Atlas Energy 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Mar. 24, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
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
Entity Public Float			$ 125.4
Entity Common Stock, Units Outstanding		26,027,992
Entity Current Reporting Status	No
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Trading Symbol	ATLS

COMBINED CONSOLIDATED BALANCE S

COMBINED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 31,214	$ 58,358
Accounts receivable	65,920	115,290
Advances to affiliates		4,389
Current portion of derivative asset	159,763	144,259
Subscriptions receivable	19,877	32,398
Prepaid expenses and other	22,997	26,789
Total current assets	299,771	381,483
Property, plant and equipment, net	1,316,897	2,419,289
Goodwill and intangible assets, net	14,095	14,330
Long-term derivative asset	198,371	130,602
Other assets, net	88,980	80,611
Total assets	1,918,114	3,026,315
Current liabilities:
Current portion of long-term debt	4,250	1,500
Accounts payable	52,550	123,670
Liabilities associated with drilling contracts	21,483	40,611
Current portion of derivative payable to Drilling Partnerships	2,574	932
Accrued interest	25,452	26,479
Accrued well drilling and completion costs	33,555	92,910
Deferred acquisition purchase price		105,000
Accrued liabilities	42,440	64,854
Total current liabilities	182,304	455,956
Long-term debt, less current portion	1,602,932	1,541,085
Asset retirement obligations and other	$ 124,919	$ 114,059
Commitments and contingencies (Note 11)
Unitholders’/owner’s equity (deficit):
Common unitholders’ equity (deficit)	$ (103,148)
Series A preferred equity	40,875
Owner’s equity		$ 147,308
Accumulated other comprehensive income	4,284	54,008
Unitholders'/owner's equity excluding non-controlling interests	(57,989)	201,316
Non-controlling interests	65,948	713,899
Total unitholders’/owner’s equity	7,959	915,215
Total liabilities and unitholders’/owner’s equity	$ 1,918,114	$ 3,026,315

COMBINED CONSOLIDATED STATEMENT

COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Gas and oil production	$ 368,845	$ 475,758	$ 273,906
Well construction and completion	76,505	173,564	167,883
Gathering and processing	7,431	14,107	15,676
Administration and oversight	7,812	15,564	12,277
Well services	23,822	24,959	19,492
Gain on mark-to-market derivatives	268,085	2,819
Other, net	993	1,739	(14,135)
Total revenues	753,493	708,510	475,099
Costs and expenses:
Gas and oil production	171,882	184,296	100,178
Well construction and completion	66,526	150,925	145,985
Gathering and processing	9,613	15,525	18,012
Well services	9,162	10,007	9,515
General and administrative	109,569	90,476	89,957
Depreciation, depletion and amortization	166,929	242,079	139,916
Asset impairment	973,981	580,654	38,014
Total costs and expenses	1,507,662	1,273,962	541,577
Operating loss	(754,169)	(565,452)	(66,478)
Loss on asset sales and disposal	(1,181)	(1,859)	(987)
Interest expense	(125,658)	(73,435)	(39,712)
Loss on extinguishment of debt	(4,726)
Net loss	(885,734)	(640,746)	(107,177)
Preferred unitholders’ dividends	(3,360)
Loss attributable to non-controlling interests	649,316	471,439	58,389
Net loss attributable to unitholders’/owner’s interests	(239,778)	(169,307)	(48,788)
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)	(10,475)	(169,307)	(48,788)
Portion applicable to unitholders’ interests (period subsequent to the transfer of assets on February 27, 2015)	(229,303)
Net loss attributable to unitholders’/owner’s interests	$ (239,778)	$ (169,307)	$ (48,788)
Net loss attributable to unitholders per common unit:
Basic	$ (8.82)
Diluted	$ (8.82)
Weighted average common units outstanding:
Basic	26,011
Diluted	26,011

COMBINED CONSOLIDATED STATEMEN4

COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net loss	$ (885,734)	$ (640,746)	$ (107,177)
Other comprehensive income (loss):
Mark-to-market gains during the period		238,875	15,828
Reclassification of mark-to-market gains to offset asset impairment expense	(85,768)	(82,324)
Reclassification to mark-to-market (gains) losses	(86,328)	7,739	(10,216)
Total other comprehensive income (loss)	(172,096)	164,290	5,612
Comprehensive loss	(1,057,830)	(476,456)	(101,565)
Comprehensive loss attributable to non-controlling interests	771,688	350,819	53,416
Comprehensive loss attributable to unitholders’/owner’s interest	$ (286,142)	$ (125,637)	$ (48,149)

COMBINED CONSOLIDATED STATEMEN5

COMBINED CONSOLIDATED STATEMENTS OF UNITHOLDERS'/OWNER'S EQUITY - USD ($) $ in Thousands	Total	Series A Preferred Equity	Common Unitholders' Equity (Deficit)	Owner's Equity	Accumulated Other Comprehensive Income	Non-Controlling Interest
Balance at Dec. 31, 2012	$ 868,804			$ 366,066	$ 9,699	$ 493,039
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015	(48,788)
Distributions to non-controlling interests	(73,129)					(73,129)
Net issued and unissued units under incentive plan	12,630					12,630
Non-controlling interests’ capital contribution	326,421					326,421
Net investment from Atlas Energy	12,774			12,774
Distribution equivalent rights paid on unissued units under incentive plans	(1,939)					(1,939)
Gain on sale from subsidiary unit issuances				27,326		(27,326)
Other comprehensive income	5,612				639	4,973
Net loss	(107,177)			(48,788)		(58,389)
Balance at Dec. 31, 2013	1,043,996			357,378	10,338	676,280
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015	(169,307)
Distributions to non-controlling interests	(142,386)					(142,386)
Net issued and unissued units under incentive plan	7,391					7,391
Non-controlling interests’ capital contribution	585,240					585,240
Net distribution to Atlas Energy	(85,772)			(85,772)
Distribution equivalent rights paid on unissued units under incentive plans	(2,158)					(2,158)
Distribution payable	(14,640)					(14,640)
Gain on sale from subsidiary unit issuances				45,009		(45,009)
Other comprehensive income	164,290				43,670	120,620
Net loss	(640,746)			(169,307)		(471,439)
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)
Net assets contributed by owner to Atlas Energy Group, LLC, units			26,010,766
Issuance of units	268,880	$ 40,536	$ (536)			228,880
Issuance of units , number of units		1,621,427
Distributions to non-controlling interests	(116,621)					(116,621)
Net issued and unissued units under incentive plan	10,404		5,348			5,056
Distribution equivalent rights paid on unissued units under incentive plans	(558)					(558)
Distribution payable	10,910	$ (338)				11,248
Gain on sale from subsidiary unit issuances			4,268			(4,268)
Other comprehensive income	(172,096)				(49,724)	(122,372)
Net loss	(875,259)	3,360	(229,303)			(649,316)
Balance at Dec. 31, 2015	7,959	$ 40,875	$ (103,148)		$ 4,284	$ 65,948
Balance units at Dec. 31, 2015		1,621,427	26,010,766
Dividends paid to preferred equity unitholders	$ (2,683)	$ (2,683)

COMBINED CONSOLIDATED STATEMEN6

COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (885,734)	$ (640,746)	$ (107,177)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	166,929	242,079	139,916
Asset impairment	973,981	580,654	38,014
Loss on early extinguishment of debt	4,726
Gain on derivatives	(227,155)
Amortization of deferred financing costs and discount and premium on long-term debt	34,083	10,462	10,263
Non-cash compensation expense	10,324	7,731	12,680
Loss on asset sales and disposal	1,181	1,859	987
Distributions paid to non-controlling interests	(117,179)	(144,544)	(75,068)
Equity income in unconsolidated companies	(742)	(1,136)	(2,594)
Distributions received from unconsolidated companies	2,847	1,695	1,022
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other	127,921	(58,869)	(22,283)
Accounts payable and accrued liabilities	(84,117)	76,902	8,081
Net cash provided by operating activities	7,065	76,087	3,841
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(156,360)	(225,636)	(267,480)
Net cash paid for acquisitions	(120,332)	(741,522)	(780,857)
Other	(1,223)	4,211	(5,187)
Net cash used in investing activities	(277,915)	(962,947)	(1,053,524)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities	859,890	1,393,000	1,107,625
Repayments under credit facilities	(808,903)	(1,117,500)	(896,050)
Net proceeds from subsidiary long term debt		170,596	510,396
Net proceeds from issuance of Series A units	40,000
Net proceeds from issuance of subsidiary units to the public	208,902	585,240	326,421
Dividends to preferred unitholders	(2,683)
Net investment from (distributions to) Atlas Energy	(19,758)	(85,772)	12,774
Deferred financing costs, distribution equivalent rights and other	(33,742)	(10,971)	(24,128)
Net cash provided by financing activities	243,706	934,593	1,037,038
Net change in cash and cash equivalents	(27,144)	47,733	(12,645)
Cash and cash equivalents, beginning of year	58,358	10,625	23,270
Cash and cash equivalents, end of year	$ 31,214	$ 58,358	$ 10,625

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	NOTE 1—BASIS OF PRESENTATION Atlas Energy Group, LLC (the “Company”) is a Delaware limited liability company formed in October 2011. At December 31, 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 23.3% 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 (“MLP”) (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 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas. 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. (“Lightfoot L.P.”) and Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.”), its general partner (collectively, “Lightfoot”), which incubate new MLPs and invest in existing MLPs. On February 27, 2015, the Company’s former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to the Company, and effected a pro rata distribution of the Company’s common units representing a 100% interest in the Company, to Atlas Energy’s unitholders (the “Separation”). The Company’s common units began trading “regular-way” under the ticker symbol “ATLS” on the New York Stock Exchange on March 2, 2015. Concurrently with the distribution of the Company’s units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading. At December 31, 2015, the Company had 26,010,766 common limited partner units issued and outstanding. The common units are a class of limited liability company interests in the Company. The holders of common units are entitled to participate in company distributions and exercise the rights or privileges available to a holders of common units as outlined in the limited liability company agreement. The Company will continue as a limited liability company until dissolved under the limited liability company agreement. The limited liability company agreement specifies the manner in which the Company will make cash distributions to holders of common units and other partnership securities (see Note 13). The following is a summary of the voting requirements specified for certain matters under the limited liability company agreement: · Election of the directors to the Company’s board of directors - plurality of votes cast by the Company’s unitholders. · Issuance of additional company securities - no approval right, subject to the rules of any national securities exchange on which the Company’s securities are listed. · Amendment of the Company’s limited liability company agreement - certain amendments may be made by the Company’s board of directors without the approval of the unitholders. Other amendments generally require the approval of a majority of the Company’s outstanding voting units. · Merger of the Company or the sale of all or substantially all of the Company’s assets - majority of the Company’s outstanding voting units in certain circumstances. · Dissolution of the Company - majority of the Company’s outstanding voting units. · Continuation of the Company upon dissolution - majority of the Company’s outstanding voting units. The outstanding voting units consist of the Company’s common units and the Company’s Series A preferred units, which have voting rights identical to those of the Company’s common units on a “as converted” basis.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Combination The consolidated financial statements for the year ended December 31, 2015, subsequent to the transfer of assets on February 27, 2015, includes the accounts of the Company and its subsidiaries. The Company’s combined consolidated financial statements for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, and the combined consolidated financial statements for the years ended December 31, 2014 and 2013 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 (“U.S. GAAP”) 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 U.S. GAAP, 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 consolidates the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interests 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 “ Impairment of Long Lived Assets 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. 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. Actual results could differ from those estimates. Liquidity and Capital Resources The Company’s primary sources of liquidity are cash distributions received with respect to the Company’s ownership interests in ARP, AGP, and Lightfoot. The Company’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and distributions to unitholders, which the Company expects to fund through operating cash flow, and cash distributions received. The Company relies on the cash flows from the distributions received on the Company’s ownership interests in ARP, AGP, and Lightfoot. The amount of cash that ARP and AGP can distribute to their partners, including the Company, principally depends upon the amount of cash they each generate from their operations. Reductions of such distributions to the Company would adversely affect the Company’s ability to fund its cash requirements and obligations and meet its financial covenants under its credit agreement. In November 2015, ARP completed the semi-annual redetermination of its credit facility, reducing the borrowing base from $750 million to $700 million and resetting annual distributions to $0.15 per common unit. As a result, ARP distributions to the Company in 2016 will be significantly lower than those received in 2015. On March 30, 2016, the Company entered into a Third Amendment to its First Lien Credit Agreement and a new Second Lien Credit Agreement that, among other things, modifies certain financial covenants, incorporates the ARP financial covenants, provides for a cross-default for defaults by ARP, prohibits the Company from paying distributions on its common and preferred units and requires quarterly receipt of distributions from AGP and Lightfoot. The Company and its subsidiaries believe that they will have sufficient liquid assets, cash from operations and borrowing capacity to meet their financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. To the extent commodity prices remain low or decline further, or the Company, ARP or AGP experience disruptions in the financial markets impacting their respective longer-term access to or cost of capital, their respective ability to fund future growth projects may be further impacted. The Company, ARP and AGP continually monitor their respective capital markets and their capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. It is possible additional adjustments to the Company’s, ARP’s or AGP’s strategic plan and outlook may occur based on market conditions and their respective needs at that time, which could include selling assets, liquidating all or a portion of ARP’s hedge portfolio, seeking additional partners to develop their respective assets, reducing or suspending the payments of distributions to unitholders and/or reducing their respective planned capital programs. Strategies involving further reduction or suspension of distributions to unitholders by ARP or AGP would adversely affect the Company’s ability to fund its cash requirements and obligations. ARP relies on cash flow from operations and its credit facilities to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. In November 2015, ARP completed the semi-annual redetermination of its credit facility, reducing the borrowing base from $750 million to $700 million. ARP’s next redetermination date is in May 2016. ARP’s borrowing base, and thus its borrowing capacity, under the Credit Facility is impacted by the level of its oil and natural gas reserves. Downward revisions of its oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of its borrowing base in the future, and these reductions could be significant. ARP believes it has sufficient liquidity from (i) its cash flows from operations (including its hedges scheduled to settle in 2016), (ii) availability under its credit facility and (iii) available cash, to fund its capital program, current obligations and projected working capital requirements for 2016. Furthermore, despite the decline in natural gas and oil prices, ARP believes its derivative contracts, which are primarily fixed price swaps, provide significant commodity price protection on a significant portion of its anticipated natural gas and oil production for 2016. ARP’s ability to (i) generate sufficient cash flows from operations or obtain future borrowings under its credit facility, (ii) repay or refinance any of its indebtedness on commercially reasonable terms or at all, or (iii) obtain additional capital if required on acceptable terms or at all to fund its capital programs or any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond its control. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact ARP’s outlook. ARP’s plans are intended to address the impacts of the current volatility in commodity prices while (i) maintaining sufficient liquidity to fund capital in its core drilling programs, (ii) meeting its debt maturities, and (iii) managing and working to strengthen its balance sheet. ARP continues to implement various cost saving measures to reduce its capital, operating, and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. ARP will continue to be opportunistic and aggressive in managing its cost structure and, in turn, its liquidity to meet its capital and operating needs. To the extent commodity prices remain low or decline further, or ARP experiences disruptions in the financial markets impacting its longer-term access to or cost of capital, its ability to fund future growth projects may be further impacted. ARP continually monitors the capital markets and its capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. For example, ARP could (i) elect to repurchase a portion of its outstanding debt in the future for cash through open market repurchases or privately negotiated transactions with certain of its debtholders, or (ii) issue additional secured debt as permitted under its debt agreements, although there is no assurance ARP would do so. It is also possible additional adjustments to its plan and outlook may occur based on market conditions and its needs at that time, which could include selling assets, liquidating all or a portion of its hedge portfolio, seeking additional partners to develop its assets, reducing or suspending the payments of distributions to unitholders and/or reducing its planned capital program. Cash Equivalents The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments. Receivables Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. Management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At December 31, 2015 and 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets. Inventory The Company had $8.0 million and $8.9 million of inventory at December 31, 2015 and 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. Subscriptions Receivable ARP receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which is then delivered to Anthem. The investor contributions are then remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable. 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’s 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 undiscounted 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. 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 6.5%, 5.6% and 6.0% for the years ended December 31, 2015, 2014 and 2013, respectively. The amounts of interest capitalized by ARP were $15.8 million, $13.0 million and $14.2 million for the years ended December 31, 2015, 2014 and 2013, 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 December 31, 2015 and 2014 (in thousands): December 31, Estimated Useful Lives 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,888 ) (13,653 ) Net Carrying Amount $ 456 $ 691 Amortization expense on intangible assets was $0.2 million, $0.3 million and $0.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for intangible assets is approximately $0.1 million per year through 2019. Goodwill At December 31, 2015 and 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 year ended December 31, 2015. The change in ARP’s goodwill during the year end December 31, 2014 resulted from goodwill impairment related to its gas and oil production reporting unit. ARP evaluates 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. All remaining goodwill at December 31, 2015 and 2014 is attributable to ARP’s well construction and completion and other partnership management reporting units. No changes in the carrying amount of goodwill were recorded for the years ended December 31, 2015 and 2013. 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 pays 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 cumulative redeemable perpetual 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 14, 2015. Subsequent to July 15, 2015, ARP pays quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference. At December 31, 2015 and 2014, $103.3 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity. 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 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 December 31, 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 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 posi

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 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 ARP’s EP Energy Acquisition On July 31, 2013, ARP completed an acquisition of assets from EP Energy E&P Company, L.P. (“EP Energy”) for approximately $709.6 million in cash, net of purchase price adjustments (the “EP Energy Acquisition”). ARP funded the purchase price through borrowings under its revolving credit facility, the issuance of its 9.25% senior notes due 2021 (“9.25% ARP Senior Notes”) (see Note 7), and the issuance of 14,950,000 ARP common limited partner units and 3,749,986 newly created ARP Class C convertible preferred units (see Note 12). The assets acquired by ARP in the EP Energy Acquisition included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming. The EP Energy Acquisition had an effective date of May 1, 2013. The combined consolidated financial statements reflect the operating results of the acquired business commencing July 31, 2013 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 $12.1 million of transaction fees which were included within non-controlling interests for the year ended December 31, 2013 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 EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): Assets: Prepaid expenses and other $ 5,268 Property, plant and equipment 723,842 Total assets acquired $ 729,110 Liabilities: Accounts payable 2,747 Asset retirement obligation 16,728 Total liabilities assumed 19,475 Net assets acquired $ 709,635 Pro Forma Financial Information The following data presents pro forma revenues and net loss for the Company as if the Rangely and EP Energy acquisitions, including the related borrowings under the respective revolving credit facilities, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2013. The Company prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely and EP Energy acquisitions and related offerings, borrowings, and issuances had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per unit data; unaudited): Years Ended December 31, 2014 2013 Total revenues and other $ 754,511 $ 657,300 Net loss (602,707) (21,402 ) Net loss attributable to owner (146,227) (186 ) 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 in its standalone consolidated financial statements. 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 $342.0 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 $139.0 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 $16.0 million and ARP paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition. On July 8, 2015, AGP sold to ARP, for a purchase price of $1.4 million, AGP’s interest in a portion of the acreage AGP acquired in the Eagle Ford Acquisition, which represented AGP’s cost basis for the properties. The transaction was approved by AGP’s and ARP’s respective conflicts committees. On September 21, 2015, ARP agreed with AGP to have AGP transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP. On October 1, 2015, ARP paid $17.5 million to satisfy the fourth installment related to the Eagle Ford Acquisition. On December 31, 2015, ARP paid the $21.6 million final deferred portion of the purchase price. The Eagle Ford Acquisition had an effective date of July 1, 2014. ARP’s issuance of Class D ARP Preferred Units in March 2015 represented a non-cash transaction for statement of cash flow purposes during the year ended December 31, 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 included coal-bed methane producing natural gas assets in West Virginia and Virginia. ARP’s Norwood Acquisition On September 20, 2013, ARP completed the acquisition of certain assets from Norwood Natural Resources (“Norwood”) for $5.4 million (the “Norwood Acquisition”). The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale. The Norwood Acquisition had an effective date of June 1, 2013. The Company’s Arkoma Acquisition On July 31, 2013, Atlas Energy completed the acquisition of certain natural gas and oil producing assets in the Arkoma Basin from EP Energy for approximately $64.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). The Arkoma Acquisition was funded with a portion of the proceeds from the issuance of Atlas Energy’s term loan facility (see Note 7). The Arkoma Acquisition had an effective date of May 1, 2013.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 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): December 31, Estimated Useful Lives 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 569,377 $ 455,401 Pre-development costs 6,529 7,378 Wells and related equipment 3,157,708 3,082,429 Total proved properties 3,733,614 3,545,208 Unproved properties 213,047 311,946 Support equipment 44,921 37,359 Total natural gas and oil properties 3,991,582 3,894,513 Pipelines, processing and compression facilities 59,733 49,547 15 – 20 Rights of way 829 830 20 – 40 Land, buildings and improvements 9,798 9,160 3 – 40 Other 18,405 17,936 3 – 10 4,080,347 3,971,986 Less – accumulated depreciation, depletion and amortization (2,763,450 ) (1,552,697 ) $ 1,316,897 $ 2,419,289 During the year ended December 31, 2015, the Company recognized a $1.2 million loss on asset sales and disposal primarily related to ARP’s write-down of pipe, pump units and other inventory in the New Albany Shale and Black Warrior basin that are no longer usable and ARP’s plugging and abandonment costs for certain wells in the New Albany Shale. During the year ended December 31, 2014, the Company recognized $1.9 million of loss on asset sales and disposal primarily pertaining to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farmout agreement. During the year ended December 31, 2013, the Company recognized $1.0 million of loss on asset sales and disposal primarily pertaining to ARP’s loss on the sale of its Antrim assets. 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 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. During the year ended December 31, 2015, ARP recognized $6.6 million of asset impairments related to its unproved gas and oil properties within property, plant and equipment, net on the Company’s combined consolidated balance sheet primarily for its unproved acreage in the New Albany Shale. During the year ended December 31, 2013, ARP recognized $13.5 million of asset impairments related to its unproved gas and oil properties within property, plant and equipment, net on the Company’s combined consolidated balance sheet primarily for its unproved acreage in the Chattanooga and New Albany shales. There were no impairments of unproved gas and oil properties recorded by the Company’s subsidiaries for year ended December 31, 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. Asset impairments and offsetting hedge gains, if any, are included in asset impairment expense in the Company’s combined consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013. For the year ended December 31, 2015, the Company recognized $974.0 million of asset impairment primarily related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income. During the year ended December 31, 2014, the Company recognized $580.7 million of asset impairment primarily related to ARP’s proved oil and gas properties in Appalachian and mid-continent operations, which were impaired due to lower forecasted commodity prices, net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. During the year ended December 31, 2013, ARP recognized $24.5 million of asset impairments related to its proved gas and oil properties for its shallow natural gas wells in the New Albany Shale. During the years ended December 31, 2015, 2014 and 2013, the Company recognized $21.5 million, $36.8 million and $11.4 million, respectively, of non-cash property, plant and equipment additions, within the changes in accounts payable and accrued liabilities on the Company’s combined consolidated statements of cash flows.

Other Assets

Other Assets	12 Months Ended
	Dec. 31, 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): December 31, 2015 2014 Deferred financing costs, net of accumulated amortization of $45,529 and $20,675, respectively $ 54,933 $ 46,120 Investment in Lightfoot 19,302 21,123 Rabbi Trust 5,584 3,925 Security deposits 351 229 ARP notes receivable 3,708 3,866 Other 5,102 5,348 $ 88,980 $ 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 $13.6 million, $9.9 million and $7.0 million for the years ended December 31, 2015, 2014 and 2013, respectively, which was recorded within interest expense on the Company’s combined consolidated statements of operations. During the year ended December 31, 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 and $0.5 million for accelerated amortization of deferred financing costs associated with the retirement of a portion outstanding indebtedness under the Company’s term loan, which is included within interest expense on the combined consolidated statement of operations. During the year ended December 31, 2015, the Company recorded $0.3 million of accelerated amortization of deferred financing costs related to the early retirement of its Term Loan Facilities with Deutsche Bank, which is included within loss on early extinguishment of debt on the combined consolidated statement of operations. During the year ended December 31, 2015, ARP recognized $5.6 million for accelerated amortization of deferred financing costs associated with reductions of the borrowing base under its revolving credit facility, which is included within interest expense on the combined consolidated statement of operations. During the year ended December 31, 2014, ARP recognized $0.6 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under its revolving credit facility, which is included within interest expense on the combined consolidated statement of operations. During the year ended December 31, 2013, ARP recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement of a portion of its then-existing term loan facility and a portion of the outstanding indebtedness under its revolving credit facility with a portion of the proceeds from its issuance of the 7.75% ARP Senior Notes (see Note 7), which is included within interest expense on the combined consolidated statement of operations. ARP notes receivable. At December 31, 2015 and 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. For each of the years ended December 31, 2015, 2014 and 2013, the Company recognized interest income within other, net on the Company’s combined consolidated statements of operations of approximately $0.1 million. At December 31, 2015 and 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 December 31, 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 the years ended December 31, 2015, 2014 and 2013, the Company recognized equity income of approximately $0.7 million, $1.1 million and $2.6 million, respectively, within other, net on the Company’s combined consolidated statements of operations. During the years ended December 31, 2015, 2014 and 2013, the Company received net cash distributions of approximately $2.8 million, $1.7 million and $1.0 million, respectively. On November 6, 2013, Arc Logistics Partners. L.P. (“ARCX”), an MLP, owned and controlled by Lightfoot, which is involved in terminalling, storage, throughput and transloading of crude oil and petroleum products, began trading publicly on the NYSE under the ticker symbol “ARCX”.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	NOTE 6—ASSET RETIREMENT OBLIGATIONS 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 December 31, 2015, the Drilling Partnerships had $44.2 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 December 31, 2015, ARP has withheld approximately $5.2 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): Years Ended December 31, 2015 2014 2013 Asset retirement obligations, beginning of year $ 108,101 $ 91,214 $ 64,794 Liabilities incurred 2,074 3,677 6,401 Adjustment to liability due to acquisitions (Note 3) — 6,997 16,728 Liabilities settled (2,591 ) (1,664 ) (1,188 ) Accretion expense 6,325 5,759 4,479 Revisions — 2,118 — Asset retirement obligations, end of year $ 113,909 $ 108,101 $ 91,214 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.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	NOTE 7—DEBT Total debt consists of the following at the dates indicated (in thousands): December 31, 2015 2014 Term loan facilities $ 72,700 $ 148,125 ARP revolving credit facility 592,000 696,000 ARP term loan facility 243,783 — ARP 7.75% Senior Notes—due 2021 374,619 374,544 ARP 9.25% Senior Notes—due 2021 324,080 323,916 Total debt 1,607,182 1,542,585 Less current maturities (4,250 ) (1,500 ) Total long-term debt $ 1,602,932 $ 1,541,085 Term Loan Facilities On August 10, 2015, the Company entered into a credit agreement (the “First Lien Credit Agreement”) with Riverstone Credit Partners, L.P., as administrative agent, New Atlas Holdings, LLC, and the lenders party thereto, for a new term loan facility (the “First Lien Term Loan Facility”) in an aggregate principal amount of $82.7 million maturing in August 2020. The borrowings under the First Lien Term Loan Facility were used to repay in full outstanding borrowings under the Company’s then existing term loan facility. The Company’s obligations under the First Lien Term Loan Facility are secured on a first priority basis by security interests in substantially all of the assets of the Company and each of New Atlas Holdings, LLC, the Company’s direct wholly owned subsidiary, Atlas Lightfoot, LLC, and any other material subsidiary of the Company that later guarantees indebtedness under the First Lien Term Loan Facility, including all equity interests directly held by New Atlas Holdings, LLC or any guarantor and all tangible and intangible property of the Company and the guarantors (subject to certain customary exclusions and exceptions). Borrowings under the First Lien Term Loan Facility bear interest, at the Company’s option, at either (i) LIBOR plus 7.0% (as used with respect to the First Lien Term Loan Facility, “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%, each plus 6.0% (as used with respect to the First Lien Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. At December 31, 2015, $72.7 million was outstanding under the First Lien Term Loan Facility. At December 31, 2015, the weighted average interest rate on outstanding borrowings under the First Lien Term Loan Facility was 8.0%. The First Lien 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 First Lien Credit Agreement also required that (a) the Total Leverage Ratio (as defined in the First Lien Credit Agreement) not be greater than 4.00 to 1.00 as of the last day of any four consecutive fiscal quarter period, beginning with the fiscal quarter ending March 31, 2016; (b) the Company have liquidity of not less than $5 million as of the last day of any fiscal quarter, beginning with the fiscal quarter ending December 31, 2015; and (c) the Asset Coverage Ratio (as defined in the First Lien Credit Agreement) not be less than 1.75 to 1.00 as of the last day of any fiscal quarter beginning with the fiscal quarter ending September 30, 2015 and ending with (but including) the fiscal quarter ending June 30, 2016. The Company was in compliance with these covenants as of December 31, 2015. The Company has the right at any time to prepay any borrowings outstanding under the First Lien Term Loan Facility, subject to the payment of a prepayment premium specified therein. Subject to certain exceptions, the Company may also be required to prepay all or a portion of the First Lien Term Loan Facility in certain instances, including the following: · at the end of each fiscal quarter, the Company must repay the First Lien Term Loan Facility in an amount equal to: (i) if the Total Leverage Ratio as of the last day of such fiscal quarter is equal to or greater than 3.50 to 1.00, 100% of Distributable Cash (as defined in the First Lien Credit Agreement), (ii) if the Total Leverage Ratio as of the last day of such fiscal quarter is equal to or greater than 3.00 to 1.00 but less than 3.25 to 1.00, 75% of Distributable Cash, (iii) if the Total Leverage Ratio as of the last day of such fiscal quarter is equal to or greater than 2.75 to 1.00 but less than 3.00 to 1.00, 50% of Distributable Cash, (iv) if the Total Leverage Ratio as of the last day of such fiscal quarter is equal to or greater than 2.50 to 1.00 but less than 2.75 to 1.00, 25% of Distributable Cash, and (v) if the Total Leverage Ratio as of the last day of such fiscal quarter is less than 2.50 to 1.00, 0% of Distributable Cash. · Beginning with July 2016, if the Company’s Asset Coverage Ratio is less than 2.00 to 1.00, the Company must either prepay the First Lien Term Loan Facility or provide additional oil and gas properties to be subject to the lien of the administrative agent under the First Lien Term Loan Facility, in each case in an amount necessary to achieve an Asset Coverage Ratio of greater than 2.00 to 1.00; · if the Company or any of its restricted subsidiaries disposes of property or assets (including equity interests) to a person other than a loan party or receives insurance or condemnation proceeds following a casualty event, the Company must repay the First Lien Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event (subject to certain reinvestment rights); and · if the Company or any of its restricted subsidiaries issues or incurs any debt not permitted under the First Lien Term Loan Facility or issues any equity (subject to certain exceptions), the Company must repay the First Lien Term Loan Facility in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity. On March 30, 2016, the Company entered into a Third Amendment to its First Lien Credit Agreement and a new Second Lien Credit Agreement, both of which modify the terms of the facilities in material ways. Please see “Subsequent Events.” 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 provided 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”). In June 2015, the Company prepaid $33.1 million on the Term Loan Facilities in connection with the Arkoma Acquisition (see Note 3). On August 10, 2015, the Company repaid in full the remaining $82.7 million outstanding under 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 then existing term loan (see Note 2). The Interim Term Loan Facility matured on August 27, 2015 and the Term Loan A Facility was to mature on February 26, 2016. The Company’s obligations under the Term Loan Facilities were 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 bore interest, at the Company’s option, at either (i) LIBOR plus 7.5% (as used with respect to the Term Loan Facilities, “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% (as was used with the Term Loan Facilities, an “ABR Loan”). Interest was generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans. The Company had 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 was repaid prior to the Term Loan A Facility. Subject to certain exceptions, the Company may also have been 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) was less than 2.00 to 1.00, the Company must have prepaid 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 was equal to the ratio of the Recognized Value (the sum of the discounted net present values of the Loan Parties’ oil and gas properties and the values of the common units, Class A Units and Class C Units of ARP, determined as set forth in the Credit Agreement) to Total Funded Debt (as defined in the Credit Agreement); · if the Company disposed of all or any portion of the Arkoma Assets (as defined in the Credit Agreement), the Company must have prepaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds resulting from such disposition; · if the Company or any of its restricted subsidiaries disposed of property or assets (including equity interests), the Company must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds from such disposition or casualty event; and; · if the Company incurred any debt or issues any equity, it must have repaid the Term Loan Facilities in an aggregate principal amount equal to 100% of the net cash proceeds of such issuances or incurrences of debt or issuances of equity. The Credit Agreement contained customary covenants that limited 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 Credit Agreement also required that the Total Leverage Ratio (as defined in the Credit Agreement) not be greater than (i) as of the last day of any fiscal quarter prior to the full repayment of the Interim Term Loan Facility, 3.75 to 1.00, and (ii) as of the last day of any quarter thereafter, 3.50 to 1.00. In connection with the Term Loan Facilities, the lenders thereunder syndicated participations in loans underlying the facilities. As a result, certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and a 5% or more unitholder participated in approximately 12% of the loan syndication. 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 from time to time, the “ARP Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto, which provides for a senior secured revolving credit facility with a borrowing base of $700.0 million as of December 31, 2015 and a maximum facility amount of $1.5 billion scheduled to mature in July 2018. On November 23, 2015, ARP entered into an Eighth Amendment to the ARP Credit Agreement. Among other things, the Eighth Amendment: · reduced the borrowing base under the ARP Credit Agreement from $750.0 million to $700.0 million; · increases the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels; · permits the incurrence of third lien debt subject to the satisfaction of certain conditions, including pro forma financial covenant compliance; · upon the issuance of any third lien debt, reduces the borrowing base by 25% of the stated amount of such third lien debt (other than third lien debt that is used to refinance senior notes, second lien debt and other third lien debt); · suspended compliance with a maximum ratio of Total Funded Debt (as defined in the ARP Credit Agreement) to EBITDA (as defined in the ARP Credit Agreement) until the four fiscal quarter period ending March 31, 2017 and revised the maximum ratio of Total Funded Debt to EBITDA to be 5.75 to 1.00 for the four quarter periods ending March 31, 2017 and June 30, 2017, 5.50 to 1.00 for the four quarter periods ending September 30, 2017 and December 31, 2017, 5.25 to 1.00 for the four quarter period ending March 31, 2018, and 5.00 to 1.00 for each four fiscal quarter period ending thereafter; · replaced the requirement to maintain compliance with a maximum ratio of Senior Secured Total Funded Debt to EBITDA with a requirement to be in compliance with a maximum ratio of First Lien Debt (as defined in the ARP Credit Agreement) to EBITDA of 2.75 to 1.00; and · reset the distribution to $0.15 per common unit and permits increases to the distribution per common unit if (a) the ratio of Total Funded Debt (as of such date) to EBITDA for the most recent four fiscal quarters is equal to or less than 5.00 to 1.00 and (b) the borrowing base utilization is less than or equal to 85%, on a pro forma basis after giving effect to the distribution payment. A Seventh Amendment to the ARP Credit Agreement was entered into on July 24, 2015. Among other things, the Seventh Amendment redefined EBITDA. A Sixth Amendment to the ARP Credit Agreement was entered into on February 23, 2015. Among other things, the Sixth Amendment: · reduced the borrowing base under the ARP Credit Agreement from $900.0 million to $750.0 million; · permitted the incurrence of second lien debt in an aggregate principal amount up to $300.0 million; · rescheduled the May 1, 2015 borrowing base redetermination to July 1, 2015; · if the borrowing base utilization (as defined in the ARP Credit Agreement) is less than 90%, increases the applicable margin on Eurodollar loans and ABR loans by 0.25% from previous levels, · following the next scheduled redetermination of the borrowing base, upon the issuance of senior notes or the incurrence of second lien debt, reduces the borrowing base by 25% of the stated amount of such senior notes or additional second lien debt; and · revised the maximum ratio of Total Funded Debt to EBITDA to be (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. ARP’s borrowing base is scheduled for semi-annual redeterminations in May and November of each year. In February 2015, the borrowing base was reduced from $900 million to $750 million in connection with the Sixth Amendment to the ARP Credit Agreement; in July 2015 (the rescheduled redetermination date in the Sixth Amendment to the ARP Credit Agreement), the determination by the lenders reaffirmed ARP’s $750 million borrowing base in connection with the Seventh Amendment to the ARP Credit Agreement; and in November 2015, the borrowing base was reduced from $750 million to $700 million in connection with the Eighth Amendment to the ARP Credit Agreement. 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. In addition, the ARP Credit Agreement provides that our borrowing base will be reduced by 25% of the stated amount of any third lien debt issued (other than third lien debt that is used to refinance senior notes, second lien debt and other third lien debt). At December 31, 2015, $592.0 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 $4.2 million was outstanding at December 31, 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 2.00% and 3.00% per annum (which shall change depending on the borrowing base utilization percentage) 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 1.00% and 2.00% per annum(which shall change depending on the borrowing base utilization percentage. 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 December 31, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 3.25%. The ARP Credit Agreement contains customary covenants including, without limitation, covenants that limit ARP’s ability to incur additional indebtedness (but which permits second lien debt in an aggregate principal amount of up to $300.0 million and third lien debt that satisfies certain conditions including pro forma financial covenants), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merge or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP Credit Agreement also requires that ARP maintain a ratio of First Lien Debt to EBITDA of 2.75 to 1.00 as set forth in the Eighth Amendment described above, 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. ARP was in compliance with these covenants as of December 31, 2015. Based on the definitions contained in the ARP Credit Agreement, at December 31, 2015, ARP’s ratio of current assets to current liabilities was 1.3 to 1.0, and its ratio of First Lien Debt to EBITDA was 2.3 to 1.0. Although ARP currently expects its sources of capital to be sufficient to meet its near-term liquidity needs, there can be no assurance that the lenders under its credit facility will not reduce the borrowing base to an amount below its outstanding borrowings or that its liquidity requirements will continue to be satisfied, given current oil prices and the discretion of its lenders to decrease its borrowing base. Due to the steep decline in commodity prices, ARP may not be able to obtain funding in the equity or capital markets on terms it finds acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in some cases, ceased to provide any new funding. If the borrowing base determinations in May and/or November 2016 result in a borrowing base deficiency and ARP cannot access the capital markets and repay debt under its credit facility, ARP may be unable to continue to pay distributions to its unitholders and may take other actions to reduce costs and to raise funds to repay debt, such as selling assets or monetizing derivative contracts. 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 $6.2 million at December 31, 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 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 last day of the applicable interest period (or, with respect to interest periods of more than three-months’ duration, each day prior to the last day of such interest period that occurs at intervals of three months’ duration after the first day of such interest period) for Eurodollar loans and quarterly for ABR loans. At December 31, 2015, the weighted average interest rate on outstanding borrowings under the term loan facility was 10.0%. The ARP Second Lien Credit Agreement contains customary covenants including, without limitation, 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 ARP 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 December 31, 2015. Under the ARP 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. ARP Senior Notes At December 31, 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 December 31, 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 indenture governing the 7.75% Senior Notes (the “7.75% Senior Notes Indenture”)), plus accrued and unpaid interest and additional 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. On December 29, 2015, ARP entered into a Third Supplemental Indenture to the 7.75% Senior Notes Indenture following the receipt of requisite consents of the holders of the 7.75% Senior Notes pursuant to a consent solicitation in respect of the 7.75% Senior Notes that commenced on December 10, 2015. As a result of the consent solicitation, ARP paid a consent fee of $10.00 for each $1,000 in principal amount of the 7.75% ARP Senior Notes for a total of approximately $3.8 million that was capitalized as deferred financing costs. Consents were received for the purpose of making the following amendments to the 7.75% Senior Notes Indenture: (1) Increasing the fixed dollar amount in the basket for secured credit facility indebtedness to $1,000.0 million, the approximate amount of secured credit facility indebtedness currently permitted under ARP’s secured credit facilities, from $500.0 million. The use of secured indebtedness incurred under such basket in exchange for the 7.75% ARP Senior Notes or the 9.25% ARP Senior Notes (as defined below) will be limited to a maximum amount of $100 million, and the subsidiaries of ARP that issued the 7.75% ARP Senior Notes (the “Issuers”) will be required to make any offer to exchange the 7.75% ARP Senior Notes for secured indebtedness of the Issuers incurred under such basket to all holders of the 7.75% ARP Senior Notes on a pro rata basis and to make any offer to exchange the 9.25% Senior Notes for secured indebtedness of the Issuers incurred under such basket to all holders of the 9.25% ARP Senior Notes on a pro rata basis. (2) Adding an additional covenant providing that ARP will not permit its consolidated senior secured interest expense to exceed the greater of $80 million in any fiscal year or 8.0% of the consolidated senior secured debt outstanding as of the last day of any fiscal year for which audited financial statements have been provided, subject to certain adjustments and cure rights. (3) Adding a prohibition with respect to certain make-whole, yield maintenance, redemption, repayment or any other payments, premiums, fees or penalties, providing that such payments or premiums shall not be payable after and during the continuance of an event of default, upon the automatic or other acceleration of such indebtedness prior to its stated maturity date, or after the commencement of a case with respect to the Issuers under bankruptcy law. At December 31, 2015, ARP had $324.1 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 $0.9 million unamortized discount as of December 31, 2015. Interest on the 9.25% ARP Senior Notes is payable semi-annually on February 15 and August 15. 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 indenture governing the 9.25% Senior Notes (the “9.25% ARP Senior Notes 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. On December 17, 2015, ARP entered into a Fourth Supplemental Indenture to the 9.25% ARP Senior Notes Indenture following the receipt of requisite consents of the holders of the 9.25% ARP Senior Notes pursuant to a consent solicitation in respect of the 9.25% Senior Notes that commenced on December 10, 2015. As a result of the consent solicitation, ARP paid a consent fee of $10.00 for each $1,000 in principal amount of the 9.25% ARP Senior Notes for a total of approximately $3.3 million that was capitalized as deferred financing costs. Consents were received for the primary purpose of increasing the fixed dollar amount in the basket for secured credit facility indebtedness to $1,050.0 million, the approximate amount of secured credit facility indebtedness currently permitted under ARP’s secured credit facilities, from $500.0 million. The use of secured indebtedness incurred under such basket in exchange for the 7.75% ARP Senior Notes or the 9.25% ARP Senior Notes will be limited to a maximum amount of $100 million. 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, subject to certain customary automatic release provisions, including, in certain circumstances, the sale or other disposition of all or substantially all the assets of, or all of the equity interests in, the subsidiary guarantor, or the subsidiary guarantor is declared “unrestricted” for covenant purposes, 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 without limitation covenants that limit 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 inter

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 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 the use of 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 ethane, propane, butane and iso butane contracts are based on the respective Mt. Belvieu price. 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 $358.1 million and $274.9 million at December 31, 2015 and 2014, respectively. Of the $4.3 million of net gain in accumulated other comprehensive income within unitholders’ equity on the Company’s combined consolidated balance sheet related to derivatives at December 31, 2015, the Company expects to reclassify $3.7 million of gains to its combined consolidated statement of operations over the next twelve-month period as these contracts expire. Aggregate gains of $0.6 million of gas and oil production revenues will be reclassified to the Company’s combined consolidated statements of operations in later periods as the remaining contracts expire. During the year ended December 31, 2014, $2.5 million of derivative gains were reclassified from accumulated other comprehensive income related to derivative instruments entered into during that same period. No derivatives were reclassified from accumulated other comprehensive income related to derivatives instruments entered into during the year ended December 31, 2015. The following table summarizes the commodity derivative activity and presentation in the Company’s consolidated statement of operations for the year ended December 31, 2015 (in thousands): Year Ended December 31, 2015 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ 86,328 Portion of settlements attributable to subsequent mark to market gains (2) 93,182 Total cash settlements on commodity derivative contracts $ 179,510 Gains recognized prior to settlement (2) 40,930 Gains recognized on open derivative contracts, net of amounts recognized in income in prior year (2) 227,155 Gains on mark-to-market derivatives $ 268,085 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. During the years ended December 31, 2014 and 2013, the Company reclassified from accumulated other comprehensive income losses of $7.7 million and gains of $10.2 million on settled contracts covering commodity production. These gains and losses were included within gas and oil production revenue in the Company’s combined consolidated statements of operations During the year ended December 31, 2015, the Company received approximately $4.9 million in net proceeds from the early termination of its remaining natural gas and oil derivative positions for production periods from 2015 through 2018. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under the Company’s Term Loan Facilities (see Note 7). Atlas Growth Partners On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of December 31, 2015, 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. Obligations under the credit facility are secured by mortgages on AGP’s oil and gas properties and first priority security interest in substantially all of its assets. 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 December 31, 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 Amounts Recognized Gross Amounts Offset Net Amount Presented Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 399 $ (96 ) $ 303 Long-term portion of derivative assets 162 (53 ) 109 Total derivative assets $ 561 $ (149 ) $ 412 Current portion of derivative liabilities $ (96 ) $ 96 $ — Long-term portion of derivative liabilities (53 ) 53 — Total derivative liabilities $ (149 ) $ 149 $ — No derivatives were held by AGP at December 31, 2014. At December 31, 2015, AGP had the following commodity derivatives: Crude Oil – Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset/(Liability) (Bbl) (1) (per Bbl) (1) (in thousands) (2) 2016 76,000 $ 45.229 $ 303 2017 37,100 $ 49.968 127 2018 26,500 $ 48.850 (18 ) AGP’s net assets $ 412 (1) “Bbl” represents barrels. (2) Fair value based on forward WTI crude oil prices, as applicable. Atlas Resource Partners 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 Amounts Recognized Gross Amounts Offset Net Amount Presented Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 159,460 $ — $ 159,460 Long-term portion of derivative assets 198,262 — 198,262 Total derivative assets $ 357,722 $ — $ 357,722 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — Offsetting Derivatives 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 Current portion of derivative liabilities $ (98 ) $ 98 $ — Long-term portion of derivative liabilities (370 ) 370 — Total derivative liabilities $ (468 ) $ 468 $ — At December 31, 2014, ARP had net cash proceeds of $0.2 million related to ARP’s hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Company’s combined consolidated balance sheet. ARP allocated the monetization net proceeds to the Drilling Partnerships’ limited partners based on their natural gas and oil production generated over the period of the original derivative contracts during the year ended December 31, 2015. During the year ended December 31, 2013, ARP entered into contracts which provided the option to enter into swaptions up through September 30, 2013 for production volumes related to assets acquired from EP Energy (see Note 3). In connection with these swaption contracts, ARP paid premiums of $14.5 million, which represented their fair value on the date the transactions were initiated and were initially recorded as a derivative asset on the Company’s combined consolidated balance sheet and were fully amortized as of September 30, 2013. Swaption contract premiums paid are amortized over the period from initiation of the contract through their termination date. For the year ended December 31, 2013, ARP recognized $14.5 million of amortization expense in other, net on the Company’s combined consolidated statement of operations related to the swaption contracts. At December 31, 2015, ARP had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2016 53,546,300 $ 4.229 $ 92,131 2017 49,920,000 $ 4.219 67,916 2018 40,800,000 $ 4.170 47,153 2019 15,960,000 $ 4.017 13,839 $ 221,039 Natural Gas – Put Options – Drilling Partnerships Production Period Ending December 31, Option Type Volumes Average Fixed Price Fair Value Asset (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2016 Puts purchased 1,440,000 $ 4.150 $ 2,393 $ 2,393 Natural Gas Liquids – Crude Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 84,000 $ 85.651 $ 3,651 2017 60,000 $ 83.780 2,124 $ 5,775 Crude Oil – Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 1,557,000 $ 81.471 $ 61,284 2017 1,140,000 $ 77.285 33,335 2018 1,080,000 $ 76.281 26,248 2019 540,000 $ 68.371 7,648 $ 128,515 ARP’s net assets $ 357,722 (1) “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. (2) Fair value based on forward NYMEX natural gas prices, as applicable. (3) Fair value based on forward WTI crude oil prices, as applicable. 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 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 December 31, 2015, net derivative assets of $2.4 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts. At December 31, 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 the ultimate 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	12 Months Ended
	Dec. 31, 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 values were 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 December 31, 2015 and 2014 was as follows (in thousands): Level 1 Level 2 Level 3 Total As of December 31, 2015 Assets, gross Rabbi trust $ 5,584 $ — $ — $ 5,584 ARP Commodity swaps — 355,329 — 355,329 ARP Commodity puts — 2,393 — 2,393 AGP Commodity swaps — 561 — 561 Total assets, gross 5,584 358,283 — 363,867 Liabilities, gross ARP Commodity swaps — — — — ARP Commodity puts — — — — AGP Commodity swaps — (149 ) — (149 ) Total derivative liabilities, gross — (149 ) — (149 ) Total assets, fair value, net $ 5,584 $ 358,134 $ — $ 363,718 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 December 31, 2015 and 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 $929.2 million and $1,363.4 million, respectively, compared with the carrying amounts of $1,607.2 million and $1,542.6 million, respectively. The carrying values of outstanding borrowings under the respective revolving credit facilities, which bear interest at variable interest rates, approximated their estimated fair values. The estimated fair values of the ARP senior notes and term loan credit facility were based upon the market approach and calculated using the yields of the ARP senior notes and term loan facility 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 years ended December 31, 2015 and 2014 was as follows (in thousands): Years Ended December 31, 2015 2014 Level 3 Level 3 Asset retirement obligations $ 2,074 $ 10,674 Total $ 2,074 $ 10,674 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. See Note 4 for a discussion of current year impairments. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs. 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). During the year ended December 31, 2013, ARP completed the acquisition of certain oil and gas assets from EP Energy (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 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 required significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuations, which were finalized in 2015.

Certain Relationships and Relat

Certain Relationships and Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Certain Relationships And Related Party Transactions	NOTE 10—CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS Relationship with ARP. ARP does not directly employ any persons to manage or operate its business. These functions are provided by employees of the Company and/or its affiliates. Relationship with AGP . AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of the Company and/or its affiliates. Atlas Growth Partners, GP (“AGP GP”) receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the years ended December 31, 2015 and 2014, AGP paid approximately $1.8 million and $0.3 million related to AGP GP for this management fee. AGP did not pay a management fee for the period ended December 31, 2013. Other indirect costs, such as rent for offices, are allocated to AGP by the Company based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses the Company at cost for direct costs incurred on its behalf. AGP will reimburse all necessary and reasonable costs allocated by the general partner. AGP was required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to its private placement offering and the formation and financing of AGP, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of its private placement offering. 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 the ultimate general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the ultimate 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. Other Relationships . The Company has other related party transactions with regard to its Term Loan Facilities (see Note 7), its Series A preferred units (Note 12), its general partner and limited partner interest in Lightfoot (see Note 5) and the Eagle Ford Acquisition (see Note 3).

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 11—COMMITMENTS AND CONTINGENCIES General Commitments The Company leases office space and equipment under leases with varying expiration dates. Rental expense was $16.2 million, $17.5 million, and $13.1 million for the years ended December 31, 2015, 2014, and 2013, respectively. Future minimum rental commitments for the next five years are as follows (in thousands): Years Ended December 31, 2016 $ 3,875 2017 3,637 2018 3,261 2019 1,662 2020 1,590 Thereafter 1,849 $ 15,874 ARP is the ultimate 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 December 31, 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 years ended December 31, 2015, 2014 and 2013, $1.7 million, $5.3 million and $9.6 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 was to be paid by AGP. ARP’s and AGP’s deferred purchase obligation was included within deferred acquisition purchase price on the Company’s combined consolidated balance sheets at December 31, 2014 (see Note 3). Estimated fixed and determinable portions of ARP’s gathering obligations as of December 31, 2015 were as follows: 2016— $0.4 million; 2017 to 2020— none. 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 December 31, 2015 were as follows: 2016— $3.7 million; 2017— $2.6 million; 2018— $1.8 million; 2019— $1.8 million; 2020— $1.8 million; thereafter— $4.9 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 December 31, 2015 were as follows: 2016— $2.2 million; and 2017 to 2020— none. As of December 31, 2015, the Company’s subsidiaries are committed to expend approximately $7.1 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	12 Months Ended
	Dec. 31, 2015
Proceeds From Issuance Or Sale Of Equity [Abstract]
Issuances of Units	NOTE 12—ISSUANCES OF UNITS The Company recognizes gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on its combined consolidated balance sheets rather than as income or loss on its combined consolidated statements of operations. These gains or losses represent the Company’s portion of the excess or the shortage of the net offering price per unit of each of ARP’s and AGP’s common units as compared to 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. The Company sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to the Company of $40.0 million. The Company used the proceeds to fund a portion of the $150.0 million payment by the Company to Atlas Energy related to the repayment of Atlas Energy’s term loan (see Note 2). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities. On August 26, 2015, at a special meeting of the unitholders of the Company, the unitholders approved changes to the terms of the Series A Preferred Units to provide that each Series A Preferred Unit will be convertible into common units at the option of the holder. Atlas Resource Partners In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”) which ARP terminated and replaced in November 2015, when ARP entered into a distribution agreement (the “Distribution Agreement”) with MLV and FBR Capital Markets & Co. (“FBR” and, together with MLV, the “Agents”). Pursuant to the Distribution Agreement, ARP may sell from time to time to or through the Agents ARP’s 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and Class E ARP Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”) (together with the Class D ARP Preferred Units, the “ARP Preferred Units” having an aggregate offering price of up to $100 million. Sales of ARP Preferred 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 of 1933, as amended, including sales made to or through a market maker other than on an exchange or through an electronic communications network and sales made directly on the New York Stock Exchange, the existing trading market for the ARP Preferred Units. Under the terms of the distribution agreement, ARP may sell ARP Preferred Units from time to time to each Agent as principal for its respective account at a price equal to 97.0% of the volume weighted average price of the Class D ARP Preferred Units or Class E ARP Preferred Units, as applicable, on the date of sale. Upon the sale of ARP Preferred Units to an Agent as principal, ARP and such Agent will enter into separate terms agreement with respect to such sale. The ARP Preferred Units may also be offered by the Sales Agent as agents for ARP at negotiated prices or prevailing market prices at the time of sale. ARP will pay each Agent a commission on Units sold by it in an agency capacity, which shall not be more than 3.0% of the gross sales price of ARP Preferred Units sold through the Agent as agent for ARP. Under the August 2015 ARP Distribution Agreement, ARP issued 90,328 Class D ARP Preferred Units and 1,083 Class E ARP Preferred Units for net proceeds of $0.9 million, net of $0.3 million in commissions and offering expenses paid. Under the November 2015 ARP Distribution Agreement, ARP did not issue any Class D ARP Preferred Units nor Class E ARP Preferred Units under the preferred equity distribution program, but incurred $0.1 million of net offering expenses. In July 2015, the remaining 39,654 Class B ARP Preferred Units were voluntarily converted into common limited partner units. 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 $49.7 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 cumulative distributions on a quarterly basis at an annual rate of $2.6875 per unit or at a rate of 10.75% per annum of the stated liquidation preference of $25.00. In October 2014, ARP issued 3,200,000 8.625% Class D ARP 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 (see Note 3). 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. 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 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. Additionally, if at any time ARP’s general partner and its affiliates own more than two-thirds of the outstanding class of any limited partner interests, ARP’s general partner will have the right, which it may assign to any of its affiliates or to ARP, to acquire all, but not less than all, of such class of limited partner interests held by unaffiliated persons at a price equal to the greater of (1) the highest cash price paid by ARP’s general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which ARP’s general partner first mails notice of its election to purchase those limited partner interests; and (2) the average of the daily closing prices of the limited partner interests of such class over the 20 trading days preceding the date three days before the date of the mailing of the exercise notice for such call right. 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 year ended December 31, 2015, ARP issued 9,803,451 common limited partner units under the equity distribution program for net proceeds of $44.2 million, net of $1.1 million in commissions and offering expenses paid. No units were sold under the equity distribution program during the year ended December 31, 2014. 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. In July 2013, in connection with the closing of the EP Energy Acquisition (see Note 3), ARP issued 3,749,986 of its newly created Class C convertible preferred units to Atlas Energy, at a negotiated price per unit of $23.10, for proceeds of $86.6 million. The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016. Unless previously converted, all Class C preferred units will convert into common units on July 31, 2016. Upon issuance of the Class C preferred units, Atlas Energy, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP‘s common units at an exercise price equal to the face value of the Class C preferred units. The warrants were exercisable beginning October 29, 2013 into an equal number of common units of ARP at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016. Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants. The Partnership filed a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and the registration statement was declared effective on March 27, 2015. In June 2013, in connection with the EP Energy Acquisition (see Note 3), ARP sold an aggregate of 14,950,000 of its common limited partner units (including 1,950,000 units pursuant to an over-allotment option) in a public offering at a price of $21.75 per unit, yielding net proceeds of approximately $313.1 million. ARP utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 7). In May 2013, ARP entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, ARP could sell, from time to time through the agents, common units having an aggregate offering price of up to $25.0 million. During the year ended December 31, 2013, ARP issued 309,174 common limited partner units under the equity distribution program for net proceeds of $6.9 million, net of $0.4 million in commissions and net offering costs paid. ARP utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. ARP terminated this equity distribution agreement effective December 27, 2013. Atlas Growth Partners Under the terms of AGP’s initial offering, AGP offered in a private placement $500.0 million of its common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. AGP exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which AGP gives the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of AGP’s assets. Through the termination of AGP’s private placement offering on June 30, 2015, AGP issued an aggregate of 23,300,410 of its common units in exchange for proceeds to AGP, net of dealer manager fees and commissions and expenses, of $203.4 million. The Company purchased 500,010 common units for $5.0 million during the offering. AGP has issued approximately $233.0 million of its common limited partner units through the private placement offering that expired on June 30, 2015. During the year ended December 31, 2015, AGP sold an aggregate of 12,623,500 of its common limited partner units at a gross offering price of $10.00 per unit, resulting in proceeds of $112.7 million to AGP, net of dealer manager fees and commissions and expenses of $12.7 million. Of such amount, the Company purchased $2.7 million, or 300,000 common units, during the year ended December 31, 2015. In connection with the issuance of common limited partner units in 2015, unitholders received 1,262,350 warrants to purchase AGP’s common units at an exercise price of $10.00 per unit. During the year ended December 31, 2014, AGP sold an aggregate of 9,581,900 of its common limited partner units at a gross offering price of $10.00 per unit, resulting in proceeds of $81.6 million to AGP, net of dealer manager fees and commissions and expenses of $14.0 million, which was included within non-controlling interests on the Company’s combined consolidated balance sheet. The Company did not purchase common units during the year ended December 31, 2014. In connection with the issuance of common limited partner units in 2014, unitholders received 958,190 warrants to purchase AGP’s common limited partner units at an exercise price of $10.00 per unit. During the period ended December 31, 2013, AGP sold an aggregate of 1,095,010 of its common limited partner units at a gross offering price of $10.00 per unit, resulting in proceeds of $8.2 million to AGP, net of dealer manager fees and commissions and expenses of $1.9 million. Of such amount, the Company purchased $1.8 million, or 200,010 common units, during the year ended December 31, 2013. In connection with the issuance of common limited partner units in 2013, unitholders received 109,501 warrants to purchase AGP’s common limited partner units at an exercise price of $10.00 per unit. In connection with the issuance of ARP’s and AGP’s unit offerings during the year ended December 31, 2015, the Company recorded gains of $4.3 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 $45.0 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	12 Months Ended
	Dec. 31, 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 Ended Total Cash Distribution To Common Unitholders Total Cash Distribution To Preferred Unitholders May 15, 2015 March 31, 2015 $ — $ 333 June 12, 2015 April 30, 2015 $ — $ 334 July 15, 2015 May 31, 2015 $ — $ 334 August 14, 2015 June 30, 2015 $ — $ 335 September 14, 2015 July 31, 2015 $ — $ 336 October 15, 2015 August 31, 2015 $ — $ 336 November 13, 2015 September 30, 2015 $ — $ 337 December 15, 2015 October 31, 2015 $ — $ 337 January 14, 2016 November 30, 2015 $ — $ 338 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. 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 $25.00 liquidation preference. ARP pays distributions on the Class E ARP Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference. Distributions declared by ARP from January 1, 2013 through December 31, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Ended Cash Distribution per Common Limited Partner Unit Total Cash Distribution to Common Limited Partners Total Cash Distribution To Preferred Limited Partners (1) Total Cash Distribution to the General Partner’s Class A Units May 15, 2013 March 31, 2013 $ 0.5100 $ 22,428 $ 1,957 $ 946 August 14, 2013 June 30, 2013 $ 0.5400 $ 32,097 $ 2,072 $ 1,884 November 14, 2013 September 30, 2013 $ 0.5600 $ 33,291 $ 4,248 $ 2,443 February 14, 2014 December 31, 2013 $ 0.5800 $ 34,489 $ 4,400 $ 2,891 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 August 14, 2015 June 30, 2015 $ 0.1083 $ 10,309 $ 637 (2) $ 223 September 14, 2015 July 31, 2015 $ 0.1083 $ 10,571 $ 638 (2) $ 229 October 15, 2015 August 31, 2015 $ 0.1083 $ 10,949 $ 637 (2) $ 236 November 13, 2015 September 30, 2015 $ 0.1083 $ 11,063 $ 637 (2) $ 239 December 15, 2015 October 31, 2015 $ 0.0125 $ 1,277 $ 637 (2) $ 39 January 14, 2016 November 30, 2015 $ 0.0125 $ 1,277 $ 638 (2) $ 39 (1) (2) Date Cash Distribution Paid For the Period Cash Distribution per Class D Preferred Limited Partner Unit Total Cash Distribution To Class D Preferred Limited Partners January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.6169270 $ 1,974 April 15, 2015 January 15, 2015 – April 14, 2015 $ 0.5390630 $ 2,156 July 15, 2015 April 15, 2015 – July 14, 2015 $ 0.5390625 $ 2,157 October 15, 2015 July 15, 2015 – October 14, 2015 $ 0.5390625 $ 2,205 January 15, 2016 October 15, 2015 – January 14, 2016 $ 0.5390625 $ 2,205 Date Cash Distribution Paid For the Period Cash Distribution per Class E Preferred Limited Partner Unit Total Cash Distribution To Class E Preferred Limited Partners July 15, 2015 April 14, 2015 – July 14, 2015 $ 0.6793 $ 173 October 15, 2015 July 15, 2015 – October 14, 2015 $ 0.671875 $ 172 January 15, 2016 October 15, 2015 – January 14, 2016 $ 0.671875 $ 172 AGP Cash Distributions. AGP has a cash distribution policy under which it distributes to holders of common units and Class A units on a quarterly basis a target distribution of $0.175 per unit, or $0.70 per unit per year, to the extent AGP has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from AGP beginning with the quarter following the quarter in which AGP first admits them as limited partners. Distributions declared by AGP from January 1, 2014 through December 31, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For the Quarter Ended Cash Distribution per Common Limited Partner Unit Total Cash Distribution to Common Limited Partners Total Cash Distribution to the General Partner’s Class A Units February 14, 2014 (1) December 31, 2013 $ 0.1167 $ 120 $ 2 May 15, 2014 March 31, 2014 $ 0.1750 $ 223 $ 6 August 14, 2014 June 30, 2014 $ 0.1750 $ 342 $ 7 November 14, 2014 September 30, 2014 $ 0.1750 $ 841 $ 16 February 13, 2015 December 31, 2014 $ 0.1750 $ 1,636 $ 33 May 15, 2015 March 31, 2015 $ 0.1750 $ 2,180 $ 45 August 14, 2015 June 30, 2015 $ 0.1750 $ 2,646 $ 54 November 14, 2015 September 30, 2015 $ 0.1750 $ 4,078 $ 83 (1) Represents a pro-rated cash distribution of $0.1750 per common limited partner unit and general partner unit for the period from November 1, 2013, the date AGP commenced operations.

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 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 December 31, 2015, the Company had 2,564,910 phantom units and unit options outstanding under the 2015 LTIP, with 2,685,090 phantom 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 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 December 31, 2015, there are 840,894 units that will vest within the following twelve months. The director phantom units outstanding under the 2015 LTIP at December 31, 2015 include DERs. No amounts were paid during the years ended December 31, 2015, 2014, and 2013 with respect to DERs. The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding, beginning of year — $ — — $ — — $ — Granted 2,794,710 6.46 — — — — Vested (1) — — — — — — Forfeited (229,800 ) 6.43 — — — — Outstanding, end of year (2)(3) 2,564,910 $ 6.46 — $ — — $ — Non-cash compensation expense recognized (in thousands) $ 5,678 $ — $ — (1) No phantom unit awards vested during the years ended December 31, 2015, 2014 and 2013. (2) The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2015 was approximately $2.4 million. (3) There was approximately $32,000 recognized as liabilities on the Company’s consolidated balance sheet at December 31, 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 December 31, 2015. At December 31, 2015, the Company had approximately $10.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awards which is expected to be recognized over a weighted average period of 1.6 years. 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 December 31, 2015. No cash was received from the exercise of options for the years ended December 31, 2015, 2014 and 2013. 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. There were no restricted units granted, issued or outstanding through December 31, 2015. 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 December 31, 2015 and 2014, the Company reflected $5.6 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 $5.6 million and $3.9 million as of those same dates, respectively, within asset retirement obligations and other on its combined consolidated balance sheets. During the years ended December 31, 2015 and 2013, no distributions were made to Participants related to the rabbi trust. During the year ended December 31, 2014, the Company distributed $1.9 million 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 December 31, 2015, ARP had 1,656,630 phantom units, restricted units and unit options outstanding under the ARP LTIP with 187,633 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 December 31, 2015, 159,996 units will vest within the following twelve months. All phantom units outstanding under the ARP LTIP at December 31, 2015 include DERs. During the years ended December 31, 2015, 2014, and 2013, ARP paid $0.7 million, $2.0 million and $1.9 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: Years Ended December 31, 2015 2014 2013 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding, beginning of year 799,192 $ 22.70 839,808 $ 24.31 948,476 $ 24.76 Granted 9,730 8.50 264,173 19.44 145,813 21.87 Vested (1) (472,278 ) 23.55 (274,414 ) 24.46 (215,981 ) 24.73 Forfeited (34,539 ) 23.13 (30,375 ) 22.76 (38,500 ) 23.96 Outstanding, end of year (2)(3) 302,105 $ 20.87 799,192 $ 22.70 839,808 $ 24.31 Non-cash compensation expense recognized (in thousands) $ 4,124 $ 6,367 $ 9,166 (1) The intrinsic values of phantom unit awards vested during the years ended December 31, 2015, 2014 and 2013 were $4.0 million, $5.4 million and $6.1 million, respectively. (2) The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2015 was $0.3 million. (3) There were approximately $7,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at December 31, 2015 and 2014, respectively, representing 13,391 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 $13.07 and $21.16 at December 31, 2015 and 2014, respectively. At December 31, 2015, ARP had approximately $1.8 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 1.5 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 80,038 unit options outstanding under the ARP LTIP at December 31, 2015 that will vest within the following twelve months. No cash was received from the exercise of options for the years ended December 31, 2015, 2014 and 2013. The following table sets forth the ARP LTIP unit option activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number of Unit Options Weighted Average Exercise Price Number of Unit Options Weighted Average Exercise Price Number of Unit Options Weighted Average Exercise Price Outstanding, beginning of year 1,458,300 $ 24.66 1,482,675 $ 24.66 1,515,500 $ 24.68 Granted — — — — 5,000 21.56 Exercised (1) — — — — — — Forfeited (103,775 ) 24.67 (24,375 ) 24.52 (37,825 ) 24.80 Outstanding, end of year (2)(3) 1,354,525 $ 24.66 1,458,300 $ 24.66 1,482,675 $ 24.66 Options exercisable, end of year (4) 1,273,487 $ 24.67 730,775 $ 24.67 370,700 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 820 $ 1,700 $ 3,514 (1) No options were exercised during the years ended December 31, 2015, 2014 and 2013. (2) The weighted average remaining contractual life for outstanding options at December 31, 2015 was 6.4 years. (3) There were no aggregate intrinsic values of options outstanding at December 31, 2015 and 2014. The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000. (4) The weighted average remaining contractual life for exercisable options at December 31, 2015, 2014 and 2013 was 6.4 years, 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2015, 2014 and 2013. At December 31, 2015, ARP had approximately $44,000 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 0.4 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. The following weighted average assumptions were used for the options granted during the year ended December 31, 2013: Expected dividend yield 8.0 % Expected unit price volatility 35.5 % Risk-free interest rate 1.4 % Expected term (in years) 6.31 Fair value of unit options granted $ 2.95 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. There were no restricted units granted, issued or outstanding through December 31, 2015.

Operating Segment Information

Operating Segment Information	12 Months Ended
	Dec. 31, 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): Years Ending December 31, 2015 2014 2013 Atlas Resource: Revenues $ 740,033 $ 701,654 $ 474,476 Operating costs and expenses (320,922 ) (431,032 ) (351,673 ) Depreciation, depletion and amortization expense (157,978 ) (239,923 ) (139,783 ) Asset impairment (966,635 ) (573,774 ) (38,014 ) Loss on asset sales and disposal (1,181 ) (1,869 ) (987 ) Interest expense (102,133 ) (62,144 ) (34,324 ) Segment loss $ (808,816 ) $ (607,088 ) $ (90,305 ) Atlas Growth: Revenues $ 12,708 $ 5,707 $ 302 Operating costs and expenses (14,968 ) (13,816 ) (3,812 ) Depreciation, depletion and amortization expense (8,951 ) (2,156 ) (133 ) Asset impairment (7,346 ) (6,880 ) — Segment loss $ (18,557 ) $ (17,145 ) $ (3,643 ) Corporate and other: Revenues $ 752 $ 1,149 $ 321 General and administrative (30,862 ) (6,381 ) (8,162 ) Gain on asset sales and disposal — 10 — Interest expense (23,525 ) (11,291 ) (5,388 ) Loss on early extinguishment of debt (4,726 ) — — Segment loss $ (58,361 ) $ (16,513 ) $ (13,229 ) Reconciliation of segment loss to net loss: Segment loss: Atlas Resource $ (808,816 ) $ (607,088 ) $ (90,305 ) Atlas Growth (18,557 ) (17,145 ) (3,643 ) Corporate and other (58,361 ) $ (16,513 ) $ (13,229 ) Net loss $ (885,734 ) $ (640,746 ) $ (107,177 ) Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource $ 740,033 $ 701,654 $ 474,476 Atlas Growth 12,708 5,707 302 Corporate and other 752 1,149 321 Total revenues $ 753,493 $ 708,510 $ 475,099 Capital expenditures: Atlas Resource $ 127,138 $ 212,763 $ 263,886 Atlas Growth 29,222 12,873 3,594 Corporate and other — — — Total capital expenditures $ 156,360 $ 225,636 $ 267,480 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 $ 1,731,004 $ 2,798,120 Atlas Growth 160,267 190,161 Corporate and other 26,843 38,034 $ 1,918,114 $ 3,026,315

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	NOTE 16—SUBSEQUENT EVENTS The Company First Lien Credit Agreement Amendment . On March 30, 2016, the Company, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to that certain Credit Agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”). The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.25 million of the outstanding principal, which was classified as current portion of long-term debt on the Company’s consolidated balance sheet at December 31, 2015, and $0.5 million of interest. The Third Amendment amended the First Lien Credit Agreement to, among other things: · provide the ability for the Company and the Borrower to enter into the new Second Lien Credit Agreement; · shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee; · modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum; · allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million; · provide that the First Lien Credit Agreement may be prepaid without premium; · replace the existing financial covenants with (i) the requirement that the Company maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016; · prohibit the payment of cash distributions on the Company’s common and preferred units; · require the receipt of quarterly distributions from AGP and Lightfoot; and · add a cross-default provision for defaults by ARP. Second Lien Credit Agreement . Also on March 30, 2016, the Company and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement. Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If the Company’s market capitalization is greater than $75 million, it can issue common units in lieu of increasing the principal to satisfy the interest obligation. The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement. The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’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. In addition, the Second Lien Credit Agreement requires that the Company maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter. In connection with the Second Lien Credit Agreement, the Company agreed to issue within 30 days to the Lenders, warrants (the “Warrants”) to purchase up to 15% of the Company’s outstanding common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants will be subject to customary anti-dilution provisions. The Company also agreed to enter into a registration rights agreement pursuant to which it will agree to register the offer and resale of the common units underlying the Warrants on terms and conditions acceptable to the Lenders. As a result of the Third Amendment to the First Lien Credit Agreement and the Second Lien Credit Agreement, the Company’s and ARP’s future debt maturities, excluding any future payment-in-kind interest payments, are as follows: $4.3 million, $35 million, $592 million, $35 million, and $250 million, respectively, for each of the years ending December 31, 2016 through 2020; and $700 million thereafter. Cash Distributions. On January 28, 2016, the Company declared a monthly cash distribution of $0.3 million for the month ended December 31, 2015 related to its Series A Preferred Units. The distribution was paid on February 12, 2016 to unitholders of record at the close of business on February 6, 2016. On March 8, 2016, the Company declared a monthly cash distribution of $0.3 million for the month ended January 31, 2016 related to its Series A Preferred Units. The distribution was paid on March 16, 2016 to unitholders of record at the close of business on March 9, 2016. NYSE Compliance . On January 7, 2016, the Company was notified by the NYSE that it was not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of the common units had been less than $1.00 for 30 consecutive trading days. The Company also was notified by the NYSE on December 23, 2015, that it was not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company Manual because its average market capitalization had been less than $50 million for 30 consecutive trading days and its stockholders’ equity had been less than $50 million. On March 18, 2016, the Company was notified by the NYSE that it determined to commence proceedings to delist the Company’s common units from the NYSE as a result of the Company’s failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of the Company’s common units at the close of trading on March 18, 2016. The Company’s common units began trading on the OTCQX on Monday, March 21, 2016 under the ticker symbol: ATLS. Atlas Resource Partners Senior Note Repurchases . In January and February 2016, ARP executed transactions to repurchase portions of its senior unsecured notes. Through the end of February 2016, ARP has repurchased approximately $20.3 million of its 7.75% Senior Notes due 2021 and approximately $12.1 million of its 9.25% Senior Notes due 2021 for approximately $5.5 million. As a result of these transactions, ARP will recognize approximately $25.9 million as gain on early extinguishment of debt in the first quarter of 2016. Cash Distributions. On January 28, 2016, ARP declared a monthly distribution of $0.0125 per common unit for the month of December 31, 2015. The $2.0 million distribution, including approximately $39,000 and $0.6 million to the Company as the general partner and as holder of common units and Class C preferred limited units, respectively, was paid on February 12, 2016 to unitholders of record at the close of business on February 8, 2016. On February 24, 2016, ARP declared a monthly distribution of $0.0125 per common unit for the month of January 31, 2016. The $2.0 million distribution, including approximately $39,000 and $0.6 million to the Company as the general partner and as holder of common units and Class C preferred limited units, respectively, was paid on March 16, 2016 to unitholders of record at the close of business on March 9, 2016. On March 29, 2016, ARP declared a monthly distribution of $0.0125 per common unit for the month of February 29, 2016. The $2.0 million distribution, including approximately $39,000 and $0.6 million to the Company as the general partner and as holder of common units and Class C preferred limited units, respectively, will be paid on April 14, 2016 to unitholders of record at the close of business on April 8, 2016. On January 15, 2016, ARP paid a quarterly distribution of $0.5390625 per Class D Preferred Unit, or $2.2 million, for the period from October 15, 2015 through January 14, 2016 to Class D Preferred Unitholders of record as of January 4, 2016. On January 15, 2016, ARP paid a quarterly distribution of $0.671875 per Class E Preferred Unit, or $0.2 million, for the period from October 15, 2015 through January 14, 2016 to Class E Preferred Unitholders of record as of January 4, 2015. On March 22, 2016, ARP declared a quarterly distribution of $0.5390625 per Class D ARP Preferred Unit, or $2.2 million, for the period from January 15, 2016 through April 14, 2016, which will be paid on April 15, 2016, to Class D Preferred Unitholders of record as of April 1, 2016. On March 22, 2016, ARP declared a quarterly distribution of $0.671875 per Class E ARP Preferred Unit, or $0.2 million, for the period from January 15, 2016 through April 14, 2016, which will be paid on April 15, 2016, to Class E Preferred Unitholders of record as of April 1, 2016. NYSE Compliance . On January 12, 2016, ARP was notified by the NYSE that it was not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of its common units had been less than $1.00 for 30 consecutive trading days. ARP is working to remedy this situation in a timely manner as set forth in the applicable NYSE rules in order to maintain its listing on the NYSE. Atlas Growth Partners On February 5, 2016, AGP declared a quarterly distribution of $0.1750 per common unit for the quarter ended December 31, 2015. The $4.2 million distribution, including $0.1 million to its general partner, will be paid on February 12, 2016 to unitholders of record at the close of business on December 31, 2015.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Information (Unaudited)	NOTE 17—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil, Gas and NGL Reserve Information. The preparation of AGP’s and ARP’s natural gas, oil and NGL reserve estimates was completed in accordance with AGP’s and ARP’s prescribed internal control procedures by AGP’s and ARP’s reserve engineers. The accompanying reserve information included below was derived from the reserve reports prepared ARP’s annual reports on Form 10-K for the years ended December 31, 2015, 2014 and 2013. For the years ended 2015, 2014 and 2013, AGP’s information was derived from the reserve reports prepared for AGP’s registration statement on Form S-1 (Registration No. 333-207537). Other than for ARP’s Rangely assets, for the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas, oil and NGL reserves which are all located throughout the United States. The independent reserves engineer’s evaluation was based on more than 39 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For ARP’s Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 33 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. AGP’s and ARP’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by AGP’s and ARP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 17 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by the Senior Vice President. The reserve disclosures that follow reflect AGP’s and ARP’s estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows as of December 31, 2015, 2014 and 2013 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2015, 2014 and 2013, including adjustments related to regional price differentials and energy content. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within AGP and ARP or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved. Reserve quantity information and a reconciliation of changes in proved reserve quantities included within AGP and ARP are as follows (unaudited): Gas (Mcf) Oil (Bbls) NGLs (Bbls) Balance, January 1, 2013 573,774,257 8,868,836 16,061,897 Extensions, discoveries and other additions (1) 90,098,219 8,255,531 8,197,272 Sales of reserves in-place (2,755,155 ) — (4,625 ) Purchase of reserves in-place (2) 493,481,302 1,964 55,187 Transfers to limited partnerships (2,485,210 ) (239,910 ) (258,381 ) Revisions (3) (88,484,468 ) (1,412,371 ) (3,826,744 ) Production (59,849,442 ) (485,226 ) (1,267,590 ) Balance, December 31, 2013 1,003,779,503 14,988,824 18,957,016 Extensions, discoveries and other additions (1) 58,461,204 3,372,177 3,986,986 Sales of reserves in-place (169,035 ) (1,519 ) (11,326 ) Purchase of reserves in-place (2) 88,635,059 51,168,449 5,189,827 Transfers to limited partnerships (4,887,095 ) (684,613 ) (665,486 ) Revisions (3) 5,947,622 (4,639,546 ) (2,689,372 ) Production (86,889,803 ) (1,254,247 ) (1,387,865 ) Balance, December 31, 2014 1,064,877,455 62,949,525 23,379,780 Extensions, discoveries and other additions (1) 6,806,339 3,460,609 293,256 Sales of reserves in-place (4) (2,713,428 ) (2,393 ) — Purchase of reserves in-place — — — Transfers to limited partnerships (2,958,882 ) (481,771 ) (342,156 ) Revisions (3) (379,058,376 ) (11,223,648 ) (13,769,701 ) Production (79,266,969 ) (2,119,266 ) (1,084,848 ) Balance, December 31, 2015 607,686,139 52,583,056 8,476,331 Proved developed reserves at: January 1, 2013 338,655,324 3,400,447 7,884,778 December 31, 2013 766,872,394 3,459,260 7,676,389 December 31, 2014 889,073,136 31,150,298 12,209,825 December 31, 2015 568,793,757 27,129,766 6,488,931 Proved undeveloped reserves at: January 1, 2013 235,118,932 5,468,389 8,177,120 December 31, 2013 236,907,109 11,529,564 11,280,627 December 31, 2014 175,804,319 31,799,227 11,169,954 December 31, 2015 38,892,382 25,453,290 1,987,400 (1) For the year ended December 31, 2015, the increase represents PUD conversions related to development activity in the Eagle Ford Shale. For the year ended December 31, 2014, the increase was due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s Geomet Acquisitions. For the year ended December 31, 2013, the increase was primarily due to the addition of Marble Falls wells. (2) Represents the purchase of proved reserves due to the Rangely, Eagle Ford and GeoMet Acquisitions for the year ended December 31, 2014 and mainly due to the EP Energy Acquisition for the year ended December 31, 2013. (3) The downward revisions for the year ended December 31, 2015 were primarily due to wells being shut-in as well as unfavorable economic conditions primarily related to gas and oil commodity prices. For the year ended December 31, 2014, the downward revisions on oil and NGL were primarily due to wells being shut-in. The upward revision for the year ended December 31, 2014 on gas was primarily due to production outperforming previous forecasts. The downward revisions for the year ended December 31, 2013 were primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions. (4) Decrease mainly due to ARP's sale of the County Line assets. Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of AGP and ARP during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 Natural gas and oil properties: Proved properties $ 3,733,614 $ 3,639,833 Unproved properties 213,047 217,321 Support equipment 44,921 37,359 3,991,582 3,894,513 Accumulated depreciation, depletion and amortization (2,717,002 ) (1,518,686 ) Net capitalized costs $ 1,274,580 $ 2,375,827 Results of Operations from Oil and Gas Producing Activities. The results of operations related to AGP’s and ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 368,845 $ 475,758 $ 273,906 Production costs (171,882 ) (184,296 ) (100,178 ) Depreciation, depletion and amortization (153,938 ) (231,638 ) (132,860 ) Asset impairment (1) (973,981 ) (580,654 ) (38,014 ) $ (930,956 ) $ (520,830 ) $ 2,854 (1) During the year ended December 31, 2015, the Company recognized $974.0 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, and unproved acreage in the New Albany Shale, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income. During the year ended December 31, 2014, the Company recognized $580.7 million of asset impairment consisting of $562.6 million 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 net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. Costs Incurred in Oil and Gas Producing Activities. The costs incurred by AGP and ARP in their oil and gas activities during the periods indicated are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Property acquisition costs: Proved properties $ 55,033 $ 754,197 $ 863,421 Unproved properties 43,820 10,978 895 Exploration costs (1) 1,601 722 1,053 Development costs 102,110 177,726 214,383 Total costs incurred in oil & gas producing activities $ 202,564 $ 943,623 $ 1,079,752 (1) There were no exploratory wells drilled during the years ended December 31, 2015, 2014 and 2013. Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to AGP’s and ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2015, 2014 and 2013, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and include the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): Years Ended December 31, 2015 2014 2013 Future cash inflows $ 3,910,339 $ 10,802,697 $ 5,268,148 Future production costs (1,954,564 ) (4,561,129 ) (2,397,997 ) Future development costs (1,289,841 ) (1,623,218 ) (752,369 ) Future net cash flows 665,934 4,618,350 2,117,782 Less 10% annual discount for estimated timing of (90,703 ) (2,381,586 ) (1,038,491 ) Standardized measure of discounted future net $ 575,231 $ 2,236,764 $ 1,079,291 Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since AGP and ARP allocate taxable income to their owner, no recognition has been given to income taxes: Years Ended December 31, 2015 2014 2013 Balance, beginning of year $ 2,236,764 $ 1,079,291 $ 623,676 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas, net of related costs (1) (137,942 ) (275,789 ) (171,409 ) Net changes in prices and production costs (2 ) (1,629,945 ) 339,776 85,191 Revisions of previous quantity estimates (41,147 ) (33,526 ) (1,881 ) Development costs incurred 88,261 52,077 27,245 Changes in future development costs (167,995 ) (90,887 ) (21,579 ) Transfers to limited partnerships (13,291 ) (2,966 ) (53,392 ) Extensions, discoveries, and improved recovery less related costs 20,408 69,436 143,338 Purchases of reserves in-place (3) — 1,018,345 516,985 Sales of reserves in-place (4) (2,162 ) (332 ) (2,053 ) Accretion of discount 223,676 107,929 62,368 Estimated settlement of asset retirement obligations (224 ) (16,824 ) (18,858 ) Estimated proceeds on disposals of well equipment (1,172 ) (21,896 ) 17,052 Changes in production rates (timing) and other — 12,130 (127,392 ) Outstanding, end of year $ 575,231 $ 2,236,764 $ 1,079,291 (1) Includes the amount of sales of oil and gas previously included in proved reserves and sold during the period ended. (2) Decrease due to commodity price declines for the year ended December 31, 2015. (3) Represents the change in discounted value of the proved reserves primarily due to the purchase of proved reserves due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s Geomet Acquisitions for the period ended December 31, 2014 and primarily due to the purchase of proved reserves in Marble Falls for the period ended December 31, 2013. (4)

Quarterly Results (Unaudited)

Quarterly Results (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Results (Unaudited)	NOTE 18 — QUARTERLY RESULTS (UNAUDITED) Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2015: Revenues $ 146,613 $ 262,834 $ 98,247 $ 245,799 Net income (loss) (2) (297,357 ) (582,313 ) (59,543 ) 53,479 (Income) loss attributable to non-controlling interests 228,905 439,969 38,745 (58,303 ) Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — — — 10,475 Net income (loss) attributable to common unitholders $ (69,466 ) $ (143,353 ) $ (21,802 ) $ 5,318 Net income (loss) attributable to common unitholders per unit: Basic (1) $ (2.67 ) $ (5.51 ) $ (0.80 ) $ $0.22 Diluted (1) $ (2.67 ) $ (5.51 ) $ (0.80 ) $ $0.18 (1) (2) Includes an asset impairment charge of $679.5 million and $294.4 million in the third and fourth quarters of 2015, respectively. Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2014: Revenues $ 196,170 $ 208,589 $ 141,604 $ 162,147 Net loss (1) (594,551 ) (4,349 ) (24,394 ) (17,452 ) Loss attributable to non-controlling interests 437,611 5,137 18,383 10,308 Net income (loss) attributable to owner $ (156,940 ) $ 788 $ (6,011 ) $ (7,144 ) (1)

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation and Combination	Principles of Consolidation and Combination The consolidated financial statements for the year ended December 31, 2015, subsequent to the transfer of assets on February 27, 2015, includes the accounts of the Company and its subsidiaries. The Company’s combined consolidated financial statements for the portion of 2015 which is prior to the transfer of assets on February 27, 2015, and the combined consolidated financial statements for the years ended December 31, 2014 and 2013 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 (“U.S. GAAP”) 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 U.S. GAAP, 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 consolidates the financial statements of ARP and AGP into its combined consolidated financial statements rather than presenting its ownership interests 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 “ Impairment of Long Lived Assets
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. 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. Actual results could differ from those estimates.
Liquidity and Capital Resources	Liquidity and Capital Resources The Company’s primary sources of liquidity are cash distributions received with respect to the Company’s ownership interests in ARP, AGP, and Lightfoot. The Company’s primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures, and distributions to unitholders, which the Company expects to fund through operating cash flow, and cash distributions received. The Company relies on the cash flows from the distributions received on the Company’s ownership interests in ARP, AGP, and Lightfoot. The amount of cash that ARP and AGP can distribute to their partners, including the Company, principally depends upon the amount of cash they each generate from their operations. Reductions of such distributions to the Company would adversely affect the Company’s ability to fund its cash requirements and obligations and meet its financial covenants under its credit agreement. In November 2015, ARP completed the semi-annual redetermination of its credit facility, reducing the borrowing base from $750 million to $700 million and resetting annual distributions to $0.15 per common unit. As a result, ARP distributions to the Company in 2016 will be significantly lower than those received in 2015. On March 30, 2016, the Company entered into a Third Amendment to its First Lien Credit Agreement and a new Second Lien Credit Agreement that, among other things, modifies certain financial covenants, incorporates the ARP financial covenants, provides for a cross-default for defaults by ARP, prohibits the Company from paying distributions on its common and preferred units and requires quarterly receipt of distributions from AGP and Lightfoot. The Company and its subsidiaries believe that they will have sufficient liquid assets, cash from operations and borrowing capacity to meet their financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. To the extent commodity prices remain low or decline further, or the Company, ARP or AGP experience disruptions in the financial markets impacting their respective longer-term access to or cost of capital, their respective ability to fund future growth projects may be further impacted. The Company, ARP and AGP continually monitor their respective capital markets and their capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. It is possible additional adjustments to the Company’s, ARP’s or AGP’s strategic plan and outlook may occur based on market conditions and their respective needs at that time, which could include selling assets, liquidating all or a portion of ARP’s hedge portfolio, seeking additional partners to develop their respective assets, reducing or suspending the payments of distributions to unitholders and/or reducing their respective planned capital programs. Strategies involving further reduction or suspension of distributions to unitholders by ARP or AGP would adversely affect the Company’s ability to fund its cash requirements and obligations. ARP relies on cash flow from operations and its credit facilities to execute its growth strategy and to meet its financial commitments and other short-term liquidity needs. In November 2015, ARP completed the semi-annual redetermination of its credit facility, reducing the borrowing base from $750 million to $700 million. ARP’s next redetermination date is in May 2016. ARP’s borrowing base, and thus its borrowing capacity, under the Credit Facility is impacted by the level of its oil and natural gas reserves. Downward revisions of its oil and natural gas reserves volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of its borrowing base in the future, and these reductions could be significant. ARP believes it has sufficient liquidity from (i) its cash flows from operations (including its hedges scheduled to settle in 2016), (ii) availability under its credit facility and (iii) available cash, to fund its capital program, current obligations and projected working capital requirements for 2016. Furthermore, despite the decline in natural gas and oil prices, ARP believes its derivative contracts, which are primarily fixed price swaps, provide significant commodity price protection on a significant portion of its anticipated natural gas and oil production for 2016. ARP’s ability to (i) generate sufficient cash flows from operations or obtain future borrowings under its credit facility, (ii) repay or refinance any of its indebtedness on commercially reasonable terms or at all, or (iii) obtain additional capital if required on acceptable terms or at all to fund its capital programs or any potential future acquisitions, joint ventures or other similar transactions, will depend on prevailing economic conditions many of which are beyond its control. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact ARP’s outlook. ARP’s plans are intended to address the impacts of the current volatility in commodity prices while (i) maintaining sufficient liquidity to fund capital in its core drilling programs, (ii) meeting its debt maturities, and (iii) managing and working to strengthen its balance sheet. ARP continues to implement various cost saving measures to reduce its capital, operating, and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. ARP will continue to be opportunistic and aggressive in managing its cost structure and, in turn, its liquidity to meet its capital and operating needs. To the extent commodity prices remain low or decline further, or ARP experiences disruptions in the financial markets impacting its longer-term access to or cost of capital, its ability to fund future growth projects may be further impacted. ARP continually monitors the capital markets and its capital structure and may make changes to its capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. For example, ARP could (i) elect to repurchase a portion of its outstanding debt in the future for cash through open market repurchases or privately negotiated transactions with certain of its debtholders, or (ii) issue additional secured debt as permitted under its debt agreements, although there is no assurance ARP would do so. It is also possible additional adjustments to its plan and outlook may occur based on market conditions and its needs at that time, which could include selling assets, liquidating all or a portion of its hedge portfolio, seeking additional partners to develop its assets, reducing or suspending the payments of distributions to unitholders and/or reducing its planned capital program.
Cash Equivalents	Cash Equivalents The Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.
Receivables	Receivables Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with the Company and its subsidiaries. Management performs ongoing credit evaluations of customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness. The Company and its subsidiaries extend credit on sales on an unsecured basis to many of their customers. At December 31, 2015 and 2014, the Company had recorded no allowance for uncollectible accounts receivable on its combined consolidated balance sheets.
Inventory	Inventory The Company had $8.0 million and $8.9 million of inventory at December 31, 2015 and 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.
Subscriptions Receivable	Subscriptions Receivable ARP receives contributions from limited partner investors of its Drilling Partnerships, which are used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships execute an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which is then delivered to Anthem. The investor contributions are then remitted to Anthem at a later date. Limited partner investor contributions are non-refundable upon the execution of an investment agreement. ARP recognizes the contributions associated with executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable.
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’s 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 undiscounted 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.
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 6.5%, 5.6% and 6.0% for the years ended December 31, 2015, 2014 and 2013, respectively. The amounts of interest capitalized by ARP were $15.8 million, $13.0 million and $14.2 million for the years ended December 31, 2015, 2014 and 2013, 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 December 31, 2015 and 2014 (in thousands): December 31, Estimated Useful Lives 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,888 ) (13,653 ) Net Carrying Amount $ 456 $ 691 Amortization expense on intangible assets was $0.2 million, $0.3 million and $0.4 million for the years ended December 31, 2015, 2014 and 2013, respectively. Aggregate estimated annual amortization expense for intangible assets is approximately $0.1 million per year through 2019.
Goodwill	Goodwill At December 31, 2015 and 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 year ended December 31, 2015. The change in ARP’s goodwill during the year end December 31, 2014 resulted from goodwill impairment related to its gas and oil production reporting unit. ARP evaluates 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. All remaining goodwill at December 31, 2015 and 2014 is attributable to ARP’s well construction and completion and other partnership management reporting units. No changes in the carrying amount of goodwill were recorded for the years ended December 31, 2015 and 2013.
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 pays 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 cumulative redeemable perpetual 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 14, 2015. Subsequent to July 15, 2015, ARP pays quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference. At December 31, 2015 and 2014, $103.3 million and $78.0 million, respectively, related to ARP’s preferred units, are included within non-controlling interests on the Company’s combined consolidated statements of unitholders’ equity.
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 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 December 31, 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 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 years ended December 31, 2015, 2014 and 2013. 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 2012 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of December 31, 2015.
Unit-Based Compensation	Unit-Based Compensation The Company and ARP recognize all unit-based payments to employees, including grants of employee unit options, in the combined consolidated financial statements based on their fair values (see Note 14).
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 and the preferred unitholders’ interests, if applicable, by the weighted average number of common unitholders units outstanding during the period. Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities. A portion of 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 loss allocated to the common unitholders for purposes of calculating net loss attributable to common unitholders per unit (in thousands, except unit data): Years Ended December 31, 2015 2014 2013 Net loss $ (885,734 ) $ (640,746 ) $ (107,177 ) Preferred unitholder dividends (3,360 ) — — Loss attributable to non-controlling interests 649,316 471,439 58,389 Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) 10,475 169,307 48,788 Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted (1) $ (229,303 ) $ — $ — (1) Net income (loss) attributable to common unitholders for the net loss attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders and the distribution on the convertible preferred units, less income allocable to participating securities. For the year ended December 31, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 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. Diluted net income (loss) attributable to common limited partners per unit is calculated by dividing net income (loss) attributable to common limited partners, less income allocable to participating securities, by the sum of the weighted average number of common limited partner 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. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of the Company’s long-term incentive plan (see Note 14). The following table sets forth the reconciliation of the Company’s weighted average number of common unitholder units used to compute basic net loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands): Years Ended December 31, 2015 2014 2013 Weighted average number of common unitholders per unit—basic 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 — — (1) For the year ended December 31, 2015, 1,817,000 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 year ended December 31, 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.
Environmental Matters	Environmental Matters The Company and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Company’s and its subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Company and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. The Company and its subsidiaries had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2015, 2014 and 2013.
Concentration of Credit Risk	Concentration of Credit Risk Financial instruments, which potentially subject the Company and its subsidiaries to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Company and its subsidiaries place their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2015 and 2014, the Company had $41.4 million and $60.8 million, respectively, in deposits at various banks, of which $38.3 million and $57.7 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end. The Company and its subsidiaries sell natural gas, oil, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2015, ARP had four customers that individually accounted for approximately 21%, 15%, 11% and 11%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, ARP had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, ARP had three customers that individually accounted for approximately 19%, 11% and 10%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, AGP had three customers within its gas and oil production segment that individually accounted for approximately 59%, 28% and 12% respectively, of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, AGP had two customers within its gas and oil production segment that individually accounted for approximately 67% and 33% of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the period ended December 31, 2013, AGP had two customers within its gas and oil production segment that individually accounted for approximately 70% and 30% of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. ARP and AGP are subject to the risk of loss on their derivative instruments that they would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. ARP and AGP maintain credit policies with regard to their counterparties to minimize their overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of their oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. ARP’s assets related to derivatives as of December 31, 2015 represent financial instruments from ten counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with ARP’s revolving credit facility. Subject to the terms of ARP’s revolving credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the revolving credit facility.
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. For each well that is drilled by a Drilling Partnership, ARP receives a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees are earned, in accordance with the partnership agreement, and recognized as the services are performed, typically between 60 and 270 days. · Administration and oversight. For each well drilled by a Drilling Partnership, ARP receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership pays ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee is earned on a monthly basis as the services are performed. · Well services. Each Drilling Partnership pays ARP a monthly per well operating fee, currently $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees are earned on a monthly basis as the services are performed. 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 cumulative 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 December 31, 2015 and 2014 of $39.9 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 February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for the Company as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. The Company is currently in the process of determining the impact that the updated accounting guidance will have on its consolidated financial statements. In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line-of-credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. The Company adopted the updated accounting guidance effective January 1, 2016 and does not expect it to have a material impact on its combined consolidated financial statements. In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. The Company adopted this accounting guidance upon its effective date of January 1, 2016, which will result in a reclassification of unamortized deferred financing costs of $34.9 million from other assets to long-term debt on its combined consolidated balance sheet at December 31, 2015, when included in future filings. In April 2015, the FASB updated the accounting guidance for earnings per unit (“EPU”) of master limited partnerships (“MLP”) applying the two-class method. The updated accounting guidance specifies that for general partner transfers (or “drop downs”) to an MLP accounted for as a transaction between entities under common control, the earnings (losses) of the transferred business before the date of the transaction should be allocated entirely to the general partner’s interest, and previously reported EPU of the limited partners should not change. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the drop down transaction occurs are also required. The Company adopted this accounting guidance upon its effective date of January 1, 2016, and does not expect it to have a material impact on its combined consolidated financial statements. In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. The Company adopted this accounting guidance upon its effective date of January 1, 2016, and does not except it to have a material impact on its combined consolidated financial statements. In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. The Company adopted this accounting guidance upon its effective date of January 1, 2016, and will provide enhanced disclosures, as applicable, within its combined consolidated financial statements. In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Company is currently in the process of determining the impact that the updated accounting guidance will have on its consolidated financial statements and its method of adoption.

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 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 December 31, 2015 and 2014 (in thousands): December 31, Estimated Useful Lives 2015 2014 In Years Gross Carrying Amount $ 14,344 $ 14,344 13 Accumulated Amortization (13,888 ) (13,653 ) Net Carrying Amount $ 456 $ 691
Reconciliation of Net Income (Loss)	The following is a reconciliation of net loss allocated to the common unitholders for purposes of calculating net loss attributable to common unitholders per unit (in thousands, except unit data): Years Ended December 31, 2015 2014 2013 Net loss $ (885,734 ) $ (640,746 ) $ (107,177 ) Preferred unitholder dividends (3,360 ) — — Loss attributable to non-controlling interests 649,316 471,439 58,389 Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) 10,475 169,307 48,788 Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted (1) $ (229,303 ) $ — $ — (1) Net income (loss) attributable to common unitholders for the net loss attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders and the distribution on the convertible preferred units, less income allocable to participating securities. For the year ended December 31, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 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.
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 loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands): Years Ended December 31, 2015 2014 2013 Weighted average number of common unitholders per unit—basic 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 — — (1) For the year ended December 31, 2015, 1,817,000 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 year ended December 31, 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)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	The following data presents pro forma revenues and net loss for the Company as if the Rangely and EP Energy acquisitions, including the related borrowings under the respective revolving credit facilities, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2013. The Company prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely and EP Energy acquisitions and related offerings, borrowings, and issuances had occurred on January 1, 2013 or the results that will be attained in future periods (in thousands, except per unit data; unaudited): Years Ended December 31, 2014 2013 Total revenues and other $ 754,511 $ 657,300 Net loss (602,707) (21,402 ) Net loss attributable to owner (146,227) (186 )
Rangely Acquisition
Business Acquisition [Line Items]
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
EP Energy Acquisition
Business Acquisition [Line Items]
Assets Acquired and Liabilities Assumed in Acquisition	The following table presents the values assigned to the assets acquired and liabilities assumed in the EP Energy Acquisition, based on their estimated fair values at the date of the acquisition (in thousands): Assets: Prepaid expenses and other $ 5,268 Property, plant and equipment 723,842 Total assets acquired $ 729,110 Liabilities: Accounts payable 2,747 Asset retirement obligation 16,728 Total liabilities assumed 19,475 Net assets acquired $ 709,635

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 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): December 31, Estimated Useful Lives 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 569,377 $ 455,401 Pre-development costs 6,529 7,378 Wells and related equipment 3,157,708 3,082,429 Total proved properties 3,733,614 3,545,208 Unproved properties 213,047 311,946 Support equipment 44,921 37,359 Total natural gas and oil properties 3,991,582 3,894,513 Pipelines, processing and compression facilities 59,733 49,547 15 – 20 Rights of way 829 830 20 – 40 Land, buildings and improvements 9,798 9,160 3 – 40 Other 18,405 17,936 3 – 10 4,080,347 3,971,986 Less – accumulated depreciation, depletion and amortization (2,763,450 ) (1,552,697 ) $ 1,316,897 $ 2,419,289

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Other Assets Noncurrent Disclosure [Abstract]
Summary of Other Assets	The following is a summary of other assets at the dates indicated (in thousands): December 31, 2015 2014 Deferred financing costs, net of accumulated amortization of $45,529 and $20,675, respectively $ 54,933 $ 46,120 Investment in Lightfoot 19,302 21,123 Rabbi Trust 5,584 3,925 Security deposits 351 229 ARP notes receivable 3,708 3,866 Other 5,102 5,348 $ 88,980 $ 80,611

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 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): Years Ended December 31, 2015 2014 2013 Asset retirement obligations, beginning of year $ 108,101 $ 91,214 $ 64,794 Liabilities incurred 2,074 3,677 6,401 Adjustment to liability due to acquisitions (Note 3) — 6,997 16,728 Liabilities settled (2,591 ) (1,664 ) (1,188 ) Accretion expense 6,325 5,759 4,479 Revisions — 2,118 — Asset retirement obligations, end of year $ 113,909 $ 108,101 $ 91,214

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Total debt consists of the following at the dates indicated (in thousands): December 31, 2015 2014 Term loan facilities $ 72,700 $ 148,125 ARP revolving credit facility 592,000 696,000 ARP term loan facility 243,783 — ARP 7.75% Senior Notes—due 2021 374,619 374,544 ARP 9.25% Senior Notes—due 2021 324,080 323,916 Total debt 1,607,182 1,542,585 Less current maturities (4,250 ) (1,500 ) Total long-term debt $ 1,602,932 $ 1,541,085
Schedule of Maturities of Long-term Debt	The aggregate amounts of the Company’s and ARP’s future debt maturities are as follows (in thousands): Years Ended December 31: 2016 $ 4,250 2017 — 2018 592,000 2019 — 2020 318,450 Thereafter 700,000 Total principal maturities 1,614,700 Unamortized premiums 309 Unamortized discounts (7,827 ) Total debt $ 1,607,182

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivatives Fair Value [Line Items]
Summary of Commodity Derivative Activity Presentation in Statement of Operations	The following table summarizes the commodity derivative activity and presentation in the Company’s consolidated statement of operations for the year ended December 31, 2015 (in thousands): Year Ended December 31, 2015 Portion of settlements associated with gains previously recognized within accumulated other comprehensive income, net of prior year offsets (1) $ 86,328 Portion of settlements attributable to subsequent mark to market gains (2) 93,182 Total cash settlements on commodity derivative contracts $ 179,510 Gains recognized prior to settlement (2) 40,930 Gains recognized on open derivative contracts, net of amounts recognized in income in prior year (2) 227,155 Gains on mark-to-market derivatives $ 268,085 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives.
Fair Value of Derivative Instruments Table	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 Amounts Recognized Gross Amounts Offset Net Amount Presented Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 399 $ (96 ) $ 303 Long-term portion of derivative assets 162 (53 ) 109 Total derivative assets $ 561 $ (149 ) $ 412 Current portion of derivative liabilities $ (96 ) $ 96 $ — Long-term portion of derivative liabilities (53 ) 53 — Total derivative liabilities $ (149 ) $ 149 $ —
Commodity Derivative Instruments by Type Table	No derivatives were held by AGP at December 31, 2014. At December 31, 2015, AGP had the following commodity derivatives: Crude Oil – Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset/(Liability) (Bbl) (1) (per Bbl) (1) (in thousands) (2) 2016 76,000 $ 45.229 $ 303 2017 37,100 $ 49.968 127 2018 26,500 $ 48.850 (18 ) AGP’s net assets $ 412 (1) “Bbl” represents barrels. (2) Fair value based on forward WTI crude oil prices, as applicable.
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 Amounts Recognized Gross Amounts Offset Net Amount Presented Offsetting Derivatives as of December 31, 2015 Current portion of derivative assets $ 159,460 $ — $ 159,460 Long-term portion of derivative assets 198,262 — 198,262 Total derivative assets $ 357,722 $ — $ 357,722 Current portion of derivative liabilities $ — $ — $ — Long-term portion of derivative liabilities — — — Total derivative liabilities $ — $ — $ — Offsetting Derivatives 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 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 December 31, 2015, ARP had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2016 53,546,300 $ 4.229 $ 92,131 2017 49,920,000 $ 4.219 67,916 2018 40,800,000 $ 4.170 47,153 2019 15,960,000 $ 4.017 13,839 $ 221,039 Natural Gas – Put Options – Drilling Partnerships Production Period Ending December 31, Option Type Volumes Average Fixed Price Fair Value Asset (MMBtu) (1) (per MMBtu) (1) (in thousands) (2) 2016 Puts purchased 1,440,000 $ 4.150 $ 2,393 $ 2,393 Natural Gas Liquids – Crude Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 84,000 $ 85.651 $ 3,651 2017 60,000 $ 83.780 2,124 $ 5,775 Crude Oil – Fixed Price Swaps Production Period Ending December 31, Volumes Average Fixed Price Fair Value Asset (Bbl) (1) (per Bbl) (1) (in thousands) (3) 2016 1,557,000 $ 81.471 $ 61,284 2017 1,140,000 $ 77.285 33,335 2018 1,080,000 $ 76.281 26,248 2019 540,000 $ 68.371 7,648 $ 128,515 ARP’s net assets $ 357,722 (1) “MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons. (2) Fair value based on forward NYMEX natural gas prices, as applicable. (3) Fair value based on forward WTI crude oil prices, as applicable.

Fair Value of Financial Instr33

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 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 December 31, 2015 and 2014 was as follows (in thousands): Level 1 Level 2 Level 3 Total As of December 31, 2015 Assets, gross Rabbi trust $ 5,584 $ — $ — $ 5,584 ARP Commodity swaps — 355,329 — 355,329 ARP Commodity puts — 2,393 — 2,393 AGP Commodity swaps — 561 — 561 Total assets, gross 5,584 358,283 — 363,867 Liabilities, gross ARP Commodity swaps — — — — ARP Commodity puts — — — — AGP Commodity swaps — (149 ) — (149 ) Total derivative liabilities, gross — (149 ) — (149 ) Total assets, fair value, net $ 5,584 $ 358,134 $ — $ 363,718 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 years ended December 31, 2015 and 2014 was as follows (in thousands): Years Ended December 31, 2015 2014 Level 3 Level 3 Asset retirement obligations $ 2,074 $ 10,674 Total $ 2,074 $ 10,674

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments	Future minimum rental commitments for the next five years are as follows (in thousands): Years Ended December 31, 2016 $ 3,875 2017 3,637 2018 3,261 2019 1,662 2020 1,590 Thereafter 1,849 $ 15,874

Cash Distribution (Distribution

Cash Distribution (Distributions Declared) (Tables)	12 Months Ended
	Dec. 31, 2015
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 Ended Total Cash Distribution To Common Unitholders Total Cash Distribution To Preferred Unitholders May 15, 2015 March 31, 2015 $ — $ 333 June 12, 2015 April 30, 2015 $ — $ 334 July 15, 2015 May 31, 2015 $ — $ 334 August 14, 2015 June 30, 2015 $ — $ 335 September 14, 2015 July 31, 2015 $ — $ 336 October 15, 2015 August 31, 2015 $ — $ 336 November 13, 2015 September 30, 2015 $ — $ 337 December 15, 2015 October 31, 2015 $ — $ 337 January 14, 2016 November 30, 2015 $ — $ 338 Distributions declared by AGP from January 1, 2014 through December 31, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For the Quarter Ended Cash Distribution per Common Limited Partner Unit Total Cash Distribution to Common Limited Partners Total Cash Distribution to the General Partner’s Class A Units February 14, 2014 (1) December 31, 2013 $ 0.1167 $ 120 $ 2 May 15, 2014 March 31, 2014 $ 0.1750 $ 223 $ 6 August 14, 2014 June 30, 2014 $ 0.1750 $ 342 $ 7 November 14, 2014 September 30, 2014 $ 0.1750 $ 841 $ 16 February 13, 2015 December 31, 2014 $ 0.1750 $ 1,636 $ 33 May 15, 2015 March 31, 2015 $ 0.1750 $ 2,180 $ 45 August 14, 2015 June 30, 2015 $ 0.1750 $ 2,646 $ 54 November 14, 2015 September 30, 2015 $ 0.1750 $ 4,078 $ 83 (1) Represents a pro-rated cash distribution of $0.1750 per common limited partner unit and general partner unit for the period from November 1, 2013, the date AGP commenced operations.
Atlas Resource Partners, L.P.
Schedule of Distributions Made by Partnership	Distributions declared by ARP from January 1, 2013 through December 31, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Ended Cash Distribution per Common Limited Partner Unit Total Cash Distribution to Common Limited Partners Total Cash Distribution To Preferred Limited Partners (1) Total Cash Distribution to the General Partner’s Class A Units May 15, 2013 March 31, 2013 $ 0.5100 $ 22,428 $ 1,957 $ 946 August 14, 2013 June 30, 2013 $ 0.5400 $ 32,097 $ 2,072 $ 1,884 November 14, 2013 September 30, 2013 $ 0.5600 $ 33,291 $ 4,248 $ 2,443 February 14, 2014 December 31, 2013 $ 0.5800 $ 34,489 $ 4,400 $ 2,891 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 August 14, 2015 June 30, 2015 $ 0.1083 $ 10,309 $ 637 (2) $ 223 September 14, 2015 July 31, 2015 $ 0.1083 $ 10,571 $ 638 (2) $ 229 October 15, 2015 August 31, 2015 $ 0.1083 $ 10,949 $ 637 (2) $ 236 November 13, 2015 September 30, 2015 $ 0.1083 $ 11,063 $ 637 (2) $ 239 December 15, 2015 October 31, 2015 $ 0.0125 $ 1,277 $ 637 (2) $ 39 January 14, 2016 November 30, 2015 $ 0.0125 $ 1,277 $ 638 (2) $ 39 (1) (2) Date Cash Distribution Paid For the Period Cash Distribution per Class D Preferred Limited Partner Unit Total Cash Distribution To Class D Preferred Limited Partners January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.6169270 $ 1,974 April 15, 2015 January 15, 2015 – April 14, 2015 $ 0.5390630 $ 2,156 July 15, 2015 April 15, 2015 – July 14, 2015 $ 0.5390625 $ 2,157 October 15, 2015 July 15, 2015 – October 14, 2015 $ 0.5390625 $ 2,205 January 15, 2016 October 15, 2015 – January 14, 2016 $ 0.5390625 $ 2,205 Date Cash Distribution Paid For the Period Cash Distribution per Class E Preferred Limited Partner Unit Total Cash Distribution To Class E Preferred Limited Partners July 15, 2015 April 14, 2015 – July 14, 2015 $ 0.6793 $ 173 October 15, 2015 July 15, 2015 – October 14, 2015 $ 0.671875 $ 172 January 15, 2016 October 15, 2015 – January 14, 2016 $ 0.671875 $ 172

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 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: Years Ended December 31, 2015 2014 2013 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding, beginning of year — $ — — $ — — $ — Granted 2,794,710 6.46 — — — — Vested (1) — — — — — — Forfeited (229,800 ) 6.43 — — — — Outstanding, end of year (2)(3) 2,564,910 $ 6.46 — $ — — $ — Non-cash compensation expense recognized (in thousands) $ 5,678 $ — $ — (1) No phantom unit awards vested during the years ended December 31, 2015, 2014 and 2013. (2) The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2015 was approximately $2.4 million. (3) There was approximately $32,000 recognized as liabilities on the Company’s consolidated balance sheet at December 31, 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 December 31, 2015.
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: Years Ended December 31, 2015 2014 2013 Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Number of Units Weighted Average Grant Date Fair Value Outstanding, beginning of year 799,192 $ 22.70 839,808 $ 24.31 948,476 $ 24.76 Granted 9,730 8.50 264,173 19.44 145,813 21.87 Vested (1) (472,278 ) 23.55 (274,414 ) 24.46 (215,981 ) 24.73 Forfeited (34,539 ) 23.13 (30,375 ) 22.76 (38,500 ) 23.96 Outstanding, end of year (2)(3) 302,105 $ 20.87 799,192 $ 22.70 839,808 $ 24.31 Non-cash compensation expense recognized (in thousands) $ 4,124 $ 6,367 $ 9,166 (1) The intrinsic values of phantom unit awards vested during the years ended December 31, 2015, 2014 and 2013 were $4.0 million, $5.4 million and $6.1 million, respectively. (2) The aggregate intrinsic value for phantom unit awards outstanding at December 31, 2015 was $0.3 million. (3) There were approximately $7,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at December 31, 2015 and 2014, respectively, representing 13,391 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 $13.07 and $21.16 at December 31, 2015 and 2014, respectively.
Unit Option Activity	The following table sets forth the ARP LTIP unit option activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number of Unit Options Weighted Average Exercise Price Number of Unit Options Weighted Average Exercise Price Number of Unit Options Weighted Average Exercise Price Outstanding, beginning of year 1,458,300 $ 24.66 1,482,675 $ 24.66 1,515,500 $ 24.68 Granted — — — — 5,000 21.56 Exercised (1) — — — — — — Forfeited (103,775 ) 24.67 (24,375 ) 24.52 (37,825 ) 24.80 Outstanding, end of year (2)(3) 1,354,525 $ 24.66 1,458,300 $ 24.66 1,482,675 $ 24.66 Options exercisable, end of year (4) 1,273,487 $ 24.67 730,775 $ 24.67 370,700 $ 24.67 Non-cash compensation expense recognized (in thousands) $ 820 $ 1,700 $ 3,514 (1) No options were exercised during the years ended December 31, 2015, 2014 and 2013. (2) The weighted average remaining contractual life for outstanding options at December 31, 2015 was 6.4 years. (3) There were no aggregate intrinsic values of options outstanding at December 31, 2015 and 2014. The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000. (4) The weighted average remaining contractual life for exercisable options at December 31, 2015, 2014 and 2013 was 6.4 years, 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2015, 2014 and 2013.
Weighted Average Assumptions	The following weighted average assumptions were used for the options granted during the year ended December 31, 2013: Expected dividend yield 8.0 % Expected unit price volatility 35.5 % Risk-free interest rate 1.4 % Expected term (in years) 6.31 Fair value of unit options granted $ 2.95

Operating Segment Information (

Operating Segment Information (Tables)	12 Months Ended
	Dec. 31, 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): Years Ending December 31, 2015 2014 2013 Atlas Resource: Revenues $ 740,033 $ 701,654 $ 474,476 Operating costs and expenses (320,922 ) (431,032 ) (351,673 ) Depreciation, depletion and amortization expense (157,978 ) (239,923 ) (139,783 ) Asset impairment (966,635 ) (573,774 ) (38,014 ) Loss on asset sales and disposal (1,181 ) (1,869 ) (987 ) Interest expense (102,133 ) (62,144 ) (34,324 ) Segment loss $ (808,816 ) $ (607,088 ) $ (90,305 ) Atlas Growth: Revenues $ 12,708 $ 5,707 $ 302 Operating costs and expenses (14,968 ) (13,816 ) (3,812 ) Depreciation, depletion and amortization expense (8,951 ) (2,156 ) (133 ) Asset impairment (7,346 ) (6,880 ) — Segment loss $ (18,557 ) $ (17,145 ) $ (3,643 ) Corporate and other: Revenues $ 752 $ 1,149 $ 321 General and administrative (30,862 ) (6,381 ) (8,162 ) Gain on asset sales and disposal — 10 — Interest expense (23,525 ) (11,291 ) (5,388 ) Loss on early extinguishment of debt (4,726 ) — — Segment loss $ (58,361 ) $ (16,513 ) $ (13,229 ) Reconciliation of segment loss to net loss: Segment loss: Atlas Resource $ (808,816 ) $ (607,088 ) $ (90,305 ) Atlas Growth (18,557 ) (17,145 ) (3,643 ) Corporate and other (58,361 ) $ (16,513 ) $ (13,229 ) Net loss $ (885,734 ) $ (640,746 ) $ (107,177 ) Reconciliation of segment revenues to total revenues: Segment revenues: Atlas Resource $ 740,033 $ 701,654 $ 474,476 Atlas Growth 12,708 5,707 302 Corporate and other 752 1,149 321 Total revenues $ 753,493 $ 708,510 $ 475,099 Capital expenditures: Atlas Resource $ 127,138 $ 212,763 $ 263,886 Atlas Growth 29,222 12,873 3,594 Corporate and other — — — Total capital expenditures $ 156,360 $ 225,636 $ 267,480 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 $ 1,731,004 $ 2,798,120 Atlas Growth 160,267 190,161 Corporate and other 26,843 38,034 $ 1,918,114 $ 3,026,315

Supplemental Oil and Gas Info38

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Reserve Quantity Information	Reserve quantity information and a reconciliation of changes in proved reserve quantities included within AGP and ARP are as follows (unaudited): Gas (Mcf) Oil (Bbls) NGLs (Bbls) Balance, January 1, 2013 573,774,257 8,868,836 16,061,897 Extensions, discoveries and other additions (1) 90,098,219 8,255,531 8,197,272 Sales of reserves in-place (2,755,155 ) — (4,625 ) Purchase of reserves in-place (2) 493,481,302 1,964 55,187 Transfers to limited partnerships (2,485,210 ) (239,910 ) (258,381 ) Revisions (3) (88,484,468 ) (1,412,371 ) (3,826,744 ) Production (59,849,442 ) (485,226 ) (1,267,590 ) Balance, December 31, 2013 1,003,779,503 14,988,824 18,957,016 Extensions, discoveries and other additions (1) 58,461,204 3,372,177 3,986,986 Sales of reserves in-place (169,035 ) (1,519 ) (11,326 ) Purchase of reserves in-place (2) 88,635,059 51,168,449 5,189,827 Transfers to limited partnerships (4,887,095 ) (684,613 ) (665,486 ) Revisions (3) 5,947,622 (4,639,546 ) (2,689,372 ) Production (86,889,803 ) (1,254,247 ) (1,387,865 ) Balance, December 31, 2014 1,064,877,455 62,949,525 23,379,780 Extensions, discoveries and other additions (1) 6,806,339 3,460,609 293,256 Sales of reserves in-place (4) (2,713,428 ) (2,393 ) — Purchase of reserves in-place — — — Transfers to limited partnerships (2,958,882 ) (481,771 ) (342,156 ) Revisions (3) (379,058,376 ) (11,223,648 ) (13,769,701 ) Production (79,266,969 ) (2,119,266 ) (1,084,848 ) Balance, December 31, 2015 607,686,139 52,583,056 8,476,331 Proved developed reserves at: January 1, 2013 338,655,324 3,400,447 7,884,778 December 31, 2013 766,872,394 3,459,260 7,676,389 December 31, 2014 889,073,136 31,150,298 12,209,825 December 31, 2015 568,793,757 27,129,766 6,488,931 Proved undeveloped reserves at: January 1, 2013 235,118,932 5,468,389 8,177,120 December 31, 2013 236,907,109 11,529,564 11,280,627 December 31, 2014 175,804,319 31,799,227 11,169,954 December 31, 2015 38,892,382 25,453,290 1,987,400 (1) For the year ended December 31, 2015, the increase represents PUD conversions related to development activity in the Eagle Ford Shale. For the year ended December 31, 2014, the increase was due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s Geomet Acquisitions. For the year ended December 31, 2013, the increase was primarily due to the addition of Marble Falls wells. (2) Represents the purchase of proved reserves due to the Rangely, Eagle Ford and GeoMet Acquisitions for the year ended December 31, 2014 and mainly due to the EP Energy Acquisition for the year ended December 31, 2013. (3) The downward revisions for the year ended December 31, 2015 were primarily due to wells being shut-in as well as unfavorable economic conditions primarily related to gas and oil commodity prices. For the year ended December 31, 2014, the downward revisions on oil and NGL were primarily due to wells being shut-in. The upward revision for the year ended December 31, 2014 on gas was primarily due to production outperforming previous forecasts. The downward revisions for the year ended December 31, 2013 were primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.
Schedule of Capitalized Costs Related to Oil and Gas Producing Activities	Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of AGP and ARP during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 Natural gas and oil properties: Proved properties $ 3,733,614 $ 3,639,833 Unproved properties 213,047 217,321 Support equipment 44,921 37,359 3,991,582 3,894,513 Accumulated depreciation, depletion and amortization (2,717,002 ) (1,518,686 ) Net capitalized costs $ 1,274,580 $ 2,375,827
Schedule of Results of Operations from Oil and gas Producing Activities	Results of Operations from Oil and Gas Producing Activities. The results of operations related to AGP’s and ARP’s oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 368,845 $ 475,758 $ 273,906 Production costs (171,882 ) (184,296 ) (100,178 ) Depreciation, depletion and amortization (153,938 ) (231,638 ) (132,860 ) Asset impairment (1) (973,981 ) (580,654 ) (38,014 ) $ (930,956 ) $ (520,830 ) $ 2,854 (1) During the year ended December 31, 2015, the Company recognized $974.0 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, and unproved acreage in the New Albany Shale, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income. During the year ended December 31, 2014, the Company recognized $580.7 million of asset impairment consisting of $562.6 million 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 net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales.
Schedule of Costs Incurred in Oil and gas Producing Activities	Costs Incurred in Oil and Gas Producing Activities. The costs incurred by AGP and ARP in their oil and gas activities during the periods indicated are as follows (in thousands): Years Ended December 31, 2015 2014 2013 Property acquisition costs: Proved properties $ 55,033 $ 754,197 $ 863,421 Unproved properties 43,820 10,978 895 Exploration costs (1) 1,601 722 1,053 Development costs 102,110 177,726 214,383 Total costs incurred in oil & gas producing activities $ 202,564 $ 943,623 $ 1,079,752 (1) There were no exploratory wells drilled during the years ended December 31, 2015, 2014 and 2013.
Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows	Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to AGP’s and ARP’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2015, 2014 and 2013, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and include the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands): Years Ended December 31, 2015 2014 2013 Future cash inflows $ 3,910,339 $ 10,802,697 $ 5,268,148 Future production costs (1,954,564 ) (4,561,129 ) (2,397,997 ) Future development costs (1,289,841 ) (1,623,218 ) (752,369 ) Future net cash flows 665,934 4,618,350 2,117,782 Less 10% annual discount for estimated timing of (90,703 ) (2,381,586 ) (1,038,491 ) Standardized measure of discounted future net $ 575,231 $ 2,236,764 $ 1,079,291
Schedule of Changes in Discounted Future Net Cash Flows	Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since AGP and ARP allocate taxable income to their owner, no recognition has been given to income taxes: Years Ended December 31, 2015 2014 2013 Balance, beginning of year $ 2,236,764 $ 1,079,291 $ 623,676 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas, net of related costs (1) (137,942 ) (275,789 ) (171,409 ) Net changes in prices and production costs (2 ) (1,629,945 ) 339,776 85,191 Revisions of previous quantity estimates (41,147 ) (33,526 ) (1,881 ) Development costs incurred 88,261 52,077 27,245 Changes in future development costs (167,995 ) (90,887 ) (21,579 ) Transfers to limited partnerships (13,291 ) (2,966 ) (53,392 ) Extensions, discoveries, and improved recovery less related costs 20,408 69,436 143,338 Purchases of reserves in-place (3) — 1,018,345 516,985 Sales of reserves in-place (4) (2,162 ) (332 ) (2,053 ) Accretion of discount 223,676 107,929 62,368 Estimated settlement of asset retirement obligations (224 ) (16,824 ) (18,858 ) Estimated proceeds on disposals of well equipment (1,172 ) (21,896 ) 17,052 Changes in production rates (timing) and other — 12,130 (127,392 ) Outstanding, end of year $ 575,231 $ 2,236,764 $ 1,079,291 (1) Includes the amount of sales of oil and gas previously included in proved reserves and sold during the period ended. (2) Decrease due to commodity price declines for the year ended December 31, 2015. (3) Represents the change in discounted value of the proved reserves primarily due to the purchase of proved reserves due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s Geomet Acquisitions for the period ended December 31, 2014 and primarily due to the purchase of proved reserves in Marble Falls for the period ended December 31, 2013.

Quarterly Results (Unaudited) (

Quarterly Results (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2015: Revenues $ 146,613 $ 262,834 $ 98,247 $ 245,799 Net income (loss) (2) (297,357 ) (582,313 ) (59,543 ) 53,479 (Income) loss attributable to non-controlling interests 228,905 439,969 38,745 (58,303 ) Loss attributable to owner’s interest (period prior to the transfer of assets on February 27, 2015) — — — 10,475 Net income (loss) attributable to common unitholders $ (69,466 ) $ (143,353 ) $ (21,802 ) $ 5,318 Net income (loss) attributable to common unitholders per unit: Basic (1) $ (2.67 ) $ (5.51 ) $ (0.80 ) $ $0.22 Diluted (1) $ (2.67 ) $ (5.51 ) $ (0.80 ) $ $0.18 (1) (2) Includes an asset impairment charge of $679.5 million and $294.4 million in the third and fourth quarters of 2015, respectively. Fourth Quarter Third Quarter Second Quarter First Quarter (in thousands, except unit data) Year ended December 31, 2014: Revenues $ 196,170 $ 208,589 $ 141,604 $ 162,147 Net loss (1) (594,551 ) (4,349 ) (24,394 ) (17,452 ) Loss attributable to non-controlling interests 437,611 5,137 18,383 10,308 Net income (loss) attributable to owner $ (156,940 ) $ 788 $ (6,011 ) $ (7,144 ) (1)

Basis of Presentation (Narrativ

Basis of Presentation (Narrative) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Feb. 27, 2015	Dec. 31, 2015	Dec. 31, 2013
Basis Of Presentation [Line Items]
Percentage of interest represented by common units which is effected by pro rata distribution		100.00%
Limited partners units issued			26,010,766
Limited partners units outstanding			26,010,766
Lightfoot Capital Partners, LP
Basis Of Presentation [Line Items]
General partner ownership interest			15.90%
Common limited partner ownership interest			12.00%
Preferred Limited Partner Units
Basis Of Presentation [Line Items]
Common limited partner interest in ARP, units			3,749,986
Atlas Resource Partners, L.P.
Basis Of Presentation [Line Items]
General partner ownership interest			100.00%
Common limited partner ownership interest			23.30%
Common limited partner interest in ARP, units			20,962,485
Atlas Growth Partners, L.P
Basis Of Presentation [Line Items]
General partner ownership interest			80.00%
Common limited partner ownership interest			2.10%
Common limited partner units issued	$ 233		$ 233
Common limited partner units purchased	$ 5		$ 2.7	$ 1.8

Summary of Significant Accoun41

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	Jul. 25, 2015	Jan. 14, 2015	Dec. 23, 2014	Jul. 31, 2013	Jul. 31, 2012	Apr. 30, 2015	Mar. 31, 2015	Oct. 31, 2014	Jul. 14, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Nov. 23, 2015	Nov. 22, 2015	Jul. 15, 2015
Summary Of Significant Accounting Policies [Line Items]
Repayments under credit facilities										$ 808,903,000	$ 1,117,500,000	$ 896,050,000
Pro-rata share in Drilling Partnerships										30.00%
Amended borrowing base													$ 700,000,000	$ 750,000,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit										$ 0.15
Allowance for Doubtful Accounts Receivable										$ 0	0
Materials, supplies and other inventory										$ 8,000,000	$ 8,900,000
Weighted Average Interest Rate Used To Capitalize Interest										6.50%	5.60%	6.00%
Interest Costs Capitalized										$ 15,800,000	$ 13,000,000	$ 14,200,000
Amortization of Intangible Assets										200,000	300,000	400,000
Future Amortization Expense, 2016										100,000
Future Amortization Expense, 2017										100,000
Future Amortization Expense, 2018										100,000
Future Amortization Expense, 2019										100,000
Goodwill										13,639,000	$ 13,639,000
Changes in carrying amount of goodwill										$ 0		0
Partners unit, issued										9,803,451	0
Percentage of Preferred Unit Regular Quarterly Cash Distributions						10.75%
Deferred income tax benefit										$ 0
Environmental remediation expense										$ 0	$ 0	$ 0
Concentration Risk, Credit Risk, Uninsured Deposits										Financial instruments, which potentially subject the Company and its subsidiaries to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Company and its subsidiaries place their temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2015 and 2014, the Company had $41.4 million and $60.8 million, respectively, in deposits at various banks, of which $38.3 million and $57.7 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.
Cash Equivalents, at Carrying Value										$ 41,400,000	60,800,000
Cash, Uninsured Amount										$ 38,300,000	57,700,000
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										$ 39,900,000	$ 85,500,000
Unamortized deferred financing costs										$ 34,900,000
Customer Concentration Risk Customer 1
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										21.00%	25.00%	19.00%
Customer Concentration Risk Customer 2
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										15.00%	15.00%	11.00%
Customer Concentration Risk Customer 3
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										11.00%	14.00%	10.00%
Customer Concentration Risk Customer 4
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										11.00%	13.00%
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 thereafter						$ 25									$ 2.6875
Percentage of Preferred Unit Regular Quarterly Cash Distributions						10.75%
Atlas Resource Partners, L.P. | Preferred class D
Summary Of Significant Accounting Policies [Line Items]
Non-controlling interests										$ 103,300,000	$ 78,000,000
Atlas Growth Partners, L.P
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued										12,623,500	9,581,900	1,095,010
Atlas Growth Partners, L.P | Customer Concentration Risk Customer 1
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										59.00%	67.00%	70.00%
Atlas Growth Partners, L.P | Customer Concentration Risk Customer 2
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										28.00%	33.00%	30.00%
Atlas Growth Partners, L.P | Customer Concentration Risk Customer 3
Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Percentage										12.00%
Drilling Partnership Wells
Summary Of Significant Accounting Policies [Line Items]
Gathering Fee Percentage										13.00%
ARP Acquisitions
Summary Of Significant Accounting Policies [Line Items]
Goodwill										$ 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)	39,654		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	3.2
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 thereafter		$ 2.15625
Percentage of Preferred Unit Regular Quarterly Cash Distributions		8.625%
Titan Acquisition | Atlas Resource Partners, L.P.
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.
Titan Acquisition | Atlas Resource Partners, L.P. | Class B Preferred Units
Summary Of Significant Accounting Policies [Line Items]
Partners unit, issued					3,800,000
Titan Acquisition | Atlas Resource Partners, L.P. | Class B Preferred Units | Minimum
Summary Of Significant Accounting Policies [Line Items]
Distribution Made to Limited Partner, Distributions Declared, Per Unit					$ 0.40
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 Accoun42

Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Gross Carrying Amount	$ 14,344	$ 14,344
Accumulated Amortization	(13,888)	(13,653)
Net Carrying Amount	$ 456	$ 691
Estimated Useful Lives In Years	13 years

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation Of Net Income [Line Items]
Net loss										$ (885,734)	$ (640,746)	$ (107,177)
Preferred unitholders’ dividends										(3,360)
Loss attributable to non-controlling interests		$ 228,905	$ 439,969	$ 38,745	$ (58,303)	$ 437,611	$ 5,137	$ 18,383	$ 10,308	649,316	471,439	58,389
Portion applicable to owner’s interest (period prior to the transfer of assets on February 27, 2015)					$ (10,475)					10,475	$ 169,307	$ 48,788
Net loss utilized in the calculation of net loss attributable to common unitholders per unit – basic and diluted	[1]									$ (229,303)
Antidilutive Phantom Unit Securities Excluded from Computation of Diluted Earnings Attributable to Common Unit Holders Outstanding Units										68,000
Continuing Operations
Reconciliation Of Net Income [Line Items]
Preferred unitholders’ dividends										$ (3,360)
[1]	Net income (loss) attributable to common unitholders for the net loss attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders and the distribution on the convertible preferred units, less income allocable to participating securities. For the year ended December 31, 2015, net loss attributable common unitholder’s ownership interest is not allocated to approximately 68,000 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.

Summary of Significant Accoun44

Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number of Common Unit Holder Units) (Details)	12 Months Ended
	Dec. 31, 2015shares
Accounting Policies [Abstract]
Weighted average number of common unitholders per unit—basic	26,011,000
Weighted average number of common unitholders per unit—diluted	26,011,000
Antidilutive Securities Excluded From Computation Of Diluted Net Income (Loss) Attributable To Common Limited Partners Outstanding Units	1,817,000

Acquisitions (Rangely Acquisiti

Acquisitions (Rangely Acquisition) (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jun. 30, 2014	May. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Partners unit, issued			9,803,451	0
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
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 Acquisi46

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 (EP Energy Acquisi

Acquisitions (EP Energy Acquisition ) (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jul. 31, 2013	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Partners unit, issued			9,803,451	0
9.25% Senior Notes
Business Acquisition [Line Items]
Debt instrument, interest rate, stated percentage			9.25%
EP Energy Acquisition
Business Acquisition [Line Items]
Partners unit, issued		14,950,000
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Business Acquisition [Line Items]
Debt instrument, interest rate, stated percentage			9.25%	9.25%
Atlas Resource Partners, L.P. | EP Energy Acquisition
Business Acquisition [Line Items]
Business acquisition, cost of acquired entity, cash paid	$ 709.6
Business acquisition, effective date of acquisition	May 1, 2013
Partners unit, issued	14,950,000
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, cost of acquired entity, transaction costs					$ 12.1
Business acquisition, purchase price allocation, status			All other costs associated with the acquisition of assets were expensed as incurred
Atlas Resource Partners, L.P. | EP Energy Acquisition | Class C Convertible Preferred Units
Business Acquisition [Line Items]
Partners unit, issued	3,749,986
Atlas Resource Partners, L.P. | EP Energy Acquisition | 9.25% Senior Notes
Business Acquisition [Line Items]
Debt instrument, interest rate, stated percentage	9.25%
Debt Instrument, Maturity Date	Aug. 15, 2021

Acquisitions (EP Energy Acqui48

Acquisitions (EP Energy Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Details) - EP Energy Acquisition $ in Thousands	Jul. 31, 2013USD ($)
Business Acquisition [Line Items]
Prepaid expenses and other	$ 5,268
Property, plant and equipment	723,842
Total assets acquired	729,110
Accounts payable	2,747
Asset retirement obligation	16,728
Total liabilities assumed	19,475
Net assets acquired	$ 709,635

Acquisitions (Pro Forma Financi

Acquisitions (Pro Forma Financial Information) (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Business Acquisition, Pro Forma Information, Description	The following data presents pro forma revenues and net loss for the Company as if the Rangely and EP Energy acquisitions, including the related borrowings under the respective revolving credit facilities, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2013. The Company prepared these pro forma unaudited financial results for comparative purposes only; they may not be indicative of the results that would have occurred if the Rangely and EP Energy acquisitions and related offerings, borrowings, and issuances had occurred on January 1, 2013 or the results that will be attained in future periods

Acquisitions (Other Acquisition

Acquisitions (Other Acquisition) (Narrative) (Details) - USD ($) $ in Millions

Oct. 01, 2015

Jul. 08, 2015

Jun. 05, 2015

Nov. 05, 2014

May. 12, 2014

Sep. 20, 2013

May. 31, 2015

Dec. 31, 2014

Mar. 31, 2014

Jul. 31, 2013

Mar. 31, 2015

Jun. 30, 2015

Sep. 30, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Business Acquisition [Line Items]

Partners unit, issued

9,803,451

0

Arkoma Acquisition

Business Acquisition [Line Items]

Partners unit, issued

6,500,000

Business acquisition, effective date of acquisition

May 1, 2013

Historical carrying value of net assets acquired

$ 64.5

ARP’s and AGP’s Eagle Ford Acquisition

Business Acquisition [Line Items]

Cash Consideration

$ 183.1

Business Acquisition, Date of Acquisition Agreement

Nov. 5, 2014

Net cash acquired

342

Deferred portion of purchase price

139

Purchase price represent non-cash transaction

$ 21.6

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 included coal-bed methane producing natural gas assets in West Virginia and Virginia

Norwood Natural Resources

Business Acquisition [Line Items]

Business acquisition, effective date of acquisition

Jun. 1, 2013

Cash Consideration

$ 5.4

Business Acquisition, Description of Acquired Entity

The assets acquired included Norwood’s non-operating working interest in certain producing wells in the Barnett Shale.

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]

Deferred portion of purchase price

$ 17.5

$ 0.6

Atlas Resource Partners, L.P. | ARP’s and AGP’s Eagle Ford Acquisition | Class D Preferred Units

Business Acquisition [Line Items]

Deferred portion of purchase price by issuing preferred units

$ 20

Atlas Growth Partners, L.P

Business Acquisition [Line Items]

Partners unit, issued

12,623,500

9,581,900

1,095,010

Atlas Growth Partners, L.P | ARP’s and AGP’s Eagle Ford Acquisition

Business Acquisition [Line Items]

Cash Consideration

$ 1.4

Deferred portion of purchase price

$ 19.9

$ 35

$ 28.3

$ 16

$ 36.3

Property, Plant and Equipment51

Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Abstract]
Proved properties: Leasehold interests	$ 569,377	$ 455,401
Proved properties: Pre-development costs	6,529	7,378
Proved properties: Wells and related equipment	3,157,708	3,082,429
Total proved properties	3,733,614	3,545,208
Unproved properties	213,047	311,946
Support equipment	44,921	37,359
Total natural gas and oil properties	3,991,582	3,894,513
Pipelines, processing and compression facilities	59,733	49,547
Rights of way	829	830
Land, buildings and improvements	9,798	9,160
Other	18,405	17,936
Total gross property, plant and equipment	4,080,347	3,971,986
Less – accumulated depreciation, depletion and amortization	(2,763,450)	(1,552,697)
Property, plant and equipment, Net, Total	$ 1,316,897	$ 2,419,289

Property, Plant and Equipment52

Property, Plant and Equipment (Useful Life Narrative) (Details)	12 Months Ended
	Dec. 31, 2015
Pipelines, processing and compression facilities | Minimum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	15 years
Pipelines, processing and compression facilities | Maximum
Property Plant And Equipment [Line Items]
Property, plant and equipment useful life	20 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 Equipment53

Property, Plant and Equipment (Narrative) (Details) - USD ($)	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment [Line Items]
Gain (loss) on asset sales and disposal				$ (1,181,000)	$ (1,859,000)	$ (987,000)
Asset impairment	$ 294,400,000	$ 679,500,000	$ 580,700,000	973,981,000	580,654,000	38,014,000
Non-cash property, plant and equipment additions				21,500,000	36,800,000	11,400,000
Proved Properties
Property Plant And Equipment [Line Items]
Net future hedge gains				85,800,000	82,300,000
Atlas Resource Partners, L.P.
Property Plant And Equipment [Line Items]
Asset impairment					580,700,000
Atlas Resource Partners, L.P. | Unproved Properties
Property Plant And Equipment [Line Items]
Asset impairment				6,600,000	$ 0	13,500,000
Atlas Resource Partners, L.P. | Proved Properties
Property Plant And Equipment [Line Items]
Asset impairment				$ 974,000,000		$ 24,500,000

Other Assets (Summary of Other

Other Assets (Summary of Other Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Assets [Line Items]
Deferred financing costs, net of accumulated amortization of $45,529 and $20,675, respectively	$ 54,933	$ 46,120
Rabbi Trust	5,584	3,925
Security deposits	351	229
Other	5,102	5,348
Total Other Assets	88,980	80,611
Lightfoot
Other Assets [Line Items]
Investment in Lightfoot	19,302	21,123
Atlas Resource Partners, L.P.
Other Assets [Line Items]
ARP notes receivable	$ 3,708	$ 3,866

Other Assets (Narrative) (Detai

Other Assets (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Assets [Line Items]
Accumulated amortization	$ 45,529,000	$ 20,675,000
Amortization of financing costs	13,600,000	9,900,000	$ 7,000,000
Accelerated amortization of deferred financing costs	5,200,000
Distributions received from unconsolidated companies	$ 2,847,000	1,695,000	1,022,000
Lightfoot LP
Other Assets [Line Items]
Equity method investment ownership percentage	12.00%
Distributions received from unconsolidated companies	$ 2,800,000	1,700,000	1,000,000
Lightfoot GP
Other Assets [Line Items]
Equity method investment ownership percentage	15.90%
Lightfoot
Other Assets [Line Items]
Equity income in joint ventures	$ 700,000	1,100,000	2,600,000
Atlas Resource Partners, L.P.
Other Assets [Line Items]
Accelerated amortization of deferred financing costs	5,600,000	600,000	3,200,000
Allowance for credit loss	$ 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	$ 100,000	$ 100,000	$ 100,000
Retirement Portion of Indebtedness under Term Loan
Other Assets [Line Items]
Accelerated amortization of deferred financing costs	500,000
Early Retirement of Term Loan Facilities with Deutsche Bank
Other Assets [Line Items]
Accelerated amortization of deferred financing costs	$ 300,000
7.75% Senior Notes | Atlas Resource Partners, L.P.
Other Assets [Line Items]
Debt instrument, interest rate, stated percentage			7.75%

Asset Retirement Obligations (R

Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 113,909	$ 108,101	$ 91,214	$ 64,794
Oil and gas reclamation liabilities noncurrent		6,997	$ 16,728
Relationship With Drilling Partnerships
Asset Retirement Obligations [Line Items]
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships	5,200
Relationship With Drilling Partnerships | Limited Partner Interest
Asset Retirement Obligations [Line Items]
Asset retirement obligations	$ 44,200
Atlas Growth Partners, L.P | Series of Individually Immaterial Business Acquisitions
Asset Retirement Obligations [Line Items]
Oil and gas reclamation liabilities noncurrent		$ 100

Asset Retirement Obligations 57

Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Roll Forward Analysis Roll Forward
Asset retirement obligations, beginning of year	$ 108,101	$ 91,214	$ 64,794
Liabilities incurred	2,074	3,677	6,401
Adjustment to liability due to acquisitions (Note 3)		6,997	16,728
Liabilities settled	(2,591)	(1,664)	(1,188)
Accretion expense	6,325	5,759	4,479
Revisions		2,118
Asset retirement obligations, end of year	$ 113,909	$ 108,101	$ 91,214

Debt (Schedule of Total Debt Ou

Debt (Schedule of Total Debt Outstanding) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total debt	$ 1,607,182	$ 1,542,585
Less current maturities	(4,250)	(1,500)
Total long-term debt	$ 1,602,932	1,541,085
9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.25%
Atlas Energy
Debt Instrument [Line Items]
Term loan facilities		148,100
Atlas Energy | Term loan facilities
Debt Instrument [Line Items]
Term loan facilities	$ 72,700	148,125
Atlas Resource Partners, L.P.
Debt Instrument [Line Items]
Term loan facilities	243,783
Revolving credit facility	592,000	696,000
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$ 374,619	$ 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	$ 324,080	$ 323,916
Debt instrument, interest rate, stated percentage	9.25%	9.25%

Debt (Term Loan Facilities) (De

Debt (Term Loan Facilities) (Details)	Aug. 10, 2015USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 27, 2015USD ($)
Debt Instrument [Line Items]
Line of Credit Facility, initiation date			Feb. 27, 2015
Term Loan Facilities, outstanding			$ 1,607,182,000	$ 1,542,600,000
Repayment of debt		$ 33,100,000
Repayments under credit facilities			$ 808,903,000	$ 1,117,500,000	$ 896,050,000
Company's Current and Former Officers
Debt Instrument [Line Items]
Percentage of lenders participated in loan syndication			12.00%
Minimum | Unitholders
Debt Instrument [Line Items]
Percentage of lenders participated in loan syndication			5.00%
First Lien Credit Agreement
Debt Instrument [Line Items]
Line of Credit Facility interest rate description			Borrowings under the First Lien Term Loan Facility bear interest, at the Company’s option, at either (i) LIBOR plus 7.0% (as used with respect to the First Lien Term Loan Facility, “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%, each plus 6.0% (as used with respect to the First Lien Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans
Term Loan Facilities, outstanding			$ 72,700,000
Outstanding Term Facility, weighted average interest rate			8.00%
Liquidity Requirement			$ 5,000,000
Minimum asset coverage ratio required beginning with July twenty sixteen			2
Required repayment from net cash proceeds disposition casualty			100.00%
Required repayment from net cash proceeds equity debt issuance incurrence			100.00%
First Lien Credit Agreement | Total Leverage Ratio 3 - 3.25
Debt Instrument [Line Items]
Required repayment of distributable cash			75.00%
First Lien Credit Agreement | Total Leverage Ratio 2.75 -3
Debt Instrument [Line Items]
Required repayment of distributable cash			50.00%
First Lien Credit Agreement | Total Leverage Ratio 2.5 - 2.75
Debt Instrument [Line Items]
Required repayment of distributable cash			25.00%
First Lien Credit Agreement | Total Leverage Ratio Less Than 2.5
Debt Instrument [Line Items]
Required repayment of distributable cash			0.00%
First Lien Credit Agreement | Maximum
Debt Instrument [Line Items]
Required total leverage ratio			4
First Lien Credit Agreement | Maximum | Total Leverage Ratio Greater Than 3.5
Debt Instrument [Line Items]
Required repayment of distributable cash			100.00%
First Lien Credit Agreement | Maximum | Total Leverage Ratio 3 - 3.25
Debt Instrument [Line Items]
Total leverage ratio			3.25
First Lien Credit Agreement | Maximum | Total Leverage Ratio 2.75 -3
Debt Instrument [Line Items]
Total leverage ratio			3
First Lien Credit Agreement | Maximum | Total Leverage Ratio 2.5 - 2.75
Debt Instrument [Line Items]
Total leverage ratio			2.75
First Lien Credit Agreement | Maximum | Total Leverage Ratio Less Than 2.5
Debt Instrument [Line Items]
Total leverage ratio			2.50
First Lien Credit Agreement | Minimum
Debt Instrument [Line Items]
Required total leverage ratio			1.75
First Lien Credit Agreement | Minimum | Total Leverage Ratio Greater Than 3.5
Debt Instrument [Line Items]
Total leverage ratio			3.50
First Lien Credit Agreement | Minimum | Total Leverage Ratio 3 - 3.25
Debt Instrument [Line Items]
Total leverage ratio			3
First Lien Credit Agreement | Minimum | Total Leverage Ratio 2.75 -3
Debt Instrument [Line Items]
Total leverage ratio			2.75
First Lien Credit Agreement | Minimum | Total Leverage Ratio 2.5 - 2.75
Debt Instrument [Line Items]
Total leverage ratio			2.50
First Lien Credit Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	7.00%
First Lien Credit Agreement | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.50%
First Lien Credit Agreement | One Month L I B O R
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.00%
First Lien Credit Agreement | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.00%
First Lien Credit Agreement | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	6.00%
Term loan facilities
Debt Instrument [Line Items]
Line of Credit Facility, initiation date			Aug. 10, 2015
Term loan initial balance			$ 82,700,000
Repayment of debt	$ 82,700,000
Recognized value ratio, description			Recognized Value Ratio (as defined in the Credit Agreement) was less than 2.00 to 1.00, the Company must have prepaid 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 was 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%
Term loan facilities | Maximum
Debt Instrument [Line Items]
Recognized value ratio			2.00%
Term loan facilities | Minimum
Debt Instrument [Line Items]
Recognized value ratio			2.00%
Secured Term Loan Facility
Debt Instrument [Line Items]
Repayments under credit facilities			$ 150,000,000
Secured Term Loan Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			7.50%
Secured Term Loan Facility | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			0.50%
Secured Term Loan Facility | One Month L I B O R
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.00%
Secured Term Loan Facility | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.00%
Secured Term Loan Facility | Alternate Base Rate
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 bore interest, at the Company’s option, at either (i) LIBOR plus 7.5% (as used with respect to the Term Loan Facilities, “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% (as was used with the Term Loan Facilities, an “ABR Loan”). Interest was generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans.
Credit Agreement | Term loan facilities
Debt Instrument [Line Items]
Line of Credit Facility, expiration date			Aug. 31, 2020
Credit Agreement | Interim Term Loan Facility
Debt Instrument [Line Items]
Line of Credit Facility, expiration date			Aug. 27, 2015
Line of Credit Facility, aggregate principal amount						$ 30,000,000
Credit Agreement | Term A Loan Facility
Debt Instrument [Line Items]
Line of Credit Facility, expiration date			Feb. 26, 2016
Line of Credit Facility, aggregate principal amount						$ 97,800,000

Debt (Atlas Energy Term Loan Fa

Debt (Atlas Energy Term Loan Facility) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	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
Term loan facilities		$ 148,100,000
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 ($)

Nov. 30, 2015

Nov. 23, 2015

Oct. 31, 2015

Sep. 30, 2015

Aug. 31, 2015

Jul. 31, 2015

Jun. 30, 2015

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Feb. 28, 2015

Feb. 23, 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

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Mar. 31, 2014

Dec. 31, 2015

Nov. 22, 2015

Feb. 22, 2015

Line Of Credit Facility [Line Items]

Line of Credit Facility, current borrowing capacity

$ 700,000,000

$ 750,000,000

Required Total Funded Debt to EBITDA ratio

5.00%

Ratio of First Lien Debt to EBITDA

2.75%

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

$ 0.15

Percentage of borrowing base utilized

85.00%

Atlas Resource Partners, L.P.

Line Of Credit Facility [Line Items]

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

$ 0.0125

$ 0.0125

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 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

$ 0.5800

$ 0.5600

$ 0.5400

$ 0.5100

$ 0.1933

Revolving credit facility

$ 696,000,000

$ 592,000,000

Revolving Credit Facility

Line Of Credit Facility [Line Items]

Line of Credit Facility, current borrowing capacity

$ 750,000,000

700,000,000

$ 750,000,000

$ 900,000,000

Credit facility

$ 1,500,000

Line of Credit Facility, expiration date

Jul. 1, 2018

Percentage of stated amount of senior notes or additional second lien debt that borrowing base reduced

25.00%

25.00%

Revolving credit facility

$ 592,000,000

Letters of credit outstanding amount

$ 4,200,000

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 2.00% and 3.00% per annum (which shall change depending on the borrowing base utilization percentage) 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 1.00% and 2.00% per annum(which shall change depending on the borrowing base utilization percentage. 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 December 31, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 3.25%.

Line of Credit Facility, weighted average interest rate

3.25%

Aggregate principal amount of second lien debt

$ 300,000,000

Line Of Credit Facility covenant terms

The ARP Credit Agreement contains customary covenants including, without limitation, covenants that limit ARP’s ability to incur additional indebtedness (but which permits second lien debt in an aggregate principal amount of up to $300.0 million and third lien debt that satisfies certain conditions including pro forma financial covenants), grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merge or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The ARP Credit Agreement also requires that ARP maintain a ratio of First Lien Debt to EBITDA of 2.75 to 1.00 as set forth in the Eighth Amendment described above, 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 December 31, 2015.

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 | Third Lien Credit Agreement | 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%

Revolving Credit Facility | Quarter ended March 31, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt to EBITDA ratio

5.75%

4.50%

Revolving Credit Facility | Quarter ended June 30, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt to EBITDA ratio

5.75%

Revolving Credit Facility | Quarter ended September 30, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt to EBITDA ratio

5.50%

Revolving Credit Facility | Quarter ended December 31, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt to EBITDA ratio

5.50%

Revolving Credit Facility | Quarter ended March 31, 2018

Line Of Credit Facility [Line Items]

Required Total Funded Debt to EBITDA ratio

5.25%

Revolving Credit Facility | Fiscal quarters ending thereafter

Line Of Credit Facility [Line Items]

Required Total Funded Debt to EBITDA ratio

5.00%

4.00%

Revolving Credit Facility | Borrowing base utilization is less than 25%

Line Of Credit Facility [Line Items]

Line of credit facility, commitment fee percentage

0.375%

Revolving Credit Facility | Borrowing base utilization is less than 90%

Line Of Credit Facility [Line Items]

Percentage of borrowing base utilized

90.00%

Revolving Credit Facility | Quarter Ended March 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 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 | Eurodollar

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Revolving Credit Facility | Eurodollar | Borrowing base utilization is less than 25%

Line Of Credit Facility [Line Items]

Debt instrument, basis spread on variable rate

2.00%

Revolving Credit Facility | Eurodollar | Borrowing base utilization is less than 90%

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Revolving Credit Facility | Alternate Base Rate

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Revolving Credit Facility | Alternate Base Rate | Borrowing base utilization is less than 90%

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Revolving Credit Facility | Base Rate | Borrowing base utilization is less than 25%

Line Of Credit Facility [Line Items]

Debt instrument, basis spread on variable rate

0.50%

Debt (ARP Term Loan Facility) (

Debt (ARP Term Loan Facility) (Details) - USD ($)	Feb. 23, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Term Loan Facilities, unamortized discount		$ 7,827,000
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”).
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		$ 6,200,000
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 (ARP Senior Notes) (Detail

Debt (ARP Senior Notes) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 29, 2015	Dec. 17, 2015
Debt Instrument [Line Items]
Term Loan Facilities, unamortized discount	$ 7,827,000
Maximum debt indebtedness in exchange of senior notes				$ 100,000,000	$ 100,000,000
Debt instrument, restrictive covenants	The indentures governing the 7.75% ARP Senior Notes and 9.25% ARP Senior Notes contain covenants including without limitation covenants that limit 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 December 31, 2015.
Cash paid on accrued interest on debt	$ 106,700,000	$ 68,500,000	$ 22,300,000
Senior Notes Indenture
Debt Instrument [Line Items]
Percentage of senior secured outstanding debt	8.00%
Senior Notes Indenture | Maximum
Debt Instrument [Line Items]
Senior secured notes interest expense	$ 80,000,000
7.75% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt				500,000,000
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor	0
7.75% Senior Notes | Senior Notes Indenture
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt				1,000,000,000
9.25% Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt	$ 324,100,000				500,000,000
Senior Notes, maturity	2,021
Debt instrument, interest rate, stated percentage	9.25%
Term Loan Facilities, unamortized discount	$ 900,000
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 indenture governing the 9.25% Senior Notes (the “9.25% ARP Senior Notes 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.
9.25% Senior Notes | Maximum
Debt Instrument [Line Items]
Completion of exchange offer period	270 days
9.25% Senior Notes | Senior Notes Indenture
Debt Instrument [Line Items]
Aggregate principal amount of second lien debt					1,050,000,000
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 indenture governing the 7.75% Senior Notes (the “7.75% Senior Notes Indenture”)), plus accrued and unpaid interest and additional 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.
Consent fee payment description	Consent fee of $10.00 for each $1,000 in principal amount
Consent fee				10
Consent fee, principal amount				1,000
Deferred financing costs, capitalized				$ 3,800,000
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	9.25%	9.25%
Consent fee payment description	Consent fee of $10.00 for each $1,000 in principal amount
Consent fee					10
Consent fee, principal amount					1,000
Deferred financing costs, capitalized					$ 3,300,000

Debt (Aggregate Amount of the P

Debt (Aggregate Amount of the Partnership's, ARP's Future Debt Maturities Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
2,016	$ 4,250
2,018	592,000
2,020	318,450
Thereafter	700,000
Total principal maturities	1,614,700
Unamortized premiums	309
Unamortized discounts	(7,827)
Total debt	$ 1,607,182	$ 1,542,600

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Gain Loss [Line Items]
Cash flow hedges derivative assets at fair value, net	$ 358,100,000	$ 274,900,000
Net gain in accumulated other comprehensive income	4,300,000
Cash flow hedge gain (losses) to be reclassified within twelve months	3,700,000
Cash flow hedge gain (loss) to be reclassified in later periods	600,000
Derivative instruments, gains reclassified from accumulated OCI into income, effective portion	0	2,500,000
Reclassification to mark-to-market (gains) losses	(86,328,000)	7,739,000	$ (10,216,000)
Gain on mark-to-market derivatives	268,085,000	2,819,000
Gains or losses recognized during the period			0
Gas And Oil Production Revenue | EP Energy Acquisition
Derivative Instruments Gain Loss [Line Items]
Premiums paid on swaption contracts			14,500,000
Amortization expense on swaption contracts			$ 14,500,000
Atlas Growth Partners, L.P
Derivative Instruments Gain Loss [Line Items]
Derivative assets		0
Derivative liabilities		0
Atlas Resource Partners, L.P.
Derivative Instruments Gain Loss [Line Items]
Premiums paid on swaption contracts		$ 200,000
Net unrealized derivative assets payable to limited partners	2,400,000
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

Derivative Instruments (Summary

Derivative Instruments (Summary of Commodity Derivative Activity and Presentation in Partnership's Consolidated Statement of Operations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 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]	$ 86,328
Portion of settlements attributable to subsequent mark to market gains	[2]	93,182
Total cash settlements on commodity derivative contracts		179,510
Gains recognized prior to settlement	[2]	40,930
Gains recognized on open derivative contracts, net of amounts recognized in income in prior year	[2]	227,155
Gains on mark-to-market derivatives		$ 268,085	$ 2,819
[1]	Recognized in gas and oil production revenue.
[2]	Recognized in gain on mark-to-market derivatives.

Derivative Instruments (Fair Va

Derivative Instruments (Fair Values of the Company's Derivative Instruments Table) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 363,867,000	$ 279,254,000
Gross Amounts Recognized, Liabilities	(149,000)	(468,000)
Atlas Growth Partners, L.P
Derivatives Fair Value [Line Items]
Net Amount Presented, Assets		0
Net Amount Presented, Liabilities		$ 0
Atlas Growth Partners, L.P | Derivative Financial Instruments Current Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(96,000)
Gross Amounts Offset, Liabilities	96,000
Atlas Growth Partners, L.P | Derivative Financial Instruments Long Term Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(53,000)
Gross Amounts Offset, Liabilities	53,000
Atlas Growth Partners, L.P | Derivative Financial Instruments Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities	(149,000)
Gross Amounts Offset, Liabilities	149,000
Atlas Growth Partners, L.P | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	399,000
Gross Amounts Offset, Assets	(96,000)
Net Amount Presented, Assets	303,000
Atlas Growth Partners, L.P | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	162,000
Gross Amounts Offset, Assets	(53,000)
Net Amount Presented, Assets	109,000
Atlas Growth Partners, L.P | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	561,000
Gross Amounts Offset, Assets	(149,000)
Net Amount Presented, Assets	$ 412,000

Derivative Instruments (The Com

Derivative Instruments (The Company's Commodity Derivative Instruments by Type Table) (Details) - Atlas Growth Partners, L.P - Natural Gas Liquids – Crude Oil Fixed Price Swaps $ in Thousands	Dec. 31, 2015USD ($)bbl$ / bbl
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 412	[1]
Production Period Ending December 31 2016
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	76,000	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	45.229	[2]
Fair Value Asset / (Liability)	$ 303	[1]
Production Period Ending December 31 2017
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	37,100	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	49.968	[2]
Fair Value Asset / (Liability)	$ 127	[1]
Production Period Ending December 31 2018
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | bbl	26,500	[2]
Derivative, Swap Type, Average Fixed Price | $ / bbl	48.850	[2]
Fair Value Asset / (Liability)	$ (18)	[1]
[1]	Fair value based on forward WTI crude oil prices, as applicable.
[2]	“Bbl” represents barrels.

Derivative Instruments (Fair 69

Derivative Instruments (Fair Value of ARP's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 363,867	$ 279,254
Gross Amounts Recognized, Liabilities	(149)	(468)
Atlas Resource Partners, L.P. | Derivative Financial Instruments Current Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(98)
Gross Amounts Offset, Liabilities		98
Atlas Resource Partners, L.P. | Derivative Financial Instruments Long Term Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(370)
Gross Amounts Offset, Liabilities		370
Atlas Resource Partners, L.P. | Derivative Financial Instruments Liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(468)
Gross Amounts Offset, Liabilities		468
Atlas Resource Partners, L.P. | Current portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	159,460	144,357
Gross Amounts Offset, Assets		(98)
Net Amount Presented, Assets	159,460	144,259
Atlas Resource Partners, L.P. | Long-term portion of derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	198,262	130,972
Gross Amounts Offset, Assets		(370)
Net Amount Presented, Assets	198,262	130,602
Atlas Resource Partners, L.P. | Total derivative assets
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	357,722	275,329
Gross Amounts Offset, Assets		(468)
Net Amount Presented, Assets	$ 357,722	$ 274,861

Derivative Instruments (ARP's C

Derivative Instruments (ARP's Commodity Derivative Instruments by Type Table) (Details) - Atlas Resource Partners, L.P. $ in Thousands	Dec. 31, 2015USD ($)bblMMBTU$ / bbl$ / MMBTU
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 221,039	[1]
Natural Gas Put Options Drilling Partnership
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	2,393	[1]
Natural Gas Liquids Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	5,775	[2]
Natural Gas Liquids – Crude Oil Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	128,515	[2]
Total ARP Net Liability
Derivatives Fair Value [Line Items]
Fair Value Asset / (Liability)	$ 357,722	[2]
Production Period Ending December 31 2016 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	53,546,300	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.229	[3]
Fair Value Asset / (Liability)	$ 92,131	[1]
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	1,440,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.150	[3]
Fair Value Asset / (Liability)	$ 2,393	[1]
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	84,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	85.651	[3]
Fair Value Asset / (Liability)	$ 3,651	[2]
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	1,557,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	81.471	[3]
Fair Value Asset / (Liability)	$ 61,284	[2]
Production Period Ending December 31 2017 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	49,920,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.219	[3]
Fair Value Asset / (Liability)	$ 67,916	[1]
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	60,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	83.780	[3]
Fair Value Asset / (Liability)	$ 2,124	[2]
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	1,140,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	77.285	[3]
Fair Value Asset / (Liability)	$ 33,335	[2]
Production Period Ending December 31 2018 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	40,800,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.170	[3]
Fair Value Asset / (Liability)	$ 47,153	[1]
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	1,080,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	76.281	[3]
Fair Value Asset / (Liability)	$ 26,248	[2]
Production Period Ending December 31 2019 | Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Derivatives Nonmonetary Volume Notional Amount | MMBTU	15,960,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / MMBTU	4.017	[3]
Fair Value Asset / (Liability)	$ 13,839	[1]
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	540,000	[3]
Derivative, Swap Type, Average Fixed Price | $ / bbl	68.371	[3]
Fair Value Asset / (Liability)	$ 7,648	[2]
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	Fair value based on forward WTI crude oil prices, as applicable.
[3]	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

Fair Value of Financial Instr71

Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	$ 363,867	$ 279,254
Liabilities, gross	(149)	(468)
Total assets, fair value, net	363,718	278,786
Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	5,584	3,925
Atlas Resource Partners, L.P. | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,393	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	355,329	267,242
Liabilities, gross		(401)
Atlas Resource Partners, L.P. | Commodity Options
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross		5,320
Liabilities, gross		(67)
Atlas Growth Partners, L.P | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	561
Liabilities, gross	(149)
Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	5,584	3,925
Total assets, fair value, net	5,584	3,925
Level 1 | Rabbi trust
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Rabbi trust	5,584	3,925
Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	358,283	275,329
Liabilities, gross	(149)	(468)
Total assets, fair value, net	358,134	274,861
Level 2 | Atlas Resource Partners, L.P. | Puts
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	2,393	2,767
Level 2 | Atlas Resource Partners, L.P. | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	355,329	267,242
Liabilities, gross		(401)
Level 2 | Atlas Resource Partners, L.P. | Commodity Options
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross		5,320
Liabilities, gross		$ (67)
Level 2 | Atlas Growth Partners, L.P | Swap | Commodity Contract
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets, gross	561
Liabilities, gross	$ (149)

Fair Value of Financial Instr72

Fair Value of Financial Instruments (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 929,200	$ 1,363,400
Long-term debt	$ 1,607,182	$ 1,542,600
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). During the year ended December 31, 2013, ARP completed the acquisition of certain oil and gas assets from EP Energy (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 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 required significant judgments and estimates by the Company’s subsidiaries’ management at the time of the valuations, which were finalized in 2015.

Fair Value of Financial Instr73

Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	$ 2,074	$ 3,677	$ 6,401
Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	2,074	10,674
Asset Retirement Obligations | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities incurred	$ 2,074	$ 10,674

Certain Relationships and Rel74

Certain Relationships and Related Party Transactions (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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 the ultimate general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the ultimate 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.
Relationship with AGP
Related Party Transaction [Line Items]
Percentage of capital contribution	1.00%
Payment for management fee	$ 1.8	$ 0.3
Gross proceeds of private placement offering percentage	2.00%

Commitments and Contingencies75

Commitments and Contingencies (General Commitments) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating leases, rent expense, net	$ 16,200,000	$ 17,500,000	$ 13,100,000
Percentage of present value of future cash flows	10.00%
Net partnership revenues subordinated	$ 1,700,000	$ 5,300,000	$ 9,600,000
Commitment to expend	7,100,000
ARP’s and AGP’s Eagle Ford Acquisition
Contractual obligation, due in next twelve months	400,000
Contractual obligation, due in second year	0
Contractual obligation, due in third year	0
Contractual obligation, due in fourth year	0
Contractual obligation, due in fifth year	0
ARP’s Geomet Acquisition
Contractual obligation, due in next twelve months	3,700,000
Contractual obligation, due in second year	2,600,000
Contractual obligation, due in third year	1,800,000
Contractual obligation, due in fourth year	1,800,000
Contractual obligation, due in fifth year	1,800,000
Contractual obligation, due in thereafter	4,900,000
EP Energy Acquisition
Contractual obligation, due in next twelve months	2,200,000
Contractual obligation, due in second year	0
Contractual obligation, due in third year	0
Contractual obligation, due in fourth year	0
Contractual obligation, due in fifth year	$ 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%

Commitments and Contingencies76

Commitments and Contingencies (Schedule of Future Minimum Lease Payments) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 3,875
2,017	3,637
2,018	3,261
2,019	1,662
2,020	1,590
Thereafter	1,849
Operating leases, future minimum payments due, total	$ 15,874

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	Apr. 30, 2015	Dec. 31, 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

Jul. 31, 2013

Nov. 30, 2015

Aug. 31, 2015

Jul. 31, 2015

May. 31, 2015

Apr. 30, 2015

Oct. 31, 2014

Aug. 31, 2014

May. 31, 2014

Mar. 31, 2014

Jul. 31, 2013

Jun. 30, 2013

Jul. 14, 2015

Mar. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Oct. 31, 2015

Jul. 15, 2015

Capital Unit [Line Items]

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%

Partners unit, issued

9,803,451

0

Proceeds from Issuance of Common Limited Partners Units

$ 44,200,000

Payments for commissions

$ 1,100,000

Percentage of Preferred Unit Regular Quarterly Cash Distributions

10.75%

Atlas Growth Partners, L.P

Capital Unit [Line Items]

Partners unit, issued

12,623,500

9,581,900

1,095,010

Payment of stock Issuance costs

$ 12,700,000

$ 14,000,000

$ 1,900,000

Subsidiary or Equity Method Investee, Price-Per-Share

$ 10

$ 10

$ 10

Common limited partner units issued

$ 233,000,000

$ 233,000,000

Percentage of warrants to purchase additional common units in amount equal to

10.00%

Warrants, exercise price

$ 10

Common limited partner number of units purchased

300,000

0

200,010

Common limited partner units purchased

$ 5,000,000

$ 2,700,000

$ 1,800,000

Common stock, shares issued

$ 112,700,000

$ 81,600,000

$ 8,200,000

Warrants Received

109,501

1,262,350

958,190

Atlas Growth Partners, L.P | Private Placement

Capital Unit [Line Items]

Payment of stock Issuance costs

$ 203,400,000

Common limited partner units issued

$ 500,000,000

Number of days extension private placement offering

two 90 day

Stock issued during period, shares

23,300,410

Common limited partner number of units purchased

500,010

Common limited partner units purchased

$ 5,000,000

Atlas Resource Partners, L.P. and Atlas Growth Partners, L.P

Capital Unit [Line Items]

Gain on sale of subsidiary unit issuances

$ 4,300,000

$ 45,000,000

Arkoma Acquisition

Capital Unit [Line Items]

Partners unit, issued

6,500,000

Partners Capital Account Units Date Of Sale

May 2,015

Subsidiary or Equity Method Investee, Price-Per-Share

$ 7.97

Partners Capital Account Sale Of Units

$ 49,700,000

Rangely Acquisition

Capital Unit [Line Items]

Partners unit, issued

15,525,000

Partners Capital Account Units Date Of Sale

May 2,014

Subsidiary or Equity Method Investee, Price-Per-Share

$ 19.90

Partners Capital Account Sale Of Units

$ 297,300,000

ARP’s Geomet Acquisition

Capital Unit [Line Items]

Partners unit, issued

6,325,000

Partners Capital Account Units Date Of Sale

March 2,014

Subsidiary or Equity Method Investee, Price-Per-Share

$ 21.18

Partners Capital Account Sale Of Units

$ 129,000,000

EP Energy Acquisition

Capital Unit [Line Items]

Partners unit, issued

14,950,000

Partners Capital Account Units Date Of Sale

June 2,013

Subsidiary or Equity Method Investee, Price-Per-Share

$ 21.75

Partners Capital Account Sale Of Units

$ 313,100,000

Preferred Class B

Capital Unit [Line Items]

Conversion of Class B preferred units (units)

39,654

Class D and Class E Preferred Units

Capital Unit [Line Items]

Redemption price per unit

$ 25

Class D Preferred Units

Capital Unit [Line Items]

Tentative date for preferred stock redemption

Oct. 15, 2019

Class D Preferred Units | Eagle Ford Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

8.625%

Partners unit, issued

3,200,000

800,000

Partners Capital Account Units Date Of Sale

October 2,014

Subsidiary or Equity Method Investee, Price-Per-Share

$ 25

$ 25

Partners Capital Account Sale Of Units

$ 77,300,000

Percentage of Preferred Unit Regular Quarterly Cash Distributions

8.625%

Preferred Unit Regular Quarterly Cash Distributions Per Unit thereafter

$ 2.15625

Class E Preferred Units

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

10.75%

Partners unit, issued

255,000

Partners Capital Account Units Date Of Sale

April 2,015

Partners Capital Account Sale Of Units

$ 6,000,000

Redemption price per unit

$ 25

Preferred Unit Regular Cash Distributions Per Unit

$ 2.6875

Percentage of Preferred Unit Regular Quarterly Cash Distributions

10.75%

Preferred Unit Regular Quarterly Cash Distributions Per Unit thereafter

$ 25

$ 2.6875

Tentative date for preferred stock redemption

Apr. 15, 2020

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.6793

Equity Distribution Agreement with MLV & Co. LLC | Class D and Class E Preferred Units

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

8.625%

Aggregate Offering Price Of Common Units (Maximum)

$ 100,000,000

Volume weighted average price

97.00%

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

3.00%

Proceeds from Issuance of Common Limited Partners Units

$ 900,000

Payments for commissions

300,000

Payment of stock Issuance costs

$ 100,000

Equity Distribution Agreement with MLV & Co. LLC | Class D Preferred Units

Capital Unit [Line Items]

Partners unit, issued

0

90,328

Equity Distribution Agreement with MLV & Co. LLC | Class E Preferred Units

Capital Unit [Line Items]

Partners unit, issued

0

1,083

Over Allotment Units Issued | Rangely Acquisition

Capital Unit [Line Items]

Partners unit, issued

2,025,000

Over Allotment Units Issued | ARP’s Geomet Acquisition

Capital Unit [Line Items]

Partners unit, issued

825,000

Over Allotment Units Issued | EP Energy Acquisition

Capital Unit [Line Items]

Partners unit, issued

1,950,000

Class C Convertible Preferred Units | EP Energy Acquisition | ARP Acquisitions

Capital Unit [Line Items]

Partners unit, issued

3,749,986

Subsidiary or Equity Method Investee, Price-Per-Share

$ 23.10

$ 23.10

Common limited partner units issued

$ 86,600,000

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.51

Preferred Stock, Voting Rights

The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation.

Warrants Exercisable Date

Oct. 29, 2013

Warrants Expiration Date

Jul. 31, 2016

Preferred Units Description

The Class C preferred units were offered and sold in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Class C preferred units pay cash distributions in an amount equal to the greater of (i) $0.51 per unit and (ii) the distributions payable on each common unit at each declared quarterly distribution date. The Class C preferred units have no voting rights, except as set forth in the certificate of designation for the Class C preferred units, which provides, among other things, that the affirmative vote of 75% of the Class C Preferred Units is required to repeal such certificate of designation. Holders of the Class C preferred units have the right to convert the Class C preferred units on a one-for-one basis, in whole or in part, into common units at any time before July 31, 2016.

Warrants Received

562,497

Class C Convertible Preferred Units | EP Energy Acquisition | Atlas Energy

Capital Unit [Line Items]

Registration Rights Agreement Description And Terms

Upon issuance of the Class C preferred units and warrants on July 31, 2013, ARP entered into a registration rights agreement pursuant to which it agreed to file a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and upon exercise of the warrants. ARP agreed to use commercially reasonable efforts to file such registration statement within 90 days of the conversion of the Class C preferred units into common units or the exercise of the warrants. The Partnership filed a registration statement with the SEC to register the resale of the common units issuable upon conversion of the Class C preferred units and the registration statement was declared effective on March 27, 2015.

Equity Distribution Agreement with Deutsche Bank Securities Inc.

Capital Unit [Line Items]

Aggregate Offering Price Of Common Units (Maximum)

$ 25,000,000

Partners unit, issued

309,174

Proceeds from Issuance of Common Limited Partners Units

$ 6,900,000

Payments for commissions

$ 400,000

Equity Distribution Program Commencement Date

May 1, 2013

Equity Distribution Agreement Effective Date

Dec. 27, 2013

Cash Distributions - Additional

Cash Distributions - Additional Information (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
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.
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	0.5390625
Preferred Unit Regular Cash Distributions Per Unit	$ 2.15625
Partners' Capital Account, Units, Percentage	8.625%
Preferred Stock Liquidation Preference	$ 25
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	$ 2.6875
Partners' Capital Account, Units, Percentage	10.75%
Preferred Stock Liquidation Preference	$ 25
Atlas Growth Partners, L.P
Distribution Made To Limited Partner [Line Items]
Quarterly cash distribution target	0.175
Yearly cash distribution target	$ 0.70

Cash Distributions (Schedule of

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

Nov. 30, 2015

Nov. 23, 2015

Oct. 31, 2015

Sep. 30, 2015

Aug. 31, 2015

Jul. 31, 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

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Nov. 30, 2015

Oct. 31, 2015

Sep. 30, 2015

Aug. 31, 2015

Jul. 31, 2015

Jun. 30, 2015

May. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Mar. 31, 2014

Jan. 14, 2015

Jan. 14, 2016

Oct. 14, 2015

Sep. 30, 2015

Jul. 14, 2015

Jun. 30, 2015

Apr. 14, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2015

Distribution Made To Limited Partner [Line Items]

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

$ 0.15

Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

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

$ 0.0125

$ 0.0125

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 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

$ 0.5800

$ 0.5600

$ 0.5400

$ 0.5100

$ 0.1933

Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

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

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1167

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 June 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Month Ended July 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Sep. 14, 2015

Month Ended August 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Oct. 15, 2015

Month Ended September 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Nov. 13, 2015

Month Ended October 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Dec. 15, 2015

Month Ended November 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jan. 14, 2016

Month Ended March 31, 2013

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

May 15, 2013

Month Ended June 30, 2013

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2013

Month Ended September 30, 2013

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Nov. 14, 2013

Month Ended December 31, 2013

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Feb. 14, 2014

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

January 15, 2015 to April 14, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 15, 2015

April 15, 2015 to July 14, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jul. 15, 2015

July 15, 2015 to October 14, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Oct. 15, 2015

October 15, 2015 – January 14, 2016

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jan. 15, 2016

Quarter Ended December Thirty First Two Thousand And Thirteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

[1]

Feb. 14, 2014

Quarter Ended March Thirty First Two Thousand And Fourteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

May 15, 2014

Quarter Ended June Thirty Two Thousand And Fourteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2014

Quarter Ended September Thirty Two Thousand And Fourteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Nov. 14, 2014

Quarter Ended December Thirty First Two Thousand And Fourteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Feb. 13, 2015

Quarter Ended March Thirty First Two Thousand And Fifteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

May 15, 2015

Quarter Ended June Thirty Two Thousand And Fifteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Quarter Ended September Thirty Two Thousand And Fifteen | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Nov. 14, 2015

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

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 1,277

$ 1,277

$ 11,063

$ 10,949

$ 10,571

$ 10,309

$ 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

$ 12,718

$ 34,489

$ 33,291

$ 32,097

$ 22,428

$ 12,719

Limited Partner Interest | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 4,078

$ 2,646

$ 2,180

$ 1,636

$ 841

$ 342

$ 223

$ 120

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

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

[2]

638

[3]

637

[3]

637

[3]

637

[3]

638

[3]

637

[3]

643

642

643

643

643

745

745

1,491

1,492

1,491

1,493

1,492

1,466

1,466

1,466

1,467

4,400

4,248

2,072

1,957

1,466

General Partner | Atlas Resource Partners, L.P.

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 39

$ 39

$ 239

$ 236

$ 229

$ 223

$ 223

$ 221

$ 206

$ 204

$ 203

$ 1,378

$ 1,378

$ 1,378

$ 1,378

$ 1,378

$ 1,378

$ 1,377

$ 1,279

$ 1,279

$ 1,055

$ 1,055

$ 2,891

$ 2,443

$ 1,884

$ 946

$ 1,054

General Partner | Atlas Growth Partners, L.P

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 83

$ 54

$ 45

$ 33

$ 16

$ 7

$ 6

$ 2

Class D Preferred Limited Partners

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 1,974

$ 2,205

$ 2,157

$ 2,156

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

$ 0.6169270

$ 0.5390625

$ 0.5390625

$ 0.5390630

Class D Preferred Limited Partners | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 2,205

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

$ 0.5390625

Class E Preferred Limited Partners

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 172

$ 173

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

$ 0.671875

$ 0.6793

Class E Preferred Limited Partners | Subsequent Event

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 172

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

$ 0.671875

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 | Month Ended June 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Aug. 14, 2015

Class A Preferred Units | Month Ended July 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Sep. 14, 2015

Class A Preferred Units | Month Ended August 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Oct. 15, 2015

Class A Preferred Units | Month Ended September 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Nov. 13, 2015

Class A Preferred Units | Month Ended October 31, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Dec. 15, 2015

Class A Preferred Units | Month Ended November 30, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jan. 14, 2016

Class A Preferred Units | Preferred Unitholders

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

$ 338

$ 337

$ 337

$ 336

$ 336

$ 335

$ 334

$ 334

$ 333

[1]

Represents a pro-rated cash distribution of $0.1750 per common limited partner unit and general partner unit for the period from November 1, 2013, the date AGP commenced operations.

[2]

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

[3]

Includes payments for the Class C preferred unit monthly distributions. The remaining Class B Preferred Units were converted on July 25, 2015, and the Class B Preferred Unitholders received additional ARP common units upon conversion in lieu of the June distribution. No Class B Preferred Units were outstanding at December 31, 2015.

Cash Distributions (Schedule 81

Cash Distributions (Schedule of Distributions Declared by Partnership) (Parenthetical) (Details)	2 Months Ended
	Dec. 31, 2013$ / shares
Distribution Policy Members Or Limited Partners [Abstract]
Pro-rated Cash Distributions	$ 0.1750

Benefit Plans (2015 Long Term I

Benefit Plans (2015 Long Term Incentive Plan Narrative) (Details) - 2015 Long Term Incentive Plan	12 Months Ended
	Dec. 31, 2015shares
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	2,564,910
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	2,685,090

Benefit Plans (2015 LTIP Phanto

Benefit Plans (2015 LTIP Phantom Unit Activity) (Details) - 2015 Phantom Units - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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		840,894
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans		$ 0	$ 0	$ 0
Granted (Units)		2,794,710
Forfeited (Units)		(229,800)
Outstanding, end of period (Units)	[1],[2]	2,564,910
Non-cash compensation expense recognized		$ 5,678,000
Granted		$ 6.46
Forfeited		6.43
Outstanding, end of period	[1],[2]	$ 6.46
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value		$ 0	$ 0	$ 0
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value		2,400,000
Liabilities Related to Outstanding Phantom Units		$ 32,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities		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
Unrecognized compensation expense related to unvested phantom units		$ 10,300,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 7 months 6 days
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 December 31, 2015 was approximately $2.4 million.
[2]	There was approximately $32,000 recognized as liabilities on the Company’s consolidated balance sheet at December 31, 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 December 31, 2015.

Benefit Plans (2015 Unit Option

Benefit Plans (2015 Unit Option Activity) (Details) - 2015 Unit Options - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	$ 0	$ 0	$ 0

Benefit Plans (Rabbi Trust Narr

Benefit Plans (Rabbi Trust Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Rabbi Trust	$ 5,584,000	$ 3,925,000
Rabbi trust liabilities recorded	5,600,000	3,900,000
Partnership distributed to participants		85,772,000
Rabbi trust
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Partnership distributed to participants	$ 0	$ 1,900,000	$ 0

Benefit Plans (ARP Long Term In

Benefit Plans (ARP Long Term Incentive Plan Narrative) (Details) - ARP Long Term Incentive Plan	12 Months Ended
	Dec. 31, 2015shares
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	1,656,630
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	187,633

Benefit Plans (ARP LTIP Phantom

Benefit Plans (ARP LTIP Phantom Unit Activity) (Details) - ARP Phantom Units - USD ($)		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, beginning of year (Units)		799,192	[1],[2]	839,808	[1],[2]	948,476
Granted (Units)		9,730		264,173		145,813
Vested (Units)	[3]	(472,278)		(274,414)		(215,981)
Forfeited (Units)		(34,539)		(30,375)		(38,500)
Outstanding, end of period (Units)	[1],[2]	302,105		799,192		839,808
Non-cash compensation expense recognized		$ 4,124,000		$ 6,367,000		$ 9,166,000
Outstanding, beginning of year		$ 22.70	[1],[2]	$ 24.31	[1],[2]	$ 24.76
Granted		8.50		19.44		21.87
Vested	[3]	23.55		24.46		24.73
Forfeited		23.13		22.76		23.96
Outstanding, end of period	[1],[2]	$ 20.87		$ 22.70		$ 24.31
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value		$ 4,000,000		$ 5,400,000		$ 6,100,000
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value		300,000
Liabilities Related to Outstanding Phantom Units		$ 7,000		$ 100,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities		13,391		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		$ 13.07		$ 21.16
Unrecognized compensation expense related to unvested phantom units		$ 1,800,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 6 months
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		159,996
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans		$ 700,000		$ 2,000,000		$ 1,900,000
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 aggregate intrinsic value for phantom unit awards outstanding at December 31, 2015 was $0.3 million.
[2]	There were approximately $7,000 and $0.1 million recognized as liabilities on the Company’s consolidated balance sheets at December 31, 2015 and 2014, respectively, representing 13,391 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 $13.07 and $21.16 at December 31, 2015 and 2014, respectively.
[3]	The intrinsic values of phantom unit awards vested during the years ended December 31, 2015, 2014 and 2013 were $4.0 million, $5.4 million and $6.1 million, respectively.

Benefit Plans (ARP Unit Options

Benefit Plans (ARP Unit Options Activity) (Details) - 2012 Long Term Incentive Plans - Phantom Units - USD ($)		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
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.
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		80,038
Proceeds from Stock Options Exercised		$ 0		$ 0		$ 0
Outstanding, beginning of year (Units)		1,458,300	[1],[2]	1,482,675	[1],[2]	1,515,500
Granted (Units)						5,000
Forfeited (Units)		(103,775)		(24,375)		(37,825)
Outstanding, end of period (Units)	[1],[2]	1,354,525		1,458,300		1,482,675
Options exercisable (Units)	[3]	1,273,487		730,775		370,700
Non-cash compensation expense recognized		$ 820,000		$ 1,700,000		$ 3,514,000
Outstanding, beginning of year		$ 24.66	[1],[2]	$ 24.66	[1],[2]	$ 24.68
Granted						21.56
Forfeited		24.67		24.52		24.80
Outstanding, end of period	[1],[2]	24.66		24.66		24.66
Options exercisable, end of year	[3]	$ 24.67		$ 24.67		$ 24.67
Share Based Compensation Arrangement By Share Based Payment Award Options Exercises In Period Total Intrinsic Value		$ 0		$ 0		$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term		6 years 4 months 24 days
Aggregate Intrinsic Value Of Options Outstanding		$ 0		$ 0		$ 1,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term		6 years 4 months 24 days		7 years 4 months 24 days		8 years 4 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		$ 0		$ 0
Unrecognized compensation expense related to unvested unit options		$ 44,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition		4 months 24 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.
Expected dividend yield						8.00%
Expected unit price volatility						35.50%
Risk-free interest rate						1.40%
Expected term (in years)						6 years 3 months 22 days
Fair value of unit options granted						$ 0.0295
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 December 31, 2015 was 6.4 years.
[2]	There were no aggregate intrinsic values of options outstanding at December 31, 2015 and 2014. The aggregate intrinsic value of options outstanding at December 31, 2013 was approximately $1,000.
[3]	The weighted average remaining contractual life for exercisable options at December 31, 2015, 2014 and 2013 was 6.4 years, 7.4 years and 8.4 years, respectively. There were no intrinsic values for options exercisable at December 31, 2015, 2014 and 2013.

Benefit Plan (Restricted Units

Benefit Plan (Restricted Units Narrative) (Details) - Restricted Stock	12 Months Ended
	Dec. 31, 2015shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares, Issued	0
Shares, Granted	0
Shares, Outstanding	0

Operating Segment Information90

Operating Segment Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015Segment
Segment Reporting [Abstract]
Number of reportable operating segments	3

Operating Segment Information91

Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 146,613	$ 262,834	$ 98,247	$ 245,799	$ 196,170	$ 208,589	$ 141,604	$ 162,147	$ 753,493	$ 708,510	$ 475,099
Depreciation, depletion and amortization expense									(166,929)	(242,079)	(139,916)
Asset impairment	$ (294,400)	$ (679,500)			$ (580,700)				(973,981)	(580,654)	(38,014)
General and administrative									(109,569)	(90,476)	(89,957)
Gain (loss) on asset sales and disposal									(1,181)	(1,859)	(987)
Interest expense									(125,658)	(73,435)	(39,712)
Loss on early extinguishment of debt									(4,726)
Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Asset impairment										(580,700)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Revenues									740,033	701,654	474,476
Operating costs and expenses									(320,922)	(431,032)	(351,673)
Depreciation, depletion and amortization expense									(157,978)	(239,923)	(139,783)
Asset impairment									(966,635)	(573,774)	(38,014)
Gain (loss) on asset sales and disposal									(1,181)	(1,869)	(987)
Interest expense									(102,133)	(62,144)	(34,324)
Segment loss									(808,816)	(607,088)	(90,305)
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Revenues									12,708	5,707	302
Operating costs and expenses									(14,968)	(13,816)	(3,812)
Depreciation, depletion and amortization expense									(8,951)	(2,156)	(133)
Asset impairment									(7,346)	(6,880)
Segment loss									(18,557)	(17,145)	(3,643)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Revenues									752	1,149	321
General and administrative									(30,862)	(6,381)	(8,162)
Gain (loss) on asset sales and disposal										10
Interest expense									(23,525)	(11,291)	(5,388)
Loss on early extinguishment of debt									(4,726)
Segment loss									$ (58,361)	$ (16,513)	$ (13,229)

Operating Segment Information92

Operating Segment Information (Reconciliation of Segment Loss to Net Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Net loss	$ (885,734)	$ (640,746)	$ (107,177)
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Net loss	(808,816)	(607,088)	(90,305)
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Net loss	(18,557)	(17,145)	(3,643)
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Net loss	$ (58,361)	$ (16,513)	$ (13,229)

Operating Segment Information93

Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 146,613	$ 262,834	$ 98,247	$ 245,799	$ 196,170	$ 208,589	$ 141,604	$ 162,147	$ 753,493	$ 708,510	$ 475,099
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Total revenues									740,033	701,654	474,476
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total revenues									12,708	5,707	302
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total revenues									$ 752	$ 1,149	$ 321

Operating Segment Information94

Operating Segment Information (Capital Expenditures) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Capital expenditures	$ 156,360	$ 225,636	$ 267,480
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Capital expenditures	127,138	212,763	263,886
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Capital expenditures	$ 29,222	$ 12,873	$ 3,594

Operating Segment Information95

Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Goodwill	$ 13,639	$ 13,639
Total assets	1,918,114	3,026,315
Reportable Legal Entities | Atlas Resource Partners, L.P.
Segment Reporting Information [Line Items]
Goodwill	13,639	13,639
Total assets	1,731,004	2,798,120
Reportable Legal Entities | Atlas Growth Partners, L.P
Segment Reporting Information [Line Items]
Total assets	160,267	190,161
Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total assets	$ 26,843	$ 38,034

Subsequent Events (The Company)

Subsequent Events (The Company) (Details) $ / shares in Units, $ in Thousands	Mar. 30, 2016USD ($)$ / shares	Mar. 29, 2016USD ($)	Mar. 08, 2016USD ($)	Feb. 24, 2016USD ($)	Jan. 28, 2016USD ($)	Aug. 10, 2015	Dec. 31, 2015USD ($)	Sep. 30, 2017	Dec. 31, 2014USD ($)
Subsequent Event [Line Items]
Term Loan Facilities, outstanding							$ 1,607,182		$ 1,542,600
2,016							4,250
2,018							592,000
2,020							318,450
Thereafter							700,000
Third Amendment
Subsequent Event [Line Items]
2,016							4,300
2,017							35,000
2,018							592,000
2,019							35,000
2,020							250,000
Thereafter							700,000
Subsequent Event
Subsequent Event [Line Items]
Debt instrument, basis spread on variable rate	30.00%
Subsequent Event | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date		Mar. 29, 2016		Feb. 24, 2016	Jan. 28, 2016
Subsequent Event | Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid		$ 2,000		$ 2,000	$ 2,000
Distribution Made to Member or Limited Partner, Distribution Date		Apr. 14, 2016		Mar. 16, 2016	Feb. 12, 2016
Distribution Made to Member or Limited Partner, Date of Record		Apr. 8, 2016		Mar. 9, 2016	Feb. 8, 2016
Subsequent Event | Series A Preferred Units | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date			Mar. 8, 2016		Jan. 28, 2016
Distribution Made to Member or Limited Partner, Cash Distributions Paid			$ 300		$ 300
Subsequent Event | Series A Preferred Units | Cash Distribution Paid
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Distribution Date			Mar. 16, 2016		Feb. 12, 2016
Distribution Made to Member or Limited Partner, Date of Record			Mar. 9, 2016		Feb. 6, 2016
Subsequent Event | Third Amendment
Subsequent Event [Line Items]
Current Portion of Long-term Debt	$ 4,250
Interest on long term debt	500
First Lien Credit Agreement
Subsequent Event [Line Items]
Term Loan Facilities, outstanding							$ 72,700
Line Of Credit Facility covenant terms							Replace the existing financial covenants with (i) the requirement that the Company maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016.
Line of Credit Facility interest rate description							Borrowings under the First Lien Term Loan Facility bear interest, at the Company’s option, at either (i) LIBOR plus 7.0% (as used with respect to the First Lien Term Loan Facility, “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%, each plus 6.0% (as used with respect to the First Lien Term Loan Facility, an “ABR Loan”). Interest is generally payable at interest payment periods selected by the Company for Eurodollar Loans and quarterly for ABR Loans
First Lien Credit Agreement | Alternate Base Rate
Subsequent Event [Line Items]
Debt instrument, basis spread on variable rate						6.00%
First Lien Credit Agreement | Subsequent Event
Subsequent Event [Line Items]
Term Loan Facilities, outstanding	$ 35,000
Line of Credit Facility, expiration date	Sep. 30, 2017
Line of Credit Facility, extension expiration date	Sep. 30, 2018
Extension fee percentage	5.00%
Restricted cash and cash equivalents	$ 4,000
Earnings Before Interest Taxes Depreciation and Amortization	$ 2,000
Debt instrument, basis spread on variable rate	20.00%
First Lien Credit Agreement | Subsequent Event | ABR Loans
Subsequent Event [Line Items]
Percentage of Cash Interest	0.50%
First Lien Credit Agreement | Subsequent Event | Eurodollar Loans
Subsequent Event [Line Items]
Percentage of Cash Interest	1.50%
First Lien Credit Agreement | Subsequent Event | Alternate Base Rate
Subsequent Event [Line Items]
Percentage of Pay in Kind Interest	11.00%
Second Lien Credit Agreement
Subsequent Event [Line Items]
Line of Credit Facility interest rate description							Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If the Company’s market capitalization is greater than $75 million, it can issue common units in lieu of increasing the principal to satisfy the interest obligation.
Second Lien Credit Agreement | Minimum | Scenario Forecast
Subsequent Event [Line Items]
Asset coverage ratio								0.0200
Second Lien Credit Agreement | Subsequent Event
Subsequent Event [Line Items]
Term Loan Facilities, outstanding	$ 35,800
Deemed Prepayment Premium	$ 2,400
Line of Credit Facility, expiration date	Mar. 30, 2019
Line of Credit Facility, extension expiration date	Mar. 30, 2020
Debt instrument, basis spread on variable rate	30.00%
Percentage of warrants to purchase outstanding common units	15.00%
Warrants issue period, in days	30 days
Warrants, exercise price | $ / shares	$ 0.20
Second Lien Credit Agreement | Subsequent Event | Maximum
Subsequent Event [Line Items]
Extension fee percentage	5.00%
Second Lien Credit Agreement | Subsequent Event | Minimum
Subsequent Event [Line Items]
Market capitalization	$ 75,000

Subsequent Events (The Company

Subsequent Events (The Company NYSE Compliance) (Details) - Subsequent Event - USD ($) $ / shares in Units, $ in Millions	Mar. 18, 2016	Jan. 12, 2016	Jan. 07, 2016
Subsequent Event [Line Items]
Consecutive trading days	30 days	30 days	30 days
Maximum
Subsequent Event [Line Items]
Average closing price of common unit		$ 1	$ 1
Average market capitalization			$ 50
Stockholders’ equity			$ 50
Minimum
Subsequent Event [Line Items]
Average market capitalization	$ 15

Subsequent Events (Atlas Resour

Subsequent Events (Atlas Resource Senior Note Repurchases) (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Feb. 29, 2016	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Subsequent Event [Line Items]
Repayment of debt	$ 33,100
Loss on early extinguishment of debt				$ (4,726)
9.25% Senior Notes
Subsequent Event [Line Items]
Debt instrument, interest rate, stated percentage				9.25%
Senior Notes, maturity				2,021
Atlas Resource Partners, L.P. | 7.75% Senior Notes
Subsequent Event [Line Items]
Senior Notes				$ 374,619	$ 374,544
Debt instrument, interest rate, stated percentage				7.75%	7.75%
Senior Notes, maturity				2,021
Atlas Resource Partners, L.P. | 9.25% Senior Notes
Subsequent Event [Line Items]
Senior Notes				$ 324,080	$ 323,916
Debt instrument, interest rate, stated percentage				9.25%	9.25%
Scenario Forecast | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Loss on early extinguishment of debt			$ 25,900
Subsequent Event | 7.75% Senior Notes
Subsequent Event [Line Items]
Senior Notes, maturity		2,021
Subsequent Event | Senior Notes Nine Point Two Five Percentage Due Twenty Twenty One
Subsequent Event [Line Items]
Senior Notes, maturity		2,021
Subsequent Event | Atlas Resource Partners, L.P.
Subsequent Event [Line Items]
Repayment of debt		$ 5,500
Subsequent Event | Atlas Resource Partners, L.P. | 7.75% Senior Notes
Subsequent Event [Line Items]
Senior Notes		$ 20,300
Debt instrument, interest rate, stated percentage		7.75%
Subsequent Event | Atlas Resource Partners, L.P. | 9.25% Senior Notes
Subsequent Event [Line Items]
Senior Notes		$ 12,100
Debt instrument, interest rate, stated percentage		9.25%

Subsequent Events (Atlas Reso99

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

Mar. 29, 2016

Mar. 22, 2016

Feb. 24, 2016

Jan. 28, 2016

Jan. 15, 2016

Nov. 30, 2015

Nov. 23, 2015

Oct. 31, 2015

Sep. 30, 2015

Aug. 31, 2015

Jul. 31, 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

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Mar. 31, 2014

Jul. 14, 2015

Subsequent Event [Line Items]

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

$ 0.15

Atlas Resource Partners, L.P.

Subsequent Event [Line Items]

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

$ 0.0125

$ 0.0125

$ 0.1083

$ 0.1083

$ 0.1083

$ 0.1083

$ 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

$ 0.5800

$ 0.5600

$ 0.5400

$ 0.5100

$ 0.1933

Class E Preferred Units

Subsequent Event [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.6793

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

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

Subsequent Event [Line Items]

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.671875

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

Mar. 29, 2016

Feb. 24, 2016

Jan. 28, 2016

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

$ 0.0125

$ 0.0125

$ 0.0125

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Mar. 22, 2016

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

$ 0.5390625

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Mar. 22, 2016

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

$ 0.671875

Subsequent Event | Cash Distribution Paid

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 2,000,000

$ 2,000,000

$ 2,000,000

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 14, 2016

Mar. 16, 2016

Feb. 12, 2016

Distribution Made to Member or Limited Partner, Date of Record

Apr. 8, 2016

Mar. 9, 2016

Feb. 8, 2016

Subsequent Event | Cash Distribution Paid | Common Unitholders

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 39,000

$ 39,000

$ 39,000

Subsequent Event | Cash Distribution Paid | Class C Preferred Units

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 600,000

$ 600,000

$ 600,000

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 15, 2016

Distribution Made to Member or Limited Partner, Date of Record

Apr. 1, 2016

Distribution Made to Limited Partner, Cash Distributions Paid

$ 2,200,000

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 15, 2016

Distribution Made to Member or Limited Partner, Date of Record

Apr. 1, 2016

Distribution Made to Limited Partner, Cash Distributions Paid

$ 200,000

Subsequent Events (Atlas Res100

Subsequent Events (Atlas Resource NYSE Compliance) (Details) - Subsequent Event - $ / shares	Mar. 18, 2016	Jan. 12, 2016	Jan. 07, 2016
Subsequent Event [Line Items]
Consecutive trading days	30 days	30 days	30 days
Maximum
Subsequent Event [Line Items]
Average closing price of common unit		$ 1	$ 1

Subsequent Events (Atlas Growth

Subsequent Events (Atlas Growth Cash Distribution) (Details) - USD ($) $ / shares in Units, $ in Millions

Mar. 29, 2016

Feb. 24, 2016

Feb. 05, 2016

Jan. 28, 2016

Nov. 23, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Subsequent Event [Line Items]

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

$ 0.15

Subsequent Event | Cash Distribution Declared

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Mar. 29, 2016

Feb. 24, 2016

Jan. 28, 2016

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

$ 0.0125

$ 0.0125

$ 0.0125

Subsequent Event | Cash Distribution Paid

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 2

$ 2

$ 2

Distribution Made to Member or Limited Partner, Distribution Date

Apr. 14, 2016

Mar. 16, 2016

Feb. 12, 2016

Distribution Made to Member or Limited Partner, Date of Record

Apr. 8, 2016

Mar. 9, 2016

Feb. 8, 2016

Atlas Growth Partners, L.P

Subsequent Event [Line Items]

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

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1750

$ 0.1167

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Declaration Date

Feb. 5, 2016

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

$ 0.1750

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 4.2

Distribution Made to Member or Limited Partner, Distribution Date

Feb. 12, 2016

Distribution Made to Member or Limited Partner, Date of Record

Dec. 31, 2015

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

Subsequent Event [Line Items]

Distribution Made to Member or Limited Partner, Cash Distributions Paid

$ 0.1

Supplemental Oil and Gas Inf102

Supplemental Oil and Gas Information (Reserve Quantity Information) (Details)		12 Months Ended
		Dec. 31, 2015bblMcf		Dec. 31, 2014bblMcf	Dec. 31, 2013bblMcf	Dec. 31, 2012bblMcf
Natural Gas Reserves
Reserve Quantities [Line Items]
Balance | Mcf		1,064,877,455		1,003,779,503	573,774,257
Extensions, discoveries and other additions | Mcf	[1]	6,806,339		58,461,204	90,098,219
Sales of reserves in-place | Mcf		(2,713,428)	[2]	(169,035)	(2,755,155)
Purchase of reserves in-place | Mcf	[3]			88,635,059	493,481,302
Transfers to limited partnerships | Mcf		(2,958,882)		(4,887,095)	(2,485,210)
Revisions | Mcf	[4]	(379,058,376)		5,947,622	(88,484,468)
Production | Mcf		(79,266,969)		(86,889,803)	(59,849,442)
Balance | Mcf		607,686,139		1,064,877,455	1,003,779,503
Proved developed reserves | Mcf		568,793,757		889,073,136	766,872,394	338,655,324
Proved undeveloped reserves | Mcf		38,892,382		175,804,319	236,907,109	235,118,932
Oil
Reserve Quantities [Line Items]
Balance		62,949,525		14,988,824	8,868,836
Extensions, discoveries and other additions	[1]	3,460,609		3,372,177	8,255,531
Sales of reserves in-place		(2,393)	[2]	(1,519)
Purchase of reserves in-place	[3]			51,168,449	1,964
Transfers to limited partnerships		(481,771)		(684,613)	(239,910)
Revisions	[4]	(11,223,648)		(4,639,546)	(1,412,371)
Production		(2,119,266)		(1,254,247)	(485,226)
Balance		52,583,056		62,949,525	14,988,824
Proved developed reserves		27,129,766		31,150,298	3,459,260	3,400,447
Proved undeveloped reserves		25,453,290		31,799,227	11,529,564	5,468,389
Natural Gas Liquids Reserves
Reserve Quantities [Line Items]
Balance		23,379,780		18,957,016	16,061,897
Extensions, discoveries and other additions	[1]	293,256		3,986,986	8,197,272
Sales of reserves in-place				(11,326)	(4,625)
Purchase of reserves in-place	[3]			5,189,827	55,187
Transfers to limited partnerships		(342,156)		(665,486)	(258,381)
Revisions	[4]	(13,769,701)		(2,689,372)	(3,826,744)
Production		(1,084,848)		(1,387,865)	(1,267,590)
Balance		8,476,331		23,379,780	18,957,016
Proved developed reserves		6,488,931		12,209,825	7,676,389	7,884,778
Proved undeveloped reserves		1,987,400		11,169,954	11,280,627	8,177,120
[1]	For the year ended December 31, 2015, the increase represents PUD conversions related to development activity in the Eagle Ford Shale. For the year ended December 31, 2014, the increase was due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s Geomet Acquisitions. For the year ended December 31, 2013, the increase was primarily due to the addition of Marble Falls wells
[2]	Decrease mainly due to ARP's sale of the County Line assets.
[3]	Represents the purchase of proved reserves due to the Rangely, Eagle Ford and GeoMet Acquisitions for the year ended December 31, 2014 and mainly due to the EP Energy Acquisition for the year ended December 31, 2013.
[4]	The downward revisions for the year ended December 31, 2015 were primarily due to wells being shut-in as well as unfavorable economic conditions primarily related to gas and oil commodity prices. For the year ended December 31, 2014, the downward revisions on oil and NGL were primarily due to wells being shut-in. The upward revision for the year ended December 31, 2014 on gas was primarily due to production outperforming previous forecasts. The downward revisions for the year ended December 31, 2013 were primarily due to a reduction of ARP’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

Supplemental Oil and Gas Inf103

Supplemental Oil and Gas Information (Schedule of Capitalized Costs Related to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Proved properties	$ 3,733,614	$ 3,545,208
Unproved properties	213,047	311,946
Support equipment	44,921	37,359
Capitalized Costs Related To Oil And Gas Producing Activities
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Proved properties	3,733,614	3,639,833
Unproved properties	213,047	217,321
Support equipment	44,921	37,359
Total natural gas and oil properties	3,991,582	3,894,513
Accumulated depreciation, depletion and amortization	(2,717,002)	(1,518,686)
Net capitalized costs	$ 1,274,580	$ 2,375,827

Supplemental Oil and Gas Inf104

Supplemental Oil and Gas Information (Schedule of Results of Operations from Oil and gas Producing Activities) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Revenues		$ 368,845	$ 475,758	$ 273,906
Production costs		(171,882)	(184,296)	(100,178)
Depreciation, depletion and amortization		(153,938)	(231,638)	(132,860)
Long-lived asset impairment	[1]	(973,981)	(580,654)	(38,014)
Results of Operations, Income before Income Taxes, Total		(930,956)	(520,830)	2,854
Long-lived asset impairment		(973,981)	(580,654)	$ (38,014)
Reclassification out of Accumulated Other Comprehensive Income
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Net future hedge gains reclassified from accumulated other comprehensive income		$ 85,800	82,300
Appalachian Basin
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Long-lived asset impairment			(562,600)
Goodwill impairment			$ 18,100
[1]	During the year ended December 31, 2015, the Company recognized $974.0 million of asset impairment primarily related to ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, and unproved acreage in the New Albany Shale, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income. During the year ended December 31, 2014, the Company recognized $580.7 million of asset impairment consisting of $562.6 million 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 net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, ARP recognized $38.0 million of impairment primarily related to its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales.

Supplemental Oil and Gas Inf105

Supplemental Oil and Gas Information (Schedule of Costs Incurred in Oil and gas Producing Activities) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Proved properties		$ 55,033	$ 754,197	$ 863,421
Unproved properties		43,820	10,978	895
Exploration costs	[1]	1,601	722	1,053
Development costs		102,110	177,726	214,383
Total costs incurred in oil & gas producing activities		$ 202,564	$ 943,623	$ 1,079,752
[1]	There were no exploratory wells drilled during the years ended December 31, 2015, 2014 and 2013.

Supplemental Oil and Gas Inf106

Supplemental Oil and Gas Information (Schedule of Standardized Measure of Estimated Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Future cash inflows	$ 3,910,339	$ 10,802,697	$ 5,268,148
Future production costs	(1,954,564)	(4,561,129)	(2,397,997)
Future development costs	(1,289,841)	(1,623,218)	(752,369)
Future net cash flows	665,934	4,618,350	2,117,782
Less 10% annual discount for estimated timing of cash flows	(90,703)	(2,381,586)	(1,038,491)
Standardized measure of discounted future net cash flows	$ 575,231	$ 2,236,764	$ 1,079,291

Supplemental Oil and Gas Inf107

Supplemental Oil and Gas Information (Schedule of Changes in Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Balance, beginning of year		$ 2,236,764	$ 1,079,291	$ 623,676
Sales and transfers of oil and gas, net of related costs	[1]	(137,942)	(275,789)	(171,409)
Net changes in prices and production costs	[2]	(1,629,945)	339,776	85,191
Revisions of previous quantity estimates		(41,147)	(33,526)	(1,881)
Development costs incurred		88,261	52,077	27,245
Changes in future development costs		(167,995)	(90,887)	(21,579)
Transfers to limited partnerships		(13,291)	(2,966)	(53,392)
Extensions, discoveries, and improved recovery less related costs		20,408	69,436	143,338
Purchases of reserves in-place	[3]		1,018,345	516,985
Sales of reserves in-place	[4]	(2,162)	(332)	(2,053)
Accretion of discount		223,676	107,929	62,368
Estimated settlement of asset retirement obligations		(224)	(16,824)	(18,858)
Estimated proceeds on disposals of well equipment		(1,172)	(21,896)	17,052
Changes in production rates timing and other			12,130	(127,392)
Outstanding, end of year		$ 575,231	$ 2,236,764	$ 1,079,291
[1]	Includes the amount of sales of oil and gas previously included in proved reserves and sold during the period ended.
[2]	Decrease due to commodity price declines for the year ended December 31, 2015.
[3]	Represents the change in discounted value of the proved reserves primarily due to the purchase of proved reserves due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s Geomet Acquisitions for the period ended December 31, 2014 and primarily due to the purchase of proved reserves in Marble Falls for the period ended December 31, 2013.
[4]	Decrease mainly due to ARP's sale of the County Line assets.

Quarterly Results (Unaudited) -

Quarterly Results (Unaudited) - Schedule of Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended																12 Months Ended
		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues		$ 146,613		$ 262,834		$ 98,247		$ 245,799		$ 196,170		$ 208,589		$ 141,604		$ 162,147		$ 753,493	$ 708,510	$ 475,099
Net income (loss)		(297,357)	[1]	(582,313)	[1]	(59,543)	[1]	53,479	[1]	(594,551)	[2]	(4,349)	[2]	(24,394)	[2]	(17,452)	[2]
Loss attributable to non-controlling interests		228,905		439,969		38,745		(58,303)		437,611		5,137		18,383		10,308		649,316	471,439	58,389
Net loss attributable to owner’s interest prior to the transfer of assets on February 27, 2015								10,475										(10,475)	(169,307)	(48,788)
Net income (loss) attributable to common unitholders		$ (69,466)		$ (143,353)		$ (21,802)		$ 5,318		(156,940)		$ 788		$ (6,011)		$ (7,144)
Basic	[3]	$ (2.67)		$ (5.51)		$ (0.80)		$ 0.22
Diluted	[3]	$ (2.67)		$ (5.51)		$ (0.80)		$ 0.18
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units		7,649,000		7,787,000		5,759,000
Asset impairment		$ 294,400		$ 679,500						$ 580,700								$ 973,981	$ 580,654	$ 38,014
[1]	Includes an asset impairment charge of $679.5 million and $294.4 million in the third and fourth quarters of 2015, respectively.
[2]	Includes an asset impairment charge of $580.7 million in the fourth quarter of 2014.
[3]	For the fourth quarter, third quarter and second quarter of the year ended December 31, 2015, approximately 7,649,000, 7,787,000 and 5,759,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive.