The intrinsic values of phantom unit awards vested and issued during the three months ended June 30, 2015 and 2014 were $2.0 million and $2.5 million, respectively, and $3.6 million and $2.9 million during the six months ended June 30, 2015 and 2014, respectively.
[2]	The aggregate intrinsic value for phantom unit awards outstanding at June 30, 2015 was $2.6 million.
[3]	There were approximately $24,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at June 30, 2015 and December 31, 2014, respectively, representing 14,005 and 26,579 units, respectively, due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair values for these units were $13.39 and $21.16 at June 30, 2015 and December 31, 2014, respectively. There was $0.2 million recognized as liabilities on the Company’s consolidated balance sheet at the period ended June 30, 2014 representing 25,432 units that participants may opt to settle in cash instead of units. The weighted average grant date fair value for these units was $21.38 at June 30, 2014.
[4]	The intrinsic values of phantom unit awards vested, but not yet issued at June 30, 2015 and 2014 were $0.2 million and $1.5 million, respectively.

Benefit Plans (ARP Unit Options

Benefit Plans (ARP Unit Options Activity) (Details) - 2012 Long Term Incentive Plans - Phantom Units - USD ($)		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights				The ARP LTIP Committee will determine the vesting and exercise restrictions applicable to an ARP award of options, if any, and the method by which the exercise price may be paid by the participant. Unit option awards expire 10 years from the date of grant. Unit options granted under the ARP LTIP generally will vest 25% on each of the next four anniversaries of the date of grant.
Years From Date Of Grant Unit Option Awards Expire				10 years
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Outstanding Options To Vest Within Next Twelve Months		106,949		106,949
Proceeds from Stock Options Exercised		$ 0	$ 0	$ 0	$ 0
Outstanding, beginning of year (Units)		1,453,300	1,472,675	1,458,300	1,482,675
Forfeited (Units)		(500)	(3,750)	(5,500)	(13,750)
Outstanding, end of period (Units)	[1],[2]	1,452,800	1,468,925	1,452,800	1,468,925
Options exercisable (Units)	[3]	1,342,976	734,400	1,342,976	734,400
Outstanding, beginning of year		$ 24.66	$ 24.66	$ 24.66	$ 24.66
Forfeited		25.14	24.67	24.71	24.40
Outstanding, end of period	[1],[2]	24.66	24.66	24.66	24.66
Options exercisable, end of year	[3]	$ 24.67	$ 24.67	$ 24.67	$ 24.67
Non-cash compensation expense recognized		$ 61,000	$ 420,000	$ 892,000	$ 1,033,000
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Intrinsic Value		0	0	$ 0	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term				6 years 10 months 24 days
Aggregate Intrinsic Value Of Options Outstanding		0	2,000	$ 0	2,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term				6 years 10 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		0	$ 0	$ 0	$ 0
Unrecognized compensation expense related to unvested unit options		$ 100,000		$ 100,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition				9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used				ARP used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.
Vesting Percentage On Each Of Next Four Anniversaries Of Date Of Grant
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Options Vesting Period Percentage				25.00%
[1]	The weighted average remaining contractual life for outstanding options at June 30, 2015 was 6.9 years.
[2]	There was no aggregate intrinsic value of options outstanding at June 30, 2015.
[3]	The weighted average remaining contractual life for exercisable options at June 30, 2015 was 6.9 years. There were no intrinsic values for options exercisable at June 30, 2015 and 2014.

Operating Segment Information78

Operating Segment Information (Narrative) (Details)	6 Months Ended
	Jun. 30, 2015Segment
Segment Reporting [Abstract]
Number of reportable operating segments	3

Operating Segment Information79

Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Revenues	$ 98,247	$ 141,604	$ 344,046	$ 303,751
General And Administrative Expense	(18,405)	(24,797)	(60,333)	(46,188)
Depreciation, depletion and amortization expense	(43,276)	(60,406)	(87,732)	(112,445)
Gain (loss) on asset sales and disposal	97	12	86	(1,591)
Interest expense	(33,187)	(16,074)	(67,938)	(32,051)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Revenues	96,125	138,897	339,714	300,254
Operating costs and expenses	(75,822)	(85,342)	(163,640)	(190,153)
Depreciation, depletion and amortization expense	(42,494)	(59,680)	(85,485)	(111,499)
Gain (loss) on asset sales and disposal	97	9	86	(1,594)
Interest expense	(24,716)	(13,263)	(49,913)	(26,451)
Segment income (loss)	(46,810)	(19,379)	40,762	(29,443)
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Revenues	1,865	2,457	4,176	3,025
Operating costs and expenses	(3,243)	(2,889)	(8,312)	(4,737)
Depreciation, depletion and amortization expense	(782)	(726)	(2,247)	(946)
Segment income (loss)	(2,160)	(1,158)	(6,383)	(2,658)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	257	250	156	472
General And Administrative Expense	(2,359)	(1,299)	(22,574)	(4,620)
Gain (loss) on asset sales and disposal		3		3
Interest expense	(8,471)	(2,811)	(18,025)	(5,600)
Segment income (loss)	$ (10,573)	$ (3,857)	$ (40,443)	$ (9,745)

Operating Segment Information80

Operating Segment Information (Reconciliation of Segment Income (Loss) to Net Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Net loss	$ (59,543)	$ (24,394)	$ (6,064)	$ (41,846)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Net loss	(46,810)	(19,379)	40,762	(29,443)
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Net loss	(2,160)	(1,158)	(6,383)	(2,658)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Net loss	$ (10,573)	$ (3,857)	$ (40,443)	$ (9,745)

Operating Segment Information81

Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 98,247	$ 141,604	$ 344,046	$ 303,751
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Total revenues	96,125	138,897	339,714	300,254
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total revenues	1,865	2,457	4,176	3,025
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenues	$ 257	$ 250	$ 156	$ 472

Operating Segment Information82

Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Capital expenditures	$ 30,168	$ 61,810	$ 82,609	$ 106,229
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Capital expenditures	26,993	54,718	69,491	94,649
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Capital expenditures	$ 3,175	$ 7,092	$ 13,118	$ 11,580

Operating Segment Information83

Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Goodwill	$ 13,639	$ 13,639
Total assets	2,944,838	3,026,315
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Goodwill	13,639	13,639
Total assets	2,701,094	2,791,553
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total assets	229,981	190,161
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total assets	$ 13,763	$ 44,601

Subsequent Events (The Company)

Subsequent Events (The Company) (Details) - Jul. 22, 2015 - Subsequent Event - USD ($) $ in Millions	Total
Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Jul. 22, 2015
Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 11.2
Distribution Made to Member or Limited Partner, Distribution Date	Aug. 14, 2015
Distribution Made to Member or Limited Partner, Date of Record	Aug. 7, 2015
Series A Preferred Units | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Jul. 22, 2015
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 0.3
Series A Preferred Units | Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Distribution Date	Aug. 14, 2015
Distribution Made to Member or Limited Partner, Date of Record	Aug. 7, 2015

Subsequent Events (Atlas Resour

Subsequent Events (Atlas Resource Cash Distribution) (Details) - USD ($)

Jul. 31, 2015

Jul. 22, 2015

Jul. 15, 2015

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Jul. 15, 2015

Class E Preferred Units

Subsequent Event [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.6793

Atlas Resource Partners, L.P.

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1966

$ 0.1933

$ 0.1933

$ 0.1933

$ 0.1933

$ 0.1933

General Partner | Atlas Resource Partners, L.P.

Subsequent Event [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 223,000

$ 221,000

$ 206,000

$ 204,000

$ 203,000

$ 1,378,000

$ 1,378,000

$ 1,378,000

$ 1,378,000

$ 1,378,000

$ 1,378,000

$ 1,377,000

$ 1,279,000

$ 1,279,000

$ 1,054,000

$ 1,055,000

$ 1,055,000

Subsequent Event | Atlas Resource Partners, L.P. | Class D Preferred Units

Subsequent Event [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.5390625

Distribution Made to Limited Partner, Cash Distributions Paid

$ 2,200,000

Subsequent Event | Atlas Resource Partners, L.P. | Class E Preferred Units

Subsequent Event [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.6793

Distribution Made to Limited Partner, Cash Distributions Paid

$ 200,000

Subsequent Event | Cash Distribution Declared

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Jul. 22, 2015

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

Subsequent Event | Cash Distribution Declared | Atlas Resource Partners, L.P.

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Jul. 22, 2015

Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit

$ 0.1083

Subsequent Event | Cash Distribution Paid

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 11,200,000

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Distribution Made to Member or Limited Partner, Date of Record

Aug. 7, 2015

Subsequent Event | Cash Distribution Paid | Atlas Resource Partners, L.P.

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 11,200,000

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Distribution Made to Member or Limited Partner, Date of Record

Aug. 7, 2015

Subsequent Event | Cash Distribution Paid | General Partner

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 200,000

Subsequent Event | Cash Distribution Paid | General Partner | Atlas Resource Partners, L.P.

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 200,000

Subsequent Event | Cash Distribution Paid | Preferred Limited Partner Units

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 600,000