Titan Energy 10-K 7 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	Feb. 29, 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 Resource Partners, L.P.
Entity Central Index Key	1,532,750
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 457.9
Entity Common Stock, Units Outstanding		102,421,097
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Trading Symbol	ARP

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 1,353	$ 15,247
Accounts receivable	63,367	114,520
Advances to affiliates		6,567
Current portion of derivative asset	159,460	144,259
Subscriptions receivable	19,877	32,398
Prepaid expenses and other	22,935	26,296
Total current assets	266,992	339,287
Property, plant and equipment, net	1,191,611	2,263,820
Goodwill and intangible assets, net	14,095	14,330
Long-term derivative asset	198,262	130,602
Other assets, net	60,044	50,081
Total assets	1,731,004	2,798,120
Current liabilities:
Accounts payable	49,249	111,198
Advances from affiliates	9,924	8,816
Liabilities associated with drilling contracts	21,483	40,611
Current portion of derivative payable to Drilling Partnerships	2,574	932
Accrued well drilling and completion costs	26,914	80,404
Accrued interest	25,436	26,452
Distribution payable	4,334	20,876
Deferred acquisition purchase price		23,445
Accrued liabilities	22,086	33,406
Total current liabilities	162,000	346,140
Long-term debt	1,534,482	1,394,460
Asset retirement obligations	113,740	107,950
Other long-term liabilities	$ 5,410	$ 2,033
Commitments and contingencies (Note 11)
Partners’ Capital (Deficit):
General partner’s interest	$ (33,642)	$ (13,697)
Preferred limited partners’ interests	188,739	163,522
Common limited partners’ interests	(260,276)	605,065
Accumulated other comprehensive income	19,375	191,471
Total partners’ capital (deficit)	(84,628)	947,537
Total liabilities and partners’ capital (deficit)	1,731,004	2,798,120
Common Class C
Partners’ Capital (Deficit):
Class C common limited partner warrants	$ 1,176	$ 1,176

CONSOLIDATED STATEMENTS OF OPER

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		$ 356,999	$ 470,051	$ 273,604
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		267,223	2,819
Other, net		241	590	(14,456)
Total revenues		740,033	701,654	474,476
Costs and expenses:
Gas and oil production		169,653	182,226	100,098
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	[1]	65,968	72,349	78,063
Depreciation, depletion and amortization		157,978	239,923	139,783
Asset impairment		966,635	573,774	38,014
Total costs and expenses		1,445,535	1,244,729	529,470
Operating loss		(705,502)	(543,075)	(54,994)
Interest expense	[1]	(102,133)	(62,144)	(34,324)
Loss on asset sales and disposal	[1]	(1,181)	(1,869)	(987)
Net loss		(808,816)	(607,088)	(90,305)
Preferred limited partner dividends		(16,469)	(19,267)	(11,992)
Net loss attributable to common limited partners and the general partner		(825,285)	(626,355)	(102,297)
Allocation of net loss attributable to common limited partners and the general partner:
Common limited partners’ interest		(808,780)	(625,133)	(105,661)
General partner’s interest		(16,505)	(1,222)	3,364
Net loss attributable to common limited partners and the general partner		$ (825,285)	$ (626,355)	$ (102,297)
Net loss attributable to common limited partners per unit:
Basic		$ (8.63)	$ (8.37)	$ (2.01)
Diluted		$ (8.63)	$ (8.37)	$ (2.01)
Weighted average common limited partner units outstanding:
Basic		93,745	74,716	52,528
Diluted		93,745	74,716	52,528
[1]	Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.

CONSOLIDATED STATEMENTS OF COMP

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	$ (808,816)	$ (607,088)	$ (90,305)
Other comprehensive income (loss):
Mark-to-market gains during the period		238,875	15,828
Reclassification to net loss of mark-to-market gains used to offset asset impairment expense	(85,768)	(82,324)
Reclassification to net loss of mark-to-market (gains) losses	(86,328)	7,739	(10,216)
Total other comprehensive income (loss)	(172,096)	164,290	5,612
Comprehensive loss attributable to common and preferred limited partners and the general partner	$ (980,912)	$ (442,798)	$ (84,693)

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (DEFICIT) - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income	General Partners' InterestGeneral Class A	Preferred Limited Partners InterestsPreferred Class B	Preferred Limited Partners InterestsPreferred Class C	Preferred Limited Partners InterestsPreferred Class D	Preferred Limited Partners InterestsPreferred Class E	Common Limited Partners' Interests	Class C Common Limited Partner Warrants
Balance at Dec. 31, 2012	$ 862,006	$ 21,569	$ 7,029	$ 96,155				$ 737,253
Balance (units) at Dec. 31, 2012			975,708	3,836,554				43,973,153
Arkoma transaction adjustment	64,020		$ (19)					$ 64,039
Issuance of units	406,641				$ 85,448			$ 320,017	$ 1,176
Issuance of units (units)			392,350		3,749,986			15,259,174	562,497
Net issued and unissued units under incentive plans	12,630							$ 12,630
Net issued and unissued units under incentive plans (units)								215,981
Distributions paid to common and preferred limited partners and the general partner	(124,932)		$ (5,891)	$ (8,018)	$ (2,100)			$ (108,923)
Distribution equivalent rights paid on unissued units under incentive plan	(1,939)							(1,939)
Net income (loss)	(90,305)		3,363	8,402	3,590			(105,660)
Other comprehensive income (loss)	5,612	5,612
Balance at Dec. 31, 2013	1,133,733	27,181	$ 4,482	$ 96,539	$ 86,938			$ 917,417	$ 1,176
Balance (units) at Dec. 31, 2013			1,368,058	3,836,554	3,749,986			59,448,308	562,497
Arkoma transaction adjustment	(12,351)		$ (77)					$ (12,274)
Issuance of units	503,591					$ 77,301		$ 426,290
Issuance of units (units)			451,055			3,200,000		21,860,000
Net issued and unissued units under incentive plans	7,391							$ 7,391
Net issued and unissued units under incentive plans (units)								241,733
Distributions payable	(20,876)		$ (1,378)	$ (8)	$ (737)	$ (1,974)		$ (16,779)
Distributions paid to common and preferred limited partners and the general partner	(218,995)		(15,502)	(9,704)	(9,486)			(184,303)
Distribution equivalent rights paid on unissued units under incentive plan	(2,158)							(2,158)
Conversion of Class B preferred units				$ (94,614)				$ 94,614
Conversion of Class B preferred units (units)				(3,796,900)				3,796,900
Net income (loss)	(607,088)		(1,222)	$ 8,770	8,786	1,711		$ (625,133)
Other comprehensive income (loss)	164,290	164,290
Balance at Dec. 31, 2014	947,537	191,471	$ (13,697)	$ 983	$ 85,501	$ 77,038		$ 605,065	$ 1,176
Balance (units) at Dec. 31, 2014			1,819,113	39,654	3,749,986	3,200,000		85,346,941	562,497
Arkoma transaction adjustment	(44,893)							$ (44,893)
Issuance of units	120,391					$ 20,911	$ 5,845	$ 93,635
Issuance of units (units)			342,332			890,328	256,083	16,303,451
Net issued and unissued units under incentive plans	5,056							$ 5,056
Net issued and unissued units under incentive plans (units)								470,615
Distributions payable	16,546		$ 1,339	$ 8	$ 100	$ (231)	$ (172)	$ 15,502
Distributions paid to common and preferred limited partners and the general partner	(147,795)		(4,779)	(42)	(7,849)	(8,492)	(345)	(126,288)
Distribution equivalent rights paid on unissued units under incentive plan	(558)							(558)
Conversion of Class B preferred units				$ (985)				$ 985
Conversion of Class B preferred units (units)				(39,654)				39,859
Net income (loss)	(808,816)		(16,505)	$ 36	7,650	8,292	491	$ (808,780)
Other comprehensive income (loss)	(172,096)	(172,096)
Balance at Dec. 31, 2015	$ (84,628)	$ 19,375	$ (33,642)		$ 85,402	$ 97,518	$ 5,819	$ (260,276)	$ 1,176
Balance (units) at Dec. 31, 2015			2,161,445		3,749,986	4,090,328	256,083	102,160,866	562,497

CONSOLIDATED STATEMENTS OF CASH

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	$ (808,816)	$ (607,088)	$ (90,305)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	157,978	239,923	139,783
Asset impairment	966,635	573,774	38,014
Gain on derivatives	(226,743)		4,749
Loss on asset sales and disposal	1,181	1,869	987
Non-cash compensation expense	4,944	8,067	12,680
Amortization of deferred financing costs and discount and premium on long-term debt	19,640	9,191	9,560
Changes in operating assets and liabilities:
Accounts receivable, prepaid expenses and other	132,559	(77,476)	(11,958)
Accounts payable and accrued liabilities	(74,574)	54,563	20,422
Net cash provided by operating activities	172,804	202,823	123,932
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(127,138)	(212,728)	(263,886)
Net cash paid for acquisitions	(77,854)	(686,811)	(780,857)
Other	990	3,096	(4,863)
Net cash used in investing activities	(204,002)	(896,443)	(1,049,606)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facilities	661,342	1,393,000	942,000
Repayments under credit facilities	(523,000)	(1,116,000)	(874,425)
Distributions paid to unitholders	(147,795)	(218,995)	(124,932)
Net proceeds from long term debt		170,596	510,396
Net proceeds from issuance of common limited partner units	93,635	426,290	320,017
Net proceeds from issuance of preferred units	6,778	77,301	86,624
Arkoma transaction adjustment	(44,893)	(12,351)	64,020
Deferred financing costs, distribution equivalent rights and other	(28,763)	(12,802)	(19,386)
Net cash provided by financing activities	17,304	707,039	904,314
Net change in cash and cash equivalents	(13,894)	13,419	(21,360)
Cash and cash equivalents, beginning of year	15,247	1,828	23,188
Cash and cash equivalents, end of year	$ 1,353	$ 15,247	$ 1,828

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 Resource Partners, L.P. (the “Partnership”) is a publicly traded (NYSE: ARP) Delaware master-limited partnership (“MLP”) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States. The Partnership sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. On February 27, 2015, the Partnership’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; NYSE: ATLS) distributed 100% of its common units to existing unitholders of its then parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership (NYSE: ATLS) (Atlas Energy and Atlas Energy Group are collectively referred to as “ATLS”). Atlas Energy Group manages the Partnership’s operations and activities through its ownership of the Partnership’s general partner interest. Concurrent with Atlas Energy Group’s unit distribution, Atlas Energy and its midstream ownership interests merged into Targa Resources Corp. (“Targa”; NYSE: TRGP) (the “Atlas Merger”) and ceased trading. At December 31, 2015, Atlas Energy Group owned 100% of the Partnership’s general partner Class A units, all of the incentive distribution rights through which it manages and effectively controls the Partnership and an approximate 23.3% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in the Partnership. In addition to its general and limited partner interest in the Partnership, ATLS also holds general and limited partner interests in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, oil and NGLs, with operations primarily focused in the Eagle Ford Shale, and in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, which incubate new MLPs and invest in existing MLPs. At December 31, 2015, the Partnership had 102,160,866 common limited partner units issued and outstanding. The common units are a class of limited partner interests in the Partnership. The holders of common units are entitled to participate in partnership distributions, exercise the rights or privileges available to holders of common units and have limited liability as outlined in the partnership agreement. The partnership agreement authorizes the issuance of an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by the Partnership’s general partner without the approval of the Partnership’s unitholders, subject to the rights of holders of the Partnership’s Class B, Class D and Class E Preferred Units to approve the creation or issuance of any securities senior to such units. The Partnership will continue as a limited partnership until dissolved under the partnership agreement. The partnership agreement specifies the manner in which the Partnership will make cash distributions to holders of common units and other partnership securities as well as to the general partner in respect of incentive distribution rights (see Note 13). The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require the approval of a majority of the common units. Except as set forth below, the Partnership’s convertible Class B preferred units, or the Class B Preferred Units, Class C Preferred Units, Class D Preferred Units and Class E Preferred Units have no voting rights and have limited liability. The holder of the Partnership’s Class A Units has all voting rights applicable to the general partner and generally has unlimited liability for obligations of the Partnership. The following is a summary of the vote requirements specified for certain matters under the Partnership’s partnership agreement (see partnership agreement for full listing of voting requirements): · Issuance of additional partnership securities – common and preferred unitholders have no approval right · Amendment of partnership agreement – certain amendments may be made by the Partnership’s general partner without approval of common unitholders. Other amendments generally require the approval of a unit majority or, if any amendment could adversely affect their rights, the approval by a majority of the Class B or Class C Preferred Units or the approval by two-thirds of the Class D Preferred Units or Class E Preferred Units · Merger or sale of all or substantially all of the Partnership’s assets – unit majority in certain circumstances · Dissolution of the Partnership - unit majority and the approval by a majority of the Class B and Class C Preferred Units and the approval by two-thirds of the Class D and Class E Preferred Units · Removal of the general partner - not less than two-thirds of the outstanding common units, including common units held by the Partnership’s general partner and its affiliates

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 The Partnership’s consolidated financial statements include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. On June 5, 2015, the Partnership acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (the “Arkoma Acquisition”). Management of the Partnership determined that the Arkoma Acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable Arkoma assets and liabilities based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital (deficit) on the Partnership’s consolidated balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the acquisition of Arkoma assets would have been included in the Partnership’s consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior period consolidated financial statements to furnish comparative information. As such, the Partnership reflected the impact of the Arkoma Acquisition on its consolidated financial statements in the following manner: · Recognized the assets acquired and liabilities assumed from the Arkoma Acquisition at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital (deficit); · Retrospectively adjusted its consolidated financial statements for any date prior to June 5, 2015, the date of acquisition, to reflect its results on a consolidated basis with the results of the Arkoma assets as of or at the beginning of the respective period; and · Adjusted the presentation of the Partnership’s consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 to reflect the results of operations attributable to the Arkoma assets prior to the date of acquisition to determine income attributable to common limited partners. Prior to the Arkoma Acquisition, the common limited partners did not participate in the net income (loss) of the Arkoma assets. Subsequent to the Arkoma Acquisition, the common limited partners participate in the net income (loss) of the Arkoma assets retrospectively, which was determined after the deduction of the general partner’s and the preferred unitholders’ interests. In accordance with the accounting guidance for transactions between entities under common control, the retrospective effect of the restatement of income attributable to common limited partners resulted in a $0.05 and $0.02 decrease in net loss attributable to common limited partners per unit for the years ended December 31, 2014 and 2013. In accordance with established practice in the oil and gas industry, the Partnership’s 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 the Partnership has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics (see “ Property, Plant and Equipment Use of Estimates The preparation of the Partnership’s 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 Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s 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. The oil and 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 Partnership 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, the Partnership completed the semi-annual redetermination of its Credit Facility, reducing the borrowing base from $750 million to $700 million. The Partnership’s next redetermination date is in May 2016. The Partnership’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. The Partnership believes it has sufficient liquidity from (i) its cash flows from operations (including its hedges scheduled to settle in 2016), (ii) availability under the 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, the Partnership 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. The Partnership’s ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the 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 our control. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership’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. The Partnership continues to implement various cost saving measures to reduce our 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. The Partnership 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 the Partnership 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. The Partnership 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, the Partnership 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 the Partnership 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 Partnership 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 consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. The Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness. The Partnership extends credit on sales on an unsecured basis to many of its customers. At December 31, 2015 and 2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets. Inventory The Partnership had $8.0 million and $8.9 million of inventory at December 31, 2015 and 2014, respectively, which was included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. The Partnership values inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method. Subscriptions Receivable The Partnership 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 the Partnership, 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. The Partnership recognizes the contributions associated with the 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 Partnership’s results of operations. The Partnership follows 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 NGLs 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 Partnership’s 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 the Partnership’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by the Partnership 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 Partnership’s consolidated statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Partnership’s 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 Partnership’s 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 Property, Plant and Equipment The Partnership reviews its property, plant and equipment 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 the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published future 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, the Partnership’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 the Partnership’s actual capital contributions, a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. The Partnership’s lower operating and administrative costs result from recognizing its proportionate share of limited partners’ Drilling Partnership external operating expenses. These assumptions could result in the Partnership’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 Partnership cannot predict what reserve revisions may be required in future periods. The Partnership’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 the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership 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 the Partnership 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 the Partnership is governed under the Drilling Partnership’s limited partnership agreement. In general, the Partnership will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon the Partnership’s determination of fair market value. Capitalized Interest The Partnership 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 rate used to capitalize interest on borrowed funds by the Partnership was 6.5%, 5.6% and 6.0% for the years ended December 31, 2015, 2014 and 2013, respectively. The aggregate amount of interest capitalized by the Partnership was $15.8 million, $13.0 million and $14.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. Intangible Assets The Partnership recorded its intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance method over their respective estimated useful lives. The Partnership reviews intangible 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 following table reflects the components of intangible assets being amortized at December 31, 2015 and December 31, 2014 (in thousands): December 31, Estimated 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 Partnership had $13.6 million of goodwill recorded in connection with its prior consummated acquisitions. The Partnership tests goodwill for impairment at each year end by comparing its reporting units’ estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’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 Partnership’s assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s 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 the Partnership’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, the Partnership’s management 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 the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. 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, the Partnership recognized an $18.1 million non-cash impairment charge within asset impairments on its consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in the Partnership’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. The Partnership’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, 2014 and 2015 is attributable to the Partnership’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 The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s 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 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 partners’ capital (deficit) on the Partnership’s consolidated balance sheets and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings. Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 6). The Partnership recognizes a liability for its 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 Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization. Income Taxes The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the consolidated financial statements. The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s 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 Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2015, 2014 and 2013. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015. Unit-Based Compensation The Partnership recognizes all unit-based payments to employees, including grants of employee unit options, in the consolidated financial statements based on their fair values (see Note 14). Net Income (Loss) Per Common Unit Basic net income (loss) attributable to common limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholders’ interests, by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, income (loss) attributable to preferred limited partners and net income (loss) attributable to the general partner’s Class A units. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 13), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests. The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights. Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights would result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): Years Ended December 31, 2015 2014 2013 Net income (loss) $ (808,816 ) $ (607,088 ) $ (90,305 ) Preferred limited part

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions	NOTE 3 – ACQUISITIONS Rangely Acquisition On June 30, 2014, the Partnership 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 the Partnership’s revolving credit facility, the issuance of an additional $100.0 million of its 7.75% senior notes due 2021 (“7.75% Senior Notes”) (see Note 7) and the issuance of 15,525,000 common limited partner units (see Note 12). The Rangely Acquisition had an effective date of April 1, 2014. The Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing. The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $11.6 million of transaction fees, which were included with common limited partners’ interests for the year ended December 31, 2014 on the Partnership’s 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 EP Energy Acquisition On July 31, 2013, the Partnership 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”). The purchase price was funded through borrowings under the Partnership’s revolving credit facility, the issuance of the Partnership’s 9.25% senior notes due August 15, 2021 (“9.25% Senior Notes”) (see Note 7), and the issuance of 14,950,000 common limited partner units and 3,749,986 newly created Class C convertible preferred units (see Note 12). The assets acquired 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 Partnership’s consolidated financial statements reflected the operating results of the acquired business commencing July 31, 2013 with the transaction closing. The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9). In conjunction with the issuance of common limited partner units associated with the acquisition, the Partnership recorded $12.1 million of transaction fees which were included within common limited partners’ interests for the year ended December 31, 2013 on the Partnership’s 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 $ 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, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Rangely and EP Energy acquisitions, including the related borrowings, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2013. The Partnership 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 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 $ 747,655 $ 656,677 Net loss (588,823 ) (21,144 ) Net loss attributable to common limited partners (588,353 ) (26,131 ) Net loss attributable to common limited partners per unit: Basic and Diluted $ (7.28 ) $ (0.32 ) Other Acquisitions: Arkoma Acquisition On June 5, 2015, the Partnership completed the acquisition of ATLS’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”). The Partnership 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. The Partnership accounted for the Arkoma Acquisition as a transaction between entities under common control (see Note 2). Eagle Ford Acquisition On November 5, 2014, the Partnership 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 the Partnership 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, the Partnership, 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 the Partnership issued $20.0 million of its Class D 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 the Partnership paid $0.6 million to satisfy the third installment related to the Eagle Ford Acquisition. On July 8, 2015, AGP sold to the Partnership, for a purchase price of $1.4 million, AGP’s interest in a portion of the acreage AGP acquired in the Eagle Ford Acquisition. In September 2015, the Partnership 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 the Partnership. On October 1, 2015 the Partnership paid $17.5 million to satisfy the fourth installment related to the Eagle Ford Acquisition. On December 31, 2015 the Partnership paid $21.6 million to satisfy the final installment related to the Eagle Ford Acquisition. The Partnership’s issuance of Class D Preferred Units in March 2015 represented a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2015. GeoMet Acquisition On May 12, 2014, the Partnership completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets included coal-bed methane producing natural gas assets in West Virginia and Virginia. Norwood Acquisition On September 20, 2013, the Partnership 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.

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 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 503,586 $ 441,548 Pre-development costs 6,014 7,223 Wells and related equipment 3,076,239 3,026,416 Total proved properties 3,585,839 3,475,187 Unproved properties 213,047 217,321 Support equipment 44,921 37,359 Total natural gas and oil properties 3,843,807 3,729,867 Pipelines, processing and compression facilities 56,738 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 3,929,577 3,807,340 Less – accumulated depreciation, depletion and amortization (2,737,966 ) (1,543,520 ) $ 1,191,611 $ 2,263,820 During the year ended December 31, 2015, the Partnership recognized a $1.2 million loss on asset sales and disposals primarily related to a write-down of pipe, pump units and other inventory in New Albany Shale and Black Warrior that are no longer usable and plugging and abandonment costs for certain wells in the New Albany Shale. During the year ended December 31, 2014, the Partnership recognized $1.9 million of loss on asset disposal, primarily related to the 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 Partnership recognized $1.0 million of loss on asset disposal, primarily pertaining to the 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 Partnership 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, the Partnership recognized $6.6 million of asset impairments related to its unproved gas and oil properties within property, plant and equipment, net on its consolidated balance sheet, primarily for its unproved acreage in the New Albany Shale. During the year ended December 31, 2013, the Partnership recognized $13.5 million of asset impairments related to its unproved gas and oil properties within property, plant and equipment, net on its 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 Partnership for the 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 Partnership’s consolidated statements of operations. For the year ended December 31, 2015, the Partnership recognized $960.0 million of asset impairment related to 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 Partnership recognized $555.7 million of asset impairment related to proved oil and gas properties within property, plant and equipment, net on its consolidated balance sheet for its 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, the Partnership recognized $24.5 million of asset impairments related to its proved gas and oil properties within property, plant and equipment, net on its consolidated balance sheet for its shallow natural gas wells in the New Albany Shale. During the years ended December 31, 2015, 2014 and 2013, the Partnership recognized $22.6 million, $25.0 million and $26.0 million, respectively, of non-cash property, plant and equipment additions, which were included within the changes in accounts payable and accrued liabilities on the Partnership’s 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 $36,582 and $18,622, respectively $ 50,884 $ 40,637 Notes receivable 3,708 3,866 Other 5,452 5,578 $ 60,044 $ 50,081 Deferred financing costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 7). Amortization expense of deferred financing costs was $12.4 million, $8.6 million and $6.4 million for the years ended December 31, 2015, 2014 and 2013, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the year ended December 31, 2015, the Partnership recognized $5.6 million for accelerated amortization of deferred financing costs associated with reductions of the borrowing base under the revolving credit facility. During the year ended December 31, 2014, the Partnership recognized $0.6 million for accelerated amortization of deferred financing costs associated with a reduction of the borrowing base under the revolving credit facility. During the year ended December 31, 2013, the Partnership also recognized $3.2 million for accelerated amortization of deferred financing costs associated with the retirement 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 its 7.75% Senior Notes. At December 31, 2015 and 2014, the Partnership had notes receivable with certain investors of its Drilling Partnerships, which were included within other assets, net on the Partnership’s 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 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, $0.1 million of interest income was recognized within other, net on the Partnership’s consolidated statements of operations. At December 31, 2015 and 2014, the Partnership recorded no allowance for credit losses within its consolidated balance sheets based upon payment history and ongoing credit evaluations associated with the notes receivable.

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 the Partnership’s historical experience in plugging and abandoning wells, the 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 Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets. The Partnership 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 the Partnership’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, the Partnership 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, the Partnership has withheld $5.2 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. The Partnership’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, the Partnership assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, the Partnership’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the Partnership’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, the Partnership will assume the related asset retirement obligations of the limited partners. A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): December 31, 2015 2014 2013 Asset retirement obligations, beginning of period $ 107,950 $ 91,179 $ 64,794 Liabilities incurred 2,070 3,512 6,366 Adjustment to liability due to acquisitions (Note 3) — 6,997 16,728 Liabilities settled (2,591 ) (1,664 ) (1,188 ) Accretion expense 6,311 5,747 4,479 Revisions — 2,179 — Asset retirement obligations, end of period $ 113,740 $ 107,950 $ 91,179 The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations.

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 Revolving credit facility $ 592,000 $ 696,000 Term loan facility 243,783 — 7.75 % Senior Notes – due 2021 374,619 374,544 9.25 % Senior Notes – due 2021 324,080 323,916 Total debt 1,534,482 1,394,460 Less current maturities — — Total long-term debt $ 1,534,482 $ 1,394,460 Credit Facility The Partnership is a party to a Second Amended and Restated Credit Agreement, dated July 31, 2013 (as amended from time to time, (the “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, the Partnership entered into an Eighth Amendment. Among other things, the Eighth Amendment: · reduces the borrowing base under the 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); · suspends compliance with a maximum ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the Credit Agreement) until the four fiscal quarter period ending March 31, 2017 and revises 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 to1.00 for the four quarter period ending March 31, 2018, and 5.00 to 1.00 for each four fiscal quarter period ending thereafter; · replaces 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 Credit Agreement) to EBITDA of 2.75 to1.00; and · resets 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 to1.00 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 Credit Agreement was entered into on July 24, 2015. Among other things, the Seventh Amendment redefined EBITDA. A Sixth Amendment to the Credit Agreement was entered into on February 23, 2015. Among other things, the Sixth Amendment: · reduced the borrowing base under the 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 Credit Agreement) is less than 90%, increased 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 The Partnership’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 Credit Agreement; in July 2015 (the rescheduled redetermination date in the Sixth Amendment to the Credit Agreement), a determination by the lenders reaffirmed the $750.0 million borrowing base in connection with the Seventh Amendment to the Credit Agreement; and in November 2015, the borrowing base was reduced from $750.0 million to $700.0 million in connection with the Eighth Amendment to the Credit Agreement. The Credit Agreement also provides that the Partnership’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 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. The 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. Additionally, obligations under the facility are guaranteed by certain of the Partnership’s material subsidiaries, and any non-guarantor subsidiaries of the Partnership are minor. Borrowings under the credit facility bear interest, at the Partnership’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). The Partnership 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 Partnership’s consolidated statements of operations. At December 31, 2015, the weighted average interest rate on outstanding borrowings under the credit facility was 3.25%. The Credit Agreement contains customary covenants including, without limitation, covenants that limit the Partnership’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, merger or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Credit Agreement also requires the Partnership to 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 Credit Agreement) to current liabilities (as defined in the Credit Agreement) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Partnership was in compliance with these covenants as of December 31, 2015. Based on the definitions contained in the Credit Agreement, at December 31, 2015, the Partnership’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 the Partnership 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, the Partnership 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 determination in May 2016 results in a borrowing base deficiency and the Partnership cannot access the capital markets and repay debt under its credit facility, the Partnership 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. Term Loan Facility On February 23, 2015, the Partnership 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 “Term Loan Facility”). The Term Loan Facility matures on February 23, 2020. The Term Loan Facility is presented net of unamortized discount of $6.2 million at December 31, 2015. The Partnership has the option to prepay the Term Loan Facility at any time, and is required to offer to prepay the 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. The Partnership is also required to offer to prepay the 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. The Partnership’s obligations under the 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 the Partnership’s existing first lien revolving credit facility. In addition, the obligations under the Term Loan Facility are guaranteed by the Partnership’s material restricted subsidiaries. Borrowings under the Term Loan Facility bear interest, at the Partnership’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 Second Lien Credit Agreement contains customary covenants including, without limitation, covenants that limit the Partnership’s ability to make restricted payments, take on indebtedness, issue preferred stock, grant liens, conduct sales of assets and subsidiary stock, make distributions from restricted subsidiaries, conduct affiliate transactions and engage in other business activities. In addition, the Second Lien Credit Agreement contains covenants substantially similar to those in the Partnership’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. The Partnership was in compliance with these covenants as of December 31, 2015. Under the Second Lien Credit Agreement, the Partnership may elect to add one or more incremental term loan tranches to the Term Loan Facility so long as the aggregate outstanding principal amount of the Term Loan Facility plus the principal amount of any incremental term loan does not exceed $300.0 million and certain other conditions are adhered to. Any such incremental term loans may not mature on a date earlier than February 23, 2020. Senior Notes At December 31, 2015, the Partnership had $374.6 million outstanding of its 7.75% senior unsecured notes due 2021 (“7.75% Senior Notes”). The 7.75% Senior Notes were presented net of a $0.4 million unamortized discount as of December 31, 2015. Interest on the 7.75% Senior Notes is payable semi-annually on January 15 and July 15. At any time prior to January 15, 2016, the 7.75% 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% 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, the Partnership may redeem the 7.75% 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% 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 the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, the Partnership must offer to repurchase the 7.75% Senior Notes. On December 29, 2015, the Partnership 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, the Partnership paid a consent fee of $10.00 for each $1,000 in principal amount of the 7.75% 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 the Partnership’s secured credit facilities, from $500.0 million. The use of secured indebtedness incurred under such basket in exchange for the 7.75% Senior Notes or the 9.25% Senior Notes (as defined below) will be limited to a maximum amount of $100 million, and the subsidiaries of the Partnership that issued the 7.75% Senior Notes (the “Issuers”) will be required to make any offer to exchange the 7.75% Senior Notes for secured indebtedness of the Issuers incurred under such basket to all holders of the 7.75% 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% Senior Notes on a pro rata basis. (2) Adding an additional covenant providing that the Partnership 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, the Partnership had $324.1 million outstanding of its 9.25% senior unsecured notes due 2021 (“9.25% Senior Notes”). The 9.25% Senior Notes were presented net of a $0.9 million unamortized discount as of December 31, 2015. Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15. At any time prior to August 15, 2017, the Partnership may redeem the 9.25% 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% Senior Notes Indenture”)), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, the Partnership may redeem some or all of the 9.25% Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 102.313% and on or after August 15, 2019, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 100.0%. Under certain conditions, including if the Partnership sells certain assets and does not reinvest the proceeds or repay senior indebtedness or if it experiences specific kinds of changes of control, the Partnership must offer to repurchase the 9.25% Senior Notes. On December 17, 2015, the Partnership entered into a Fourth Supplemental Indenture to the 9.25% Senior Notes Indenture following the receipt of requisite consents of the holders of the 9.25% 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, the Partnership paid a consent fee of $10.00 for each $1,000 in principal amount of the 9.25% 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 the Partnership’s secured credit facilities, from $500.0 million. The use of secured indebtedness incurred under such basket in exchange for the 7.75% Senior Notes or the 9.25% Senior Notes will be limited to a maximum amount of $100 million. The 7.75% Senior Notes and 9.25% Senior Notes are guaranteed by certain of the Partnership’s material subsidiaries. The guarantees under the 7.75% Senior Notes and 9.25% 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 the Partnership, other than the subsidiary guarantors, are minor. There are no restrictions on the Partnership’s ability to obtain cash or any other distributions of funds from the guarantor subsidiaries. The indentures governing the 7.75% Senior Notes and 9.25% Senior Notes contain covenants including, without limitation, covenants that limit the Partnership’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 the Partnership’s assets. The Partnership was in compliance with these covenants as of December 31, 2015. The aggregate amount of the Partnership’s debt maturities is as follows (in thousands): Years Ended December 31: 2016 $ — 2017 — 2018 592,000 2019 — 2020 250,000 Thereafter 700,000 Total principle maturities 1,542,000 Unamortized premium 309 Unamortized discounts (7,827 ) Total debt $ 1,534,482 Total cash payments for interest by the Partnership were $98.5 million $58.7 million and $17.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments	NOTE 8 – DERIVATIVE INSTRUMENTS The Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity and interest rate price risk management activities. Management enters into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to the New York Mercantile Stock Exchange (“NYMEX”), the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged. On January 1, 2015, the Partnership discontinued 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 Partnership’s 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 partners’ capital (deficit) on the Partnership’s consolidated balance sheet, are being reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions settle. The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s 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 Partnership’s consolidated balance sheets as the initial value of the options. The Partnership recorded net derivative assets of $357.7 million and $274.9 million on its consolidated balance sheets at December 31, 2015 and 2014, respectively. Of the $19.4 million of deferred gains in accumulated other comprehensive income on the Partnership’s consolidated balance sheet at December 31, 2015, the Partnership expects to reclassify $16.7 million of gains to its consolidated statement of operations over the next twelve month period as these contracts expire with the remaining gains of $2.7 million being reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. The following table summarizes the commodity derivative activity and presentation in the Partnership’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) 92,732 Total cash settlements on commodity derivative contracts $ 179,060 Gains recognized prior to settlement (2) 40,480 Gains recognized on open derivative contracts, net of amounts recognized in income in prior year (2) 226,743 Gains on mark-to-market derivatives $ 267,223 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives. The Partnership reclassified from accumulated other comprehensive income losses of $7.7 million and gains of $10.2 million for the years ended December 31, 2014 and 2013, respectively, on settled contracts covering commodity production. These gains and loss were included within gas and oil production revenue in the Partnership’s consolidated statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2014 and 2013 for hedge ineffectiveness. The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on the Partnership’s consolidated balance sheets for the periods indicated (in thousands): Offsetting Derivatives as of December 31, 2015 Gross Recognized Gross Net Amount Presented 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 $ — The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity prices. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index, while ethane, propane, butane and iso butane contracts are priced based on the respective Mt. Belvieu price. These contracts were recorded at their fair values. At December 31, 2014, the Partnership had net cash proceeds of $0.2 million, related to its hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s combined consolidated balance sheet. The Partnership 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, the Partnership entered into contracts which provided the option to enter into swap contracts for future production periods (“swaptions”) up through September 30, 2013 for production volumes related to assets acquired from EP Energy (see Note 3). In connection with the swaption contracts, the Partnership paid premiums of $14.5 million, which represented their fair value on the date the transactions were initiated and were initially recorded as derivative assets on the Partnership’s consolidated balance sheet and was 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, the Partnership recognized $14.5 million, of amortization expense in other, net on the Partnership’s consolidated statement of operations related to the swaption contracts. At December 31, 2015, the Partnership had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Volumes Average Fair Value (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 Option Type Volumes Average Fair Value (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 Volumes Average Fair Value (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 Volumes Average Fair Value (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 Total 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, the Partnership 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, the Partnership 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), the Partnership 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. The Partnership, 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 Partnership’s 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 Management has established a hierarchy to measure the Partnership’s financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value: Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability. Level 3 Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 8). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices’ quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument. Information for assets and liabilities measured at fair value at December 31, 2015 and 2014 was as follows (in thousands): As of December 31, 2015 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 355,329 $ — $ 355,329 Commodity puts — 2,393 — 2,393 Total derivative assets, gross — 357,722 — 357,722 Derivative liabilities, gross Commodity swaps — — — — Commodity options — — — — Total derivative liabilities, gross — — — — Total derivatives, fair value, net $ — $ 357,722 $ — $ 357,722 As of December 31, 2014 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 267,242 $ — $ 267,242 Commodity puts — 2,767 — 2,767 Commodity options — 5,320 — 5,320 Total derivative assets, gross — 275,329 — 275,329 Derivative liabilities, gross Commodity swaps — (401 ) — (401 ) Commodity options — (67 ) — (67 ) Total derivative liabilities, gross — (468 ) — (468 ) Total derivatives, fair value, net $ — $ 274,861 $ — $ 274,861 Other Financial Instruments The estimated fair value of the Partnership’s other financial instruments has been determined based upon its assessment of available market information and valuation methodologies. However, these estimates may not necessarily be indicative of the amounts that the Partnership could realize upon the sale or refinancing of such financial instruments. The Partnership’s other current assets and liabilities on its 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 Partnership’s long-term debt at December 31, 2015 and 2014, which consist of its Senior Notes and outstanding borrowings under its revolving credit and term loan facilities (see Note 7), were $907.8 million and $1,219.8 million, respectively, compared with the carrying amounts of $1,534.5 million and $1,394.5 million, respectively. At December 31, 2015 and 2014, the carrying values of outstanding borrowings under the Partnership’s revolving credit facility (see Note 7), which bears interest at variable interest rates, approximated estimated fair values. The estimated fair values of the Partnership’s Senior Notes and the term loan credit facility were based upon the market approach and calculated using yields of the Partnership Senior Notes and the term loan credit 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 Management estimates the fair value of the Partnership’s asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements, the credit-adjusted risk-free rate of the Partnership and estimated inflation rates. Information for asset retirement obligations that were measured at fair value on a nonrecurring basis for the years ended December 31, 2015 and 2014 were as follows (in thousands): Years Ended December 31, 2015 2014 Level 3 Level 3 Asset retirement obligations $ 2,070 $ 10,509 Total $ 2,070 $ 10,509 Management estimates the fair value of the Partnership’s 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, the Partnership completed the Eagle Ford, Rangely and GeoMet acquisitions (see Note 3). During the year ended December 31, 2013, the Partnership 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 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 Partnership’s existing methodology for recognizing an estimated liability for the plugging and abandonment of its gas and oil wells (see Note 6). These inputs required significant judgments and estimates by the Partnership’s 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 ATLS . The Partnership does not directly employ any persons to manage or operate its business. These functions are provided by employees of ATLS and/or its affiliates. As of December 31, 2015 and 2014, the Partnership had a $1.3 payable and an $8.8 million payable, respectively, to ATLS related to the timing of funding cash accounts, which is recorded in advances from affiliates in the consolidated balance sheets. Relationship with Drilling Partnerships. The Partnership conducts certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. The Partnership serves as general partner and operator of the Drilling Partnerships and assumes customary rights and obligations for the Drilling Partnerships. As the general partner, the Partnership 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. The Partnership 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 . In connection with the Eagle Ford Acquisition (see Note 3), the Partnership guaranteed the timely payment of the deferred portion of the purchase price that was to be paid by AGP. On September 21, 2015, the Partnership and AGP, in accordance with the terms of the Eagle Ford shared acquisition and operating agreement, agreed that the Partnership would fund the remaining two deferred purchase price installments (see Note 3). In conjunction with this agreement, AGP assigned the Partnership a portion of its non-operating Eagle Ford assets that had a value (as such value was agreed upon by the sellers and the buyers in connection with the Eagle Ford Acquisition) equal to both installments to be paid by the Partnership. As of December 31, 2015 and 2014, the Partnership had an $8.7 million payable and a $6.6 million receivable, respectively, to/from AGP related to the timing of funding cash accounts, which is recorded in advances to/from affiliates in the consolidated balance sheets.

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 Partnership leases office space and equipment under leases with varying expiration dates. Rental expense was $15.7 million, $17.0 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 The Partnership 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. The Partnership 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, the Partnership 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 the Partnership 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 the Partnership 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 the Partnership 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, the Partnership 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 from 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. The Partnership 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, the Partnership 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 the Partnership 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, the Partnership 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 the Partnership’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), the Partnership guaranteed the timely payment of the deferred portion of the purchase price that was to be paid by AGP. The Partnership’s deferred purchase obligation was included within accrued liabilities on the Partnership’s consolidated balance sheets at December 31, 2014. In connection with the Eagle Ford Acquisition, the Partnership acquired certain gathering obligations. Estimated fixed and determinable portions of the Partnership’s gathering obligations as of December 31, 2015 were as follows: 2016— $0.4 million; 2017 to 2020— none. In connection with the GeoMet Acquisition (see Note 3), the Partnership acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of the Partnership’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 the Partnership’s acquisition of assets from EP Energy E&P Company, L.P. on July 31, 2013 (the “EP Energy Acquisition”), the Partnership acquired certain long-term annual firm transportation obligations. Estimated fixed and determinable portions of the Partnership’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 Partnership is committed to expend approximately $7.1 million, principally on drilling and completion expenditures. Legal Proceedings The Partnership is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

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 In August 2015, the Partnership entered into a distribution agreement with MLV & Co. LLC (“MLV”) which the Partnership terminated and replaced in November 2015, when the Partnership 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, the Partnership may sell from time to time to or through the Agents the Partnership’s 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D Preferred Units”) and Class E Cumulative Redeemable Perpetual Preferred Units (“Class E Preferred Units”) and together with the Class D Preferred Units, the “Preferred Units”) having an aggregate offering price of up to $100 million. Sales of 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 Preferred Units. Under the terms of the distribution agreement, the Partnership may sell 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 Preferred Units or Class E Preferred Units, as applicable, on the date of sale. Upon the sale of Preferred Units to an Agent as principal, the Partnership and such Agent will enter into separate terms agreement with respect to such sale. The Preferred Units may also be offered by the Sales Agent as agents for the Partnership at negotiated prices or prevailing market prices at the time of sale. The Partnership 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 Preferred Units sold through the Agent as agent for the Partnership. Under the August 2015 ATM Agreement, the Partnership issued 90,328 Class D Preferred Units and 1,083 Class E Preferred Units for net proceeds of $0.9 million, net of $0.3 million in commissions and offering expenses paid. Under the November 2015 ATM Agreement, the Partnership did not issue any Class D Preferred Units nor Class E 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 Preferred Units were converted into common limited partner units. In May 2015, in connection with the Arkoma Acquisition (see Note 3), the Partnership 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. The Partnership used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under the Partnership’s revolving credit facility. In April 2015, the Partnership issued 255,000 of its Class E Preferred Units at a public offering price of $25.00 per unit for net proceeds of approximately $6.0 million. The Partnership 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, the Partnership issued 3,200,000 8.625% Class D Preferred Units at a public offering price of $25.00 per Class D Preferred Unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. The Partnership 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, the Partnership issued an additional 800,000 Class D Preferred Units to the seller at a value of $25.00 per unit. On January 15, 2015, the Partnership paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 13). The Partnership pays distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the $25.00 liquidation preference. The Class D and Class E Preferred Units rank senior to the Partnership’s common units and Class C Preferred Units with respect to the payment of distributions and distributions upon a liquidation event. The Class D and Class E 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 the Partnership 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 Preferred Units and April 15, 2020 for the Class E Preferred Units, the Partnership 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, the Partnership may redeem such preferred units following certain changes of control, as described in the respective Certificates of Designation. If the Partnership 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 Partnership common units as set forth in the respective Certificates of Designation. If the Partnership exercises any of its redemption rights relating to the preferred units, the holders of such preferred units will not have the conversion right described above with respect to the preferred units called for redemption. Additionally, if at any time the Partnership’s general partner and its affiliates own more than two-thirds of the outstanding class of any limited partner interests, the Partnership’s general partner will have the right, which it may assign to any of its affiliates or to the Partnership, to acquire all, but not less than all, of such class of limited partner interests held by at a price equal to the greater of (1) the highest cash price paid by the Partnership’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 the Partnership’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, the Partnership 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, the Partnership may sell from time to time through the Agents common units representing limited partner interests of the Partnership having an aggregate offering price of up to $100.0 million. Sales of common units 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. The Partnership 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, the Partnership 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 the Partnership and such Agent. During the year ended December 31, 2015, the Partnership 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), the Partnership 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), the Partnership 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), the Partnership issued 3,749,986 of its newly created Class C convertible preferred units to ATLS, 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(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, ATLS, as purchaser of the Class C preferred units, received 562,497 warrants to purchase the Partnership’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 the Partnership 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, the Partnership 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. The Partnership 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 entering the EP Energy Acquisition (see Note 3), the Partnership 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. The Partnership utilized the net proceeds from the sale to repay the outstanding balance under its revolving credit facility (see Note 7). In May 2013, the Partnership entered into an equity distribution agreement with Deutsche Bank Securities Inc., as representative of several banks. Pursuant to the equity distribution agreement, the Partnership 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, the Partnership 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 other offering costs paid. The Partnership utilized the net proceeds from the sale to repay borrowings outstanding under its revolving credit facility. The Partnership terminated this equity distribution agreement effective December 27, 2013.

Cash Distributions

Cash Distributions	12 Months Ended
	Dec. 31, 2015
Distributions Made To Members Or Limited Partners [Abstract]
Cash Distributions	NOTE 13 – CASH DISTRIBUTIONS In January 2014, the Partnership’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 the partnership agreement) for that month to its unitholders within 45 days from the month end. Prior to that, the Partnership paid quarterly cash distributions within 45 days from the end of each calendar quarter. If the Partnership’s common unit distributions in any quarter exceed specified target levels, ATLS will receive between 13% and 48% of such distributions in excess of the specified target levels. While outstanding, the Class B 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 Preferred Units will receive regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. The Partnership pays quarterly distributions on the Class D 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. The Partnership pays quarterly distributions on the Class E 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 the Partnership for the period from January 1, 2013 through December 31, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Cash Total Cash Total Cash Total Cash 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) Includes payments for the Class B and Class C preferred unit monthly distributions. (2) 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. Date Cash Distribution Paid For the Period Cash Total Cash January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.616927 $ 1,974 April 15, 2015 January 15, 2015 – April 14, 2015 $ 0.539063 $ 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 Total Cash 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 Plan

Benefit Plan	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Benefit Plan	NOTE 14 — BENEFIT PLAN 2012 Long-Term Incentive Plan The Partnership’s 2012 Long-Term Incentive Plan (“2012 LTIP”), effective March 2012, provides incentive awards to officers, employees and directors and employees of the general partner and its affiliates, consultants and joint venture partners (collectively, the “Participants”), who perform services for the Partnership. The 2012 LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “LTIP Committee”). Under the 2012 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 2,900,000 common limited partner units. At December 31, 2015, the Partnership had 1,656,630 phantom units, restricted units and restricted options outstanding under the 2012 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 2012 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2012 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, but subject to the terms of any award agreements and employment agreements to which the 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 the 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 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 LTIP Committee deems necessary or appropriate. 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 LTIP Committee, which may include vesting restrictions. In tandem with phantom unit grants, the 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 the Partnership with respect to a common unit during the period that the underlying phantom unit is outstanding. Phantom units granted under the 2012 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 2012 LTIP at December 31, 2015, 159,996 units will vest within the following twelve months. All phantom units outstanding under the 2012 LTIP at December 31, 2015 include DERs. During the years ended December 31, 2015, 2014 and 2013, the Partnership paid $0.7 million, $2.0 million and $1.9 million, respectively, with respect to the 2012 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital (deficit) on the Partnership’s consolidated balance sheets. The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted 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 Partnership’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, the Partnership had approximately $1.8 million in unrecognized compensation expense related to unvested phantom units outstanding under the 2012 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 1.5 years. Unit Options A unit option is the right to purchase a Partnership common unit in the future at a predetermined price (the exercise price). The exercise price of each option is determined by the LTIP Committee and may be equal to or greater than the fair market value of a common unit on the date the option is granted. The LTIP Committee will determine the vesting and exercise restrictions applicable to an 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 2012 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 2012 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 2012 LTIP unit option activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted 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, the Partnership had approximately $44,000 in unrecognized compensation expense related to unvested unit options outstanding under the 2012 LTIP based upon the fair value of the awards, which is expected to be recognized over a weighted average period of 0.4 years. The Partnership 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 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 in 2015, 2014 and 2013.

Operating Segment Information

Operating Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Operating Segment Information	NOTE 15 – OPERATING SEGMENT INFORMATION The Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 2013 Gas and oil production: Revenues $ 624,222 $ 472,870 $ 273,604 Operating costs and expenses (169,653 ) (182,226 ) (100,098 ) Depreciation, depletion and amortization expense (145,161 ) (229,482 ) (132,727 ) Asset impairment (966,635 ) (573,774 ) (38,014 ) Segment income (loss) $ (657,227 ) $ (512,612 ) $ 2,765 Well construction and completion: Revenues $ 76,505 $ 173,564 $ 167,883 Operating costs and expenses (66,526 ) (150,925 ) (145,985 ) Segment income $ 9,979 $ 22,639 $ 21,898 Other partnership management: (1) Revenues $ 39,306 $ 55,220 $ 32,989 Operating costs and expenses (18,775 ) (25,532 ) (27,527 ) Depreciation, depletion and amortization expense (12,817 ) (10,441 ) (7,056 ) Segment income (loss) $ 7,714 $ 19,247 $ (1,594 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ (657,227 ) $ (512,612 ) $ 2,765 Well construction and completion 9,979 22,639 21,898 Other partnership management 7,714 19,247 (1,594 ) Total segment income (loss) (639,534 ) (470,726 ) 23,069 General and administrative expenses (2) (65,968 ) (72,349 ) (78,063 ) Interest expense (2) (102,133 ) (62,144 ) (34,324 ) Loss on asset sales and disposal (2) (1,181 ) (1,869 ) (987 ) Net loss $ (808,816 ) $ (607,088 ) $ (90,305 ) Reconciliation of segment revenues to total revenues: Segment revenues: Gas and oil production (3) $ 624,222 $ 472,870 $ 273,604 Well construction and completion 76,505 173,564 167,883 Other partnership management 39,306 55,220 32,989 Total revenues $ 740,033 $ 701,654 $ 474,476 Capital expenditures: Gas and oil production $ 111,329 $ 193,131 $ 238,291 Other partnership management 14,050 14,202 17,032 Corporate and other 1,759 5,395 8,563 Total capital expenditures $ 127,138 $ 212,728 $ 263,886 December 31, 2015 2014 Balance sheet: Goodwill: Gas and oil production $ — $ — Well construction and completion 6,389 6,389 Other partnership management 7,250 7,250 $ 13,639 $ 13,639 Total assets: Gas and oil production $ 1,551,450 $ 2,601,171 Well construction and completion 27,039 39,558 Other partnership management 66,641 65,896 Corporate and other 85,874 91,495 $ 1,731,004 $ 2,798,120 (1) Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. (2) Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. (3) Gas and oil production segment revenues include gains on mark to market derivatives.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	NOTE 16 — SUBSEQUENT EVENTS Senior Note Repurchases . In January and February 2016, the Partnership executed transactions to repurchase portions of its senior unsecured notes. Through the end of February 2016, the Partnership 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 for approximately $5.5 million. As a result of these transactions, the Partnership 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, the Partnership declared a monthly distribution of $0.0125 per common unit for the month of December 31, 2015. The $2.0 million distribution, including $39,000 and $0.6 million to the general partner as holder of limited partner and Class C preferred 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, the Partnership declared a monthly distribution of $0.0125 per common unit for the month of January 31, 2016. The $2.0 million distribution, including $39,000 and $0.6 million to the general partner as holder of limited partner and Class C preferred units, respectively, will be paid on March 16, 2016 to unitholders of record at the close of business on March 9, 2016. On January 15, 2016, the Partnership 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, the Partnership 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, 2016. NYSE Compliance . On January 12, 2016, the Partnership 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 Partnership 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.

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 and Gas Reserve Information. The preparation of the Partnership’s natural gas, oil and NGL reserve estimates was completed in accordance with its prescribed internal control procedures by its reserve engineers. The reserve information included below was derived from the reserve reports prepared for the Partnership’s annual Form 10-K for the years ended December 31, 2015, 2014 and 2013. Other than for the Partnership’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 related to the Partnership. The reserve information for the Partnership 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 the Partnership’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. The Partnership’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 its 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 Partnership’s senior engineering staff and management, with final approval by the President. The reserve disclosures that follow reflect 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, gas and NGL reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil, gas and NGL 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 the Partnership 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) 493,232,119 1,942 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 (59,841,724 ) (485,226 ) (1,267,590 ) Balance, December 31, 2013 1,003,538,038 14,988,802 18,957,016 Extensions, discoveries and other additions (1) 58,454,544 3,372,177 3,986,986 Sales of reserves in-place (169,035 ) (1,519 ) (11,326 ) Purchase of reserves in-place (2) 82,279,988 36,538,935 3,567,531 Transfers to limited partnerships (4,887,095 ) (684,613 ) (665,486 ) Revisions (3) 3,805,952 (4,941,359 ) (2,689,379 ) Production (86,637,612 ) (1,254,247 ) (1,387,865 ) Balance, December 31, 2014 1,056,384,780 48,018,176 21,757,477 Extensions, discoveries and other additions (1) 6,441,969 2,492,424 218,726 Sales of reserves in-place (2,713,428 ) (2,393 ) — Purchase of reserves in-place (2) 3,555,062 8,645,686 653,416 Transfers to limited partnerships (2,958,882 ) (481,771 ) (342,156 ) Revisions (3) (377,067,441 ) (11,992,308 ) (13,382,104 ) Production (79,063,564 ) (1,875,654 ) (1,055,345 ) Balance, December 31, 2015 604,578,496 44,804,160 7,850,014 Proved developed reserves at: January 1, 2013 338,655,325 3,400,447 7,884,778 December 31, 2013 766,630,929 3,459,238 7,676,389 December 31, 2014 887,818,577 30,537,868 12,004,774 December 31, 2015 567,992,268 25,484,491 6,334,327 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 168,566,203 17,480,308 9,752,703 December 31, 2015 36,586,228 19,319,669 1,515,687 (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 the Rangely, Eagle Ford and Geomet Acquisitions. For the year ended December 31, 2013, the increase was primarily due to the addition of Marble Falls wells. (2) Represents purchase of proved reserves in the Rangely, Eagle Ford and GeoMet Acquisitions for the year ended December 31, 2014. (3) The downward revisions for the year ended December 31, 2015 were primarily due to unfavorable economic conditions primarily related to gas and oil commodity prices. For the year ended December 31, 2014, the downward revision on oil and NGL was primarily due to production underperforming previous year’s forecasts. The upward revision for the year ended December 31, 2014 on gas was primarily due to production outperforming previous year’s forecast. The downward revisions for the year ended December 31, 2013 were primarily due to a reduction of the Partnership’s five year drilling plans in the Barnett Shale and pricing scenario revisions. Capitalized Costs Related to Oil and Gas Producing Activities The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 Natural gas and oil properties: Proved properties $ 3,585,839 $ 3,475,186 Unproved properties 213,047 217,322 Support equipment 44,921 37,359 3,843,807 3,729,867 Accumulated depreciation, depletion and (2,691,692 ) (1,509,509 ) Net capitalized costs $ 1,152,115 $ 2,220,358 Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 356,999 $ 470,051 $ 273,604 Production costs (169,653 ) (182,226 ) (100,098 ) Depletion (145,161 ) (229,482 ) (132,727 ) Asset impairment (1) (966,635 ) (573,774 ) (38,014 ) $ (924,450 ) $ (515,431 ) $ 2,765 (1) During the year ended December 31, 2015, the Partnership recognized $966.6 million of asset impairment primarily related to 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 Partnership recognized $573.8 million of asset impairment primarily consisting of $555.7 million related to oil and gas properties within property, plant, and equipment, net on its consolidated balance sheet for its 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 of goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, the Partnership 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 the Partnership in its 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 $ 11,513 $ 699,451 $ 859,827 Unproved properties 43,820 10,978 895 Exploration costs (1) 1,601 722 1,053 Development costs 73,288 164,853 214,383 Total costs incurred in oil & gas producing activities $ 130,222 $ 876,004 $ 1,076,158 (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 the Partnership’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 includes 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 $ 3,514,198 $ 9,317,915 $ 5,259,688 Future production costs (1,836,779 ) (4,188,364 ) (2,393,814 ) Future development costs (1,156,367 ) (1,157,305 ) (752,349 ) Future net cash flows 521,052 3,972,246 2,113,525 Less 10% annual discount for estimated timing of cash flows (18,283 ) (1,987,975 ) (1,037,343 ) Standardized measure of discounted future net cash flows $ 502,769 $ 1,984,271 $ 1,076,182 Change in Standardized Discounted 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 the Partnership allocates taxable income to its owner, no recognition has been given to income taxes: Years Ended December 31, 2015 2014 2013 Balance, beginning of year $ 1,984,271 $ 1,076,182 $ 623,676 Increase (decrease) in discounted future net cash flows: Sales of oil and gas produced, net of related costs (1) (129,352 ) (272,961 ) (171,300 ) Net changes in prices and production costs (2) (1,453,854 ) 339,718 85,191 Revisions of previous quantity estimates (52,775 ) 4,352 (1,880 ) Development costs incurred 58,117 52,077 27,245 Changes in future development costs (152,305 ) (90,887 ) (21,579 ) Transfers to limited partnerships (13,291 ) (2,966 ) (53,392 ) Extensions, discoveries, and improved recovery less related costs 13,980 60,832 143,338 Purchases of reserves in-place (3) 53,102 737,101 513,744 Sales of reserves in-place (2,162 ) (332 ) (2,053 ) Accretion of discount 198,427 107,618 62,368 Estimated settlement of asset retirement obligations (216 ) (16,708 ) (18,823 ) Estimated proceeds on disposals of well equipment (1,173 ) (21,906 ) 17,039 Changes in production rates (timing) and other — 12,151 (127,392 ) Outstanding, end of year $ 502,769 $ 1,984,271 $ 1,076,182 (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 the Rangely, Eagle Ford and 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)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Results	NOTE 18 — QUARTERLY RESULTS (Unaudited) Fourth (1)(2) Third (1)(2) Second (1) First (1) (in thousands, except unit data) Year ended December 31, 2015: Revenues $ 142,424 $ 257,895 $ 96,125 $ 243,589 Net loss attributable to common limited partners and the general partner’s interests (2) $ (293,013 ) $ (565,147 ) $ (51,044 ) $ 83,919 Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (287,153 ) $ (553,844 ) $ (50,023 ) $ 82,240 General partner’s interest (5,860 ) (11,303 ) (1,021 ) 1,679 Net loss attributable to common limited partners and the general partner’s interests $ (293,013 ) (565,147 ) $ (51,044 ) $ 83,919 Net loss attributable to common unitholders per unit: Basic $ (2.81 ) $ (5.73 ) $ (0.55 ) $ 0.95 Diluted $ (2.81 ) $ (5.73 ) $ (0.55 ) $ 0.93 (1) For the second, third, and fourth quarters of the year ended December 31, 2015, approximately 469,000, 346,000 and 309,000 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. For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. (2) Includes asset impairment charges of $672.2 million and $294.4 million in the third and fourth quarters of 2015, respectively. Fourth (1) (2) Third (1) Second (1) First (1) (in thousands, except unit data) Year ended December 31, 2014: Revenues $ 194,701 $ 206,699 $ 138,897 $ 161,357 Net loss attributable to common limited partners and the general partner’s interests (2) $ (585,499 ) $ (2,590 ) $ (23,803 ) $ (14,463 ) Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (576,850 ) $ (5,599 ) $ (26,203 ) $ (16,481 ) General partner’s interest (8,649 ) 3,009 2,400 2,018 Net loss attributable to common limited partners and the general partner’s interests $ (585,499 ) (2,590 ) $ (23,803 ) $ (14,463 ) Net loss attributable to common unitholders per unit: Basic $ (7.04 ) $ (0.07 ) $ (0.35 ) $ (0.27 ) Diluted $ (7.04 ) $ (0.07 ) $ (0.35 ) $ (0.27 ) (1) For the first, second, third, and fourth quarters of the year ended December 31, 2014, approximately 820,000, 724,000, 797,000, and 791,000 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. For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. (2) Includes an asset impairment charge of $573.8 million in the fourth quarter of 2014.

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation The Partnership’s consolidated financial statements include the accounts of the Partnership and its wholly-owned subsidiaries. Transactions between the Partnership and other ATLS operations have been identified in the consolidated financial statements as transactions between affiliates, where applicable. All material intercompany transactions have been eliminated. On June 5, 2015, the Partnership acquired coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma from ATLS (the “Arkoma Acquisition”). Management of the Partnership determined that the Arkoma Acquisition constituted a transaction between entities under common control. In comparison to the acquisition method of accounting, whereby the purchase price for the asset acquisition would have been allocated to identifiable Arkoma assets and liabilities based upon their fair values with any excess treated as goodwill, transfers between entities under common control require that assets and liabilities be recognized by the acquirer at historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital (deficit) on the Partnership’s consolidated balance sheets. Also, in comparison to the acquisition method of accounting, whereby the results of operations and the financial position of the acquisition of Arkoma assets would have been included in the Partnership’s consolidated financial statements from the date of acquisition, transfers between entities under common control require the acquirer to reflect the effect to the assets acquired and liabilities assumed and the related results of operations at the beginning of the period during which it was acquired and retrospectively adjust its prior period consolidated financial statements to furnish comparative information. As such, the Partnership reflected the impact of the Arkoma Acquisition on its consolidated financial statements in the following manner: · Recognized the assets acquired and liabilities assumed from the Arkoma Acquisition at their historical carrying value at the date of transfer, with any difference between the purchase price and the net book value of the assets recognized as an adjustment to partners’ capital (deficit); · Retrospectively adjusted its consolidated financial statements for any date prior to June 5, 2015, the date of acquisition, to reflect its results on a consolidated basis with the results of the Arkoma assets as of or at the beginning of the respective period; and · Adjusted the presentation of the Partnership’s consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 to reflect the results of operations attributable to the Arkoma assets prior to the date of acquisition to determine income attributable to common limited partners. Prior to the Arkoma Acquisition, the common limited partners did not participate in the net income (loss) of the Arkoma assets. Subsequent to the Arkoma Acquisition, the common limited partners participate in the net income (loss) of the Arkoma assets retrospectively, which was determined after the deduction of the general partner’s and the preferred unitholders’ interests. In accordance with the accounting guidance for transactions between entities under common control, the retrospective effect of the restatement of income attributable to common limited partners resulted in a $0.05 and $0.02 decrease in net loss attributable to common limited partners per unit for the years ended December 31, 2014 and 2013. In accordance with established practice in the oil and gas industry, the Partnership’s 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 the Partnership has an interest. Such interests generally approximate 30%. The Partnership’s consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships. Rather, the Partnership calculates these items specific to its own economics (see “ Property, Plant and Equipment
Use of Estimates	Use of Estimates The preparation of the Partnership’s 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 Partnership’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s 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. The oil and 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 Partnership 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, the Partnership completed the semi-annual redetermination of its Credit Facility, reducing the borrowing base from $750 million to $700 million. The Partnership’s next redetermination date is in May 2016. The Partnership’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. The Partnership believes it has sufficient liquidity from (i) its cash flows from operations (including its hedges scheduled to settle in 2016), (ii) availability under the 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, the Partnership 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. The Partnership’s ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the 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 our control. The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership’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. The Partnership continues to implement various cost saving measures to reduce our 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. The Partnership 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 the Partnership 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. The Partnership 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, the Partnership 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 the Partnership 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 Partnership 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 consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. The Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers’ current creditworthiness. The Partnership extends credit on sales on an unsecured basis to many of its customers. At December 31, 2015 and 2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.
Inventory	Inventory The Partnership had $8.0 million and $8.9 million of inventory at December 31, 2015 and 2014, respectively, which was included within prepaid expenses and other current assets on the Partnership’s consolidated balance sheets. The Partnership values inventories at the lower of cost or market. The Partnership’s inventories, which consist of materials, pipes, supplies and other inventories, were principally determined using the average cost method.
Subscriptions Receivable	Subscriptions Receivable The Partnership 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 the Partnership, 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. The Partnership recognizes the contributions associated with the 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 Partnership’s results of operations. The Partnership follows 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 NGLs 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 Partnership’s 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 the Partnership’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by the Partnership 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 Partnership’s consolidated statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its consolidated balance sheets. Upon the Partnership’s 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 Partnership’s 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 Property, Plant and Equipment	Impairment of Property, Plant and Equipment The Partnership reviews its property, plant and equipment 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 the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published future 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, the Partnership’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 the Partnership’s actual capital contributions, a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs. The Partnership’s lower operating and administrative costs result from recognizing its proportionate share of limited partners’ Drilling Partnership external operating expenses. These assumptions could result in the Partnership’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 Partnership cannot predict what reserve revisions may be required in future periods. The Partnership’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 the Partnership sponsors and owns an interest in but does not control. The Partnership’s reserve quantities include reserves in excess of its proportionate share of reserves in Drilling Partnerships, which the Partnership may be unable to recover due to the Drilling Partnerships’ legal structure. The Partnership 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 the Partnership 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 the Partnership is governed under the Drilling Partnership’s limited partnership agreement. In general, the Partnership will seek consent from the Drilling Partnership’s limited partners to acquire the well interests from the Drilling Partnership based upon the Partnership’s determination of fair market value.
Capitalized Interest	Capitalized Interest The Partnership 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 rate used to capitalize interest on borrowed funds by the Partnership was 6.5%, 5.6% and 6.0% for the years ended December 31, 2015, 2014 and 2013, respectively. The aggregate amount of interest capitalized by the Partnership was $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 The Partnership recorded its intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. The Partnership amortizes contracts acquired on a declining balance method over their respective estimated useful lives. The Partnership reviews intangible 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 following table reflects the components of intangible assets being amortized at December 31, 2015 and December 31, 2014 (in thousands): December 31, Estimated 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 Partnership had $13.6 million of goodwill recorded in connection with its prior consummated acquisitions. The Partnership tests goodwill for impairment at each year end by comparing its reporting units’ estimated fair values to carrying values. Because quoted market prices for the reporting units are not available, the Partnership’s management must apply judgment in determining the estimated fair value of these reporting units. The Partnership’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 Partnership’s assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to the Partnership’s 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 the Partnership’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, the Partnership’s management 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 the Partnership’s industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in the Partnership’s industry to determine whether those valuations appear reasonable in management’s judgment. 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, the Partnership recognized an $18.1 million non-cash impairment charge within asset impairments on its consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in the Partnership’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. The Partnership’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, 2014 and 2015 is attributable to the Partnership’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 The Partnership enters into certain financial contracts to manage its exposure to movement in commodity prices and interest rates (see Note 8). The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s 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 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 partners’ capital (deficit) on the Partnership’s consolidated balance sheets and reclassified to the Partnership’s consolidated statements of operations at the time the originally hedged physical transactions affected earnings.
Asset Retirement Obligations	Asset Retirement Obligations The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 6). The Partnership recognizes a liability for its 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 Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.
Income Taxes	Income Taxes The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the consolidated financial statements. The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s 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 Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. The Partnership has not recognized any potential interest or penalties in its consolidated financial statements for the years ended December 31, 2015, 2014 and 2013. The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015.
Unit-Based Compensation	Unit-Based Compensation The Partnership recognizes all unit-based payments to employees, including grants of employee unit options, in the 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 limited partners per unit is computed by dividing net income (loss) attributable to common limited partners, which is determined after the deduction of the general partner’s and the preferred unitholders’ interests, by the weighted average number of common limited partner units outstanding during the period. Net income (loss) attributable to common limited partners is determined by deducting net income attributable to participating securities, if applicable, income (loss) attributable to preferred limited partners and net income (loss) attributable to the general partner’s Class A units. The general partner’s interest in net income (loss) is calculated on a quarterly basis based upon its Class A units and incentive distributions to be distributed for the quarter (see Note 13), with a priority allocation of net income to the general partner’s incentive distributions, if any, in accordance with the partnership agreement, and the remaining net income (loss) allocated with respect to the general partner’s and limited partners’ ownership interests. The Partnership presents net income (loss) per unit under the two-class method for master limited partnerships, which considers whether the incentive distributions of a master limited partnership represent a participating security. The two-class method considers whether the partnership agreement contains any contractual limitations concerning distributions to the incentive distribution rights that would impact the amount of earnings to allocate to the incentive distribution rights for each reporting period. If distributions are contractually limited to the incentive distribution rights’ share of currently designated available cash for distributions as defined under the partnership agreement, undistributed earnings in excess of available cash should not be allocated to the incentive distribution rights. Under the two-class method, management of the Partnership believes the partnership agreement contractually limits cash distributions to available cash; therefore, undistributed earnings are not allocated to the incentive distribution rights. Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. Phantom unit awards, which consist of common units issuable under the terms of its long-term incentive plan (see Note 14), contain non-forfeitable rights to distribution equivalents of the Partnership. The participation rights would result in a non-contingent transfer of value each time the Partnership declares a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis. The following is a reconciliation of net income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): Years Ended December 31, 2015 2014 2013 Net income (loss) $ (808,816 ) $ (607,088 ) $ (90,305 ) Preferred limited partner dividends (16,469 ) (19,267 ) (11,992 ) Net loss attributable to common limited partners and the general partner (825,285 ) (626,355 ) (102,297 ) Less: General partner’s interest 16,505 1,222 (3,364 ) Net loss attributable to common limited partners (808,780 ) (625,133 ) (105,661 ) Less: Net income attributable to participating securities – phantom units (1) — — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (808,780 ) (625,133 ) (105,661 ) Plus: Convertible preferred limited partner dividends (1) — — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (808,780 ) $ (625,133 ) $ (105,661 ) (1) Net income (loss) attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2015, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 453,000, 783,000 and 900,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the years ended December 31, 2015, 2014 and 2013, distributions on the Partnership’s Class B and Class C convertible preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive. 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, convertible preferred units and warrants, 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 Partnership’s long-term incentive plan (see Note 14). The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): Years Ended December 31, 2015 2014 2015 Weighted average number of common limited partner units—basic 93,745 74,716 52,528 Add effect of dilutive incentive awards (1) — — — Add effect of dilutive convertible preferred limited partner units (2) — — — Weighted average number of common limited partner units—diluted 93,745 74,716 52,528 (1) For the years ended December 31, 2015, 2014 and 2013, approximately 453,000 units, 783,000 units and 900,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the years ended December 31, 2015, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the years ended December 31, 2015, 2014 and 2013, potential common limited partner units issuable upon (a) conversion of the Partnership’s Class C preferred units and (b) exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As the Class D and Class E preferred units are convertible only upon a change of control event, they are not considered dilutive securities for earnings per unit purposes.
Environmental Matters	Environmental Matters The Partnership 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 Partnership’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 Partnership and its subsidiaries maintain insurance which may cover in whole or in part certain environmental expenditures. The Partnership 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 Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its 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 Partnership had $10.3 million and $17.2 million, respectively, in deposits at various banks, of which $8.4 million and $14.9 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 Partnership sells natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2015, the Partnership had four customers within its gas and oil production segment that individually accounted for approximately 21%, 15%, 11% and 11%, respectively, of the Partnership natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, the Partnership had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of the Partnership natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, the Partnership had three customers within its gas and oil production segment that individually accounted for approximately 19%, 11% and 10% of the Partnership’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. The Partnership is subject to the risk of loss on its derivative instruments that it would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Partnership maintains credit policies with regard to its counterparties to minimize its overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of its 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 it 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. The Partnership’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 our revolving credit facility. Subject to the terms of their 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 Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty. Drilling Partnerships. Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by the Partnership is deployed to drill and complete wells included within the partnership. As the Partnership 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 the Partnership 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 Partnership’s consolidated balance sheets. After the Drilling Partnership well is completed and turned in line (i.e. wells that have been drilled, completed, and connected to a gathering system), the Partnership 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, the Partnership is also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which generally approximates 30%. The Partnership recognizes its Drilling Partnership management fees in the following manner: · Well construction and completion. For each well that is drilled by a Drilling Partnership, the Partnership 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 each Drilling Partnership’s 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, the Partnership receives a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which is earned in accordance with each Drilling Partnership’s partnership agreement and recognized at the initiation of the well. Additionally, the Drilling Partnership pays the Partnership 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 the Partnership 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, the Partnership 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 from 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. The Partnership 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, the Partnership 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 the Partnership 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, the Partnership 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. Gathering and processing revenue. Gathering and processing revenue includes gathering fees the Partnership charges to the Drilling Partnership wells for the Partnership’s processing plants in the New Albany and the Chattanooga Shales. Generally, the Partnership charges a gathering fee to the Drilling Partnership wells equivalent to the fees the Partnership remits. In Appalachia, a majority of the Drilling Partnership wells are subject to a gathering agreement, whereby the Partnership remits a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, the Partnership charges the Drilling Partnership wells a 13% gathering fee. As a result, some of the Partnership’s gathering expenses, specifically those in the Appalachian Basin, will generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. The Partnership’s gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs and crude oil 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
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 Partnership’s 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 Partnership 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 Partnership 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 Partnership 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 Partnership adopted the updated accounting guidance effective January 1, 2016 and does not expect it to have a material impact on its 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 Partnership adopted this accounting guidance upon its effective date of January 1, 2016, which will result a reclassification of unamortized deferred financing costs of $31.1 million from other assets to long-term debt on its 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 Partnership adopted this accounting guidance upon its effective date of January 1, 2016, and does not expect it to have a material impact on its 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 Partnership adopted this accounting guidance upon its effective date of January 1, 2016, and does not except it to have a material impact on its 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 Partnership adopted this accounting guidance upon its effective date of January 1, 2016, and will provide enhanced disclosures, as applicable, within its 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 Partnership 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 December 31, 2014 (in thousands): December 31, Estimated 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 income (loss) allocated to the common limited partners for purposes of calculating net income (loss) attributable to common limited partners per unit (in thousands, except unit data): Years Ended December 31, 2015 2014 2013 Net income (loss) $ (808,816 ) $ (607,088 ) $ (90,305 ) Preferred limited partner dividends (16,469 ) (19,267 ) (11,992 ) Net loss attributable to common limited partners and the general partner (825,285 ) (626,355 ) (102,297 ) Less: General partner’s interest 16,505 1,222 (3,364 ) Net loss attributable to common limited partners (808,780 ) (625,133 ) (105,661 ) Less: Net income attributable to participating securities – phantom units (1) — — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic (808,780 ) (625,133 ) (105,661 ) Plus: Convertible preferred limited partner dividends (1) — — — Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted $ (808,780 ) $ (625,133 ) $ (105,661 ) (1) Net income (loss) attributable to common limited partners’ ownership interests is allocated to the phantom units on a pro-rata basis (weighted average phantom units outstanding as a percentage of the sum of the weighted average phantom units and common limited partner units outstanding). For the years ended December 31, 2015, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 453,000, 783,000 and 900,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity. For the years ended December 31, 2015, 2014 and 2013, distributions on the Partnership’s Class B and Class C convertible preferred units were excluded, because the inclusion of such preferred distributions would have been anti-dilutive.
Reconciliation of the Partnership's Weighted Average Number of Common Limited Partner Units	The following table sets forth the reconciliation of the Partnership’s weighted average number of common limited partner units used to compute basic net income (loss) attributable to common limited partners per unit with those used to compute diluted net income (loss) attributable to common limited partners per unit (in thousands): Years Ended December 31, 2015 2014 2015 Weighted average number of common limited partner units—basic 93,745 74,716 52,528 Add effect of dilutive incentive awards (1) — — — Add effect of dilutive convertible preferred limited partner units (2) — — — Weighted average number of common limited partner units—diluted 93,745 74,716 52,528 (1) For the years ended December 31, 2015, 2014 and 2013, approximately 453,000 units, 783,000 units and 900,000 units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. (2) For the years ended December 31, 2015, 2014 and 2013, potential common limited partner units issuable upon conversion of the Partnership’s Class B preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the years ended December 31, 2015, 2014 and 2013, potential common limited partner units issuable upon (a) conversion of the Partnership’s Class C preferred units and (b) exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. As the Class D and Class E preferred units are convertible only upon a change of control event, they are not considered dilutive securities for earnings per unit purposes.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	Years Ended December 31, 2014 2013 Total revenues and other $ 747,655 $ 656,677 Net loss (588,823 ) (21,144 ) Net loss attributable to common limited partners (588,353 ) (26,131 ) Net loss attributable to common limited partners per unit: Basic and Diluted $ (7.28 ) $ (0.32 )
Rangely Acquisition
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	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]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	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 $ 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]
Property, Plant and Equipment	The following is a summary of property, plant and equipment at the dates indicated (in thousands): December 31, Estimated 2015 2014 in Years Natural gas and oil properties: Proved properties: Leasehold interests $ 503,586 $ 441,548 Pre-development costs 6,014 7,223 Wells and related equipment 3,076,239 3,026,416 Total proved properties 3,585,839 3,475,187 Unproved properties 213,047 217,321 Support equipment 44,921 37,359 Total natural gas and oil properties 3,843,807 3,729,867 Pipelines, processing and compression facilities 56,738 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 3,929,577 3,807,340 Less – accumulated depreciation, depletion and amortization (2,737,966 ) (1,543,520 ) $ 1,191,611 $ 2,263,820

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Other Assets Noncurrent Disclosure [Abstract]
Schedule 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 $36,582 and $18,622, respectively $ 50,884 $ 40,637 Notes receivable 3,708 3,866 Other 5,452 5,578 $ 60,044 $ 50,081

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 Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands): December 31, 2015 2014 2013 Asset retirement obligations, beginning of period $ 107,950 $ 91,179 $ 64,794 Liabilities incurred 2,070 3,512 6,366 Adjustment to liability due to acquisitions (Note 3) — 6,997 16,728 Liabilities settled (2,591 ) (1,664 ) (1,188 ) Accretion expense 6,311 5,747 4,479 Revisions — 2,179 — Asset retirement obligations, end of period $ 113,740 $ 107,950 $ 91,179

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 Revolving credit facility $ 592,000 $ 696,000 Term loan facility 243,783 — 7.75 % Senior Notes – due 2021 374,619 374,544 9.25 % Senior Notes – due 2021 324,080 323,916 Total debt 1,534,482 1,394,460 Less current maturities — — Total long-term debt $ 1,534,482 $ 1,394,460
Schedule of Maturities of Long-term Debt	The aggregate amount of the Partnership’s debt maturities is as follows (in thousands): Years Ended December 31: 2016 $ — 2017 — 2018 592,000 2019 — 2020 250,000 Thereafter 700,000 Total principle maturities 1,542,000 Unamortized premium 309 Unamortized discounts (7,827 ) Total debt $ 1,534,482

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Cash Settlement on Commodity Derivatives and Presentation in Partnership's Consolidated Statement of Operations	The following table summarizes the commodity derivative activity and presentation in the Partnership’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) 92,732 Total cash settlements on commodity derivative contracts $ 179,060 Gains recognized prior to settlement (2) 40,480 Gains recognized on open derivative contracts, net of amounts recognized in income in prior year (2) 226,743 Gains on mark-to-market derivatives $ 267,223 (1) Recognized in gas and oil production revenue. (2) Recognized in gain on mark-to-market derivatives.
Fair Values of the Partnership's Derivative Instruments Table	The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities included on the Partnership’s consolidated balance sheets for the periods indicated (in thousands): Offsetting Derivatives as of December 31, 2015 Gross Recognized Gross Net Amount Presented 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, the Partnership had the following commodity derivatives: Natural Gas – Fixed Price Swaps Production Volumes Average Fair Value (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 Option Type Volumes Average Fair Value (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 Volumes Average Fair Value (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 Volumes Average Fair Value (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 Total 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]
Schedule of Assets/Liabilities at Fair Value	Information for assets and liabilities measured at fair value at December 31, 2015 and 2014 was as follows (in thousands): As of December 31, 2015 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 355,329 $ — $ 355,329 Commodity puts — 2,393 — 2,393 Total derivative assets, gross — 357,722 — 357,722 Derivative liabilities, gross Commodity swaps — — — — Commodity options — — — — Total derivative liabilities, gross — — — — Total derivatives, fair value, net $ — $ 357,722 $ — $ 357,722 As of December 31, 2014 Level 1 Level 2 Level 3 Total Derivative assets, gross Commodity swaps $ — $ 267,242 $ — $ 267,242 Commodity puts — 2,767 — 2,767 Commodity options — 5,320 — 5,320 Total derivative assets, gross — 275,329 — 275,329 Derivative liabilities, gross Commodity swaps — (401 ) — (401 ) Commodity options — (67 ) — (67 ) Total derivative liabilities, gross — (468 ) — (468 ) Total derivatives, fair value, net $ — $ 274,861 $ — $ 274,861
Schedule of Asset Retirement Obligations Measured on Non Recurring Basis	Information for asset retirement obligations that were measured at fair value on a nonrecurring basis for the years ended December 31, 2015 and 2014 were as follows (in thousands): Years Ended December 31, 2015 2014 Level 3 Level 3 Asset retirement obligations $ 2,070 $ 10,509 Total $ 2,070 $ 10,509

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
Distributions Made To Members Or Limited Partners [Abstract]
Schedule of Distributions Declared by Partnership	Distributions declared by the Partnership for the period from January 1, 2013 through December 31, 2015 were as follows (in thousands, except per unit amounts): Date Cash Distribution Paid For Month Cash Total Cash Total Cash Total Cash 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) Includes payments for the Class B and Class C preferred unit monthly distributions. (2) 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. Date Cash Distribution Paid For the Period Cash Total Cash January 15, 2015 October 2, 2014 – January 14, 2015 $ 0.616927 $ 1,974 April 15, 2015 January 15, 2015 – April 14, 2015 $ 0.539063 $ 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 Total Cash 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 Plan (Tables)

Benefit Plan (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Phantom Unit Activity	The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted 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 Partnership’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 2012 LTIP unit option activity for the periods indicated: Years Ended December 31, 2015 2014 2013 Number Weighted Number Weighted Number Weighted 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 Partnership’s operations include three reportable operating segments. These operating segments reflect the way the Partnership manages its operations and makes business decisions. Operating segment data for the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 2013 Gas and oil production: Revenues $ 624,222 $ 472,870 $ 273,604 Operating costs and expenses (169,653 ) (182,226 ) (100,098 ) Depreciation, depletion and amortization expense (145,161 ) (229,482 ) (132,727 ) Asset impairment (966,635 ) (573,774 ) (38,014 ) Segment income (loss) $ (657,227 ) $ (512,612 ) $ 2,765 Well construction and completion: Revenues $ 76,505 $ 173,564 $ 167,883 Operating costs and expenses (66,526 ) (150,925 ) (145,985 ) Segment income $ 9,979 $ 22,639 $ 21,898 Other partnership management: (1) Revenues $ 39,306 $ 55,220 $ 32,989 Operating costs and expenses (18,775 ) (25,532 ) (27,527 ) Depreciation, depletion and amortization expense (12,817 ) (10,441 ) (7,056 ) Segment income (loss) $ 7,714 $ 19,247 $ (1,594 ) Reconciliation of segment income (loss) to net loss: Segment income (loss): Gas and oil production $ (657,227 ) $ (512,612 ) $ 2,765 Well construction and completion 9,979 22,639 21,898 Other partnership management 7,714 19,247 (1,594 ) Total segment income (loss) (639,534 ) (470,726 ) 23,069 General and administrative expenses (2) (65,968 ) (72,349 ) (78,063 ) Interest expense (2) (102,133 ) (62,144 ) (34,324 ) Loss on asset sales and disposal (2) (1,181 ) (1,869 ) (987 ) Net loss $ (808,816 ) $ (607,088 ) $ (90,305 ) Reconciliation of segment revenues to total revenues: Segment revenues: Gas and oil production (3) $ 624,222 $ 472,870 $ 273,604 Well construction and completion 76,505 173,564 167,883 Other partnership management 39,306 55,220 32,989 Total revenues $ 740,033 $ 701,654 $ 474,476 Capital expenditures: Gas and oil production $ 111,329 $ 193,131 $ 238,291 Other partnership management 14,050 14,202 17,032 Corporate and other 1,759 5,395 8,563 Total capital expenditures $ 127,138 $ 212,728 $ 263,886 December 31, 2015 2014 Balance sheet: Goodwill: Gas and oil production $ — $ — Well construction and completion 6,389 6,389 Other partnership management 7,250 7,250 $ 13,639 $ 13,639 Total assets: Gas and oil production $ 1,551,450 $ 2,601,171 Well construction and completion 27,039 39,558 Other partnership management 66,641 65,896 Corporate and other 85,874 91,495 $ 1,731,004 $ 2,798,120 (1) Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information. (2) Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented. (3) Gas and oil production segment revenues include gains on mark to market derivatives.

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 the Partnership 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) 493,232,119 1,942 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 (59,841,724 ) (485,226 ) (1,267,590 ) Balance, December 31, 2013 1,003,538,038 14,988,802 18,957,016 Extensions, discoveries and other additions (1) 58,454,544 3,372,177 3,986,986 Sales of reserves in-place (169,035 ) (1,519 ) (11,326 ) Purchase of reserves in-place (2) 82,279,988 36,538,935 3,567,531 Transfers to limited partnerships (4,887,095 ) (684,613 ) (665,486 ) Revisions (3) 3,805,952 (4,941,359 ) (2,689,379 ) Production (86,637,612 ) (1,254,247 ) (1,387,865 ) Balance, December 31, 2014 1,056,384,780 48,018,176 21,757,477 Extensions, discoveries and other additions (1) 6,441,969 2,492,424 218,726 Sales of reserves in-place (2,713,428 ) (2,393 ) — Purchase of reserves in-place (2) 3,555,062 8,645,686 653,416 Transfers to limited partnerships (2,958,882 ) (481,771 ) (342,156 ) Revisions (3) (377,067,441 ) (11,992,308 ) (13,382,104 ) Production (79,063,564 ) (1,875,654 ) (1,055,345 ) Balance, December 31, 2015 604,578,496 44,804,160 7,850,014 Proved developed reserves at: January 1, 2013 338,655,325 3,400,447 7,884,778 December 31, 2013 766,630,929 3,459,238 7,676,389 December 31, 2014 887,818,577 30,537,868 12,004,774 December 31, 2015 567,992,268 25,484,491 6,334,327 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 168,566,203 17,480,308 9,752,703 December 31, 2015 36,586,228 19,319,669 1,515,687 (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 the Rangely, Eagle Ford and Geomet Acquisitions. For the year ended December 31, 2013, the increase was primarily due to the addition of Marble Falls wells. (2) Represents purchase of proved reserves in the Rangely, Eagle Ford and GeoMet Acquisitions for the year ended December 31, 2014. (3) The downward revisions for the year ended December 31, 2015 were primarily due to unfavorable economic conditions primarily related to gas and oil commodity prices. For the year ended December 31, 2014, the downward revision on oil and NGL was primarily due to production underperforming previous year’s forecasts. The upward revision for the year ended December 31, 2014 on gas was primarily due to production outperforming previous year’s forecast. The downward revisions for the year ended December 31, 2013 were primarily due to a reduction of the Partnership’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 the Partnership during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 Natural gas and oil properties: Proved properties $ 3,585,839 $ 3,475,186 Unproved properties 213,047 217,322 Support equipment 44,921 37,359 3,843,807 3,729,867 Accumulated depreciation, depletion and (2,691,692 ) (1,509,509 ) Net capitalized costs $ 1,152,115 $ 2,220,358
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 the Partnership’s oil and gas producing activities during the periods indicated were as follows (in thousands): Years Ended December 31, 2015 2014 2013 Revenues $ 356,999 $ 470,051 $ 273,604 Production costs (169,653 ) (182,226 ) (100,098 ) Depletion (145,161 ) (229,482 ) (132,727 ) Asset impairment (1) (966,635 ) (573,774 ) (38,014 ) $ (924,450 ) $ (515,431 ) $ 2,765 (1) During the year ended December 31, 2015, the Partnership recognized $966.6 million of asset impairment primarily related to 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 Partnership recognized $573.8 million of asset impairment primarily consisting of $555.7 million related to oil and gas properties within property, plant, and equipment, net on its consolidated balance sheet for its 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 of goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, the Partnership 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 the Partnership in its 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 $ 11,513 $ 699,451 $ 859,827 Unproved properties 43,820 10,978 895 Exploration costs (1) 1,601 722 1,053 Development costs 73,288 164,853 214,383 Total costs incurred in oil & gas producing activities $ 130,222 $ 876,004 $ 1,076,158 (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 the Partnership’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 includes 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 $ 3,514,198 $ 9,317,915 $ 5,259,688 Future production costs (1,836,779 ) (4,188,364 ) (2,393,814 ) Future development costs (1,156,367 ) (1,157,305 ) (752,349 ) Future net cash flows 521,052 3,972,246 2,113,525 Less 10% annual discount for estimated timing of cash flows (18,283 ) (1,987,975 ) (1,037,343 ) Standardized measure of discounted future net cash flows $ 502,769 $ 1,984,271 $ 1,076,182
Schedule of Changes in Discounted Future Net Cash Flows	Change in Standardized Discounted 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 the Partnership allocates taxable income to its owner, no recognition has been given to income taxes: Years Ended December 31, 2015 2014 2013 Balance, beginning of year $ 1,984,271 $ 1,076,182 $ 623,676 Increase (decrease) in discounted future net cash flows: Sales of oil and gas produced, net of related costs (1) (129,352 ) (272,961 ) (171,300 ) Net changes in prices and production costs (2) (1,453,854 ) 339,718 85,191 Revisions of previous quantity estimates (52,775 ) 4,352 (1,880 ) Development costs incurred 58,117 52,077 27,245 Changes in future development costs (152,305 ) (90,887 ) (21,579 ) Transfers to limited partnerships (13,291 ) (2,966 ) (53,392 ) Extensions, discoveries, and improved recovery less related costs 13,980 60,832 143,338 Purchases of reserves in-place (3) 53,102 737,101 513,744 Sales of reserves in-place (2,162 ) (332 ) (2,053 ) Accretion of discount 198,427 107,618 62,368 Estimated settlement of asset retirement obligations (216 ) (16,708 ) (18,823 ) Estimated proceeds on disposals of well equipment (1,173 ) (21,906 ) 17,039 Changes in production rates (timing) and other — 12,151 (127,392 ) Outstanding, end of year $ 502,769 $ 1,984,271 $ 1,076,182 (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 the Rangely, Eagle Ford and 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 (1)(2) Third (1)(2) Second (1) First (1) (in thousands, except unit data) Year ended December 31, 2015: Revenues $ 142,424 $ 257,895 $ 96,125 $ 243,589 Net loss attributable to common limited partners and the general partner’s interests (2) $ (293,013 ) $ (565,147 ) $ (51,044 ) $ 83,919 Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (287,153 ) $ (553,844 ) $ (50,023 ) $ 82,240 General partner’s interest (5,860 ) (11,303 ) (1,021 ) 1,679 Net loss attributable to common limited partners and the general partner’s interests $ (293,013 ) (565,147 ) $ (51,044 ) $ 83,919 Net loss attributable to common unitholders per unit: Basic $ (2.81 ) $ (5.73 ) $ (0.55 ) $ 0.95 Diluted $ (2.81 ) $ (5.73 ) $ (0.55 ) $ 0.93 (1) For the second, third, and fourth quarters of the year ended December 31, 2015, approximately 469,000, 346,000 and 309,000 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. For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. (2) Includes asset impairment charges of $672.2 million and $294.4 million in the third and fourth quarters of 2015, respectively. Fourth (1) (2) Third (1) Second (1) First (1) (in thousands, except unit data) Year ended December 31, 2014: Revenues $ 194,701 $ 206,699 $ 138,897 $ 161,357 Net loss attributable to common limited partners and the general partner’s interests (2) $ (585,499 ) $ (2,590 ) $ (23,803 ) $ (14,463 ) Allocation of net income (loss) attributable to common limited partners and the general partner: Common limited partners’ interest $ (576,850 ) $ (5,599 ) $ (26,203 ) $ (16,481 ) General partner’s interest (8,649 ) 3,009 2,400 2,018 Net loss attributable to common limited partners and the general partner’s interests $ (585,499 ) (2,590 ) $ (23,803 ) $ (14,463 ) Net loss attributable to common unitholders per unit: Basic $ (7.04 ) $ (0.07 ) $ (0.35 ) $ (0.27 ) Diluted $ (7.04 ) $ (0.07 ) $ (0.35 ) $ (0.27 ) (1) For the first, second, third, and fourth quarters of the year ended December 31, 2014, approximately 820,000, 724,000, 797,000, and 791,000 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. For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. (2) Includes an asset impairment charge of $573.8 million in the fourth quarter of 2014.

Basis of Presentation (Narrativ

Basis of Presentation (Narrative) (Details) - shares	Feb. 27, 2015	Dec. 31, 2015
Basis Of Presentation [Line Items]
Limited partners units issued		102,160,866
Limited partners units outstanding		102,160,866
Atlas Energy, L.P.
Basis Of Presentation [Line Items]
Percentage of interest represented by common units which is distributed	100.00%
General Partner interest in Atlas Resource Partners, L.P		100.00%
Common limited partner interest in Atlas Resource Partners, L.P		23.30%
Common limited partner interest in Atlas Resource Partners, L.P., Units		20,962,485
Atlas Energy, L.P. | Preferred Limited Partners' Interest
Basis Of Presentation [Line Items]
Common limited partner interest in Atlas Resource Partners, L.P., Units		3,749,986

Summary of Significant Accoun41

Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Nov. 23, 2015	Nov. 22, 2015
Summary Of Significant Accounting Policies [Line Items]
Decrease in net loss attributable to common limited partners per unit	$ (8.63)	$ (8.37)	$ (2.01)
Pro-rata share in Drilling Partnerships	30.00%
Amended borrowing base				$ 700,000,000	$ 750,000,000
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, net	13,639,000	13,639,000
Goodwill, Impairment Loss		18,100,000
Goodwill, Period Increase (Decrease)	$ 0		0
Entity Not Subject to Income Taxes, Policy	The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the consolidated financial statements. Certain corporate subsidiaries of the Partnership are subject to federal and state income tax. The federal and state income taxes related to the Partnership and these corporate subsidiaries were immaterial to the consolidated financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the consolidated financial statements.
Deferred income tax expense (benefit)	$ 0	0
Income Tax Examination, Penalties and Interest Expense	$ 0	0	0
Income Tax Examination, Description	The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015.
Accrual for Environmental Loss Contingencies	$ 0	0	$ 0
Concentration Risk, Credit Risk, Uninsured Deposits	Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its 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 Partnership had $10.3 million and $17.2 million, respectively, in deposits at various banks, of which $8.4 million and $14.9 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date.
Cash Equivalents, at Carrying Value	$ 10,300,000	17,200,000
Cash, Uninsured Amount	$ 8,400,000	14,900,000
Concentration Risk, Customer	The Partnership sells natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2015, the Partnership had four customers within its gas and oil production segment that individually accounted for approximately 21%, 15%, 11% and 11%, respectively, of the Partnership natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, the Partnership had four customers within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of the Partnership natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2013, the Partnership had three customers within its gas and oil production segment that individually accounted for approximately 19%, 11% and 10% of the Partnership’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. The Partnership is subject to the risk of loss on its derivative instruments that it would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Partnership maintains credit policies with regard to its counterparties to minimize its overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of its 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 it 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. The Partnership’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 our revolving credit facility. Subject to the terms of their revolving credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the revolving credit facility.
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	$ 37,700,000	$ 84,700,000
Unamortized deferred financing costs	$ 31,100,000
Drilling Partnership wells
Summary Of Significant Accounting Policies [Line Items]
Gathering Fee Percentage	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
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%
Arkoma Acquisition
Summary Of Significant Accounting Policies [Line Items]
Decrease in net loss attributable to common limited partners per unit		$ 0.05	$ 0.02

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 (Loss) Reconciliation) (Details) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2015	[1],[2]	Sep. 30, 2015	[1],[2]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2014	[3],[4]	Sep. 30, 2014	[3]	Jun. 30, 2014	[3]	Mar. 31, 2014	[3]	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Net income (loss)																	$ (808,816)	$ (607,088)	$ (90,305)
Preferred limited partner dividends																	(16,469)	(19,267)	(11,992)
Net loss attributable to common limited partners and the general partner	$ (293,013)		$ (565,147)		$ (51,044)	[2]	$ 83,919	[2]	$ (585,499)		$ (2,590)	[4]	$ (23,803)	[4]	$ (14,463)	[4]	(825,285)	(626,355)	(102,297)
Less: General partner’s interest	5,860		11,303		1,021		(1,679)		8,649		(3,009)		(2,400)		(2,018)		16,505	1,222	(3,364)
Net loss attributable to common limited partners	$ (287,153)		$ (553,844)		$ (50,023)		$ 82,240		$ (576,850)		$ (5,599)		$ (26,203)		$ (16,481)		(808,780)	(625,133)	(105,661)
Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Basic																	(808,780)	(625,133)	(105,661)
Net loss utilized in the calculation of net loss attributable to common limited partners per unit - Diluted																	$ (808,780)	$ (625,133)	$ (105,661)
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units																	453,000	783,000	900,000
[1]	For the second, third, and fourth quarters of the year ended December 31, 2015, approximately 469,000, 346,000 and 309,000 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. For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
[2]	Includes asset impairment charges of $672.2 million and $294.4 million in the third and fourth quarters of 2015, respectively.
[3]	For the first, second, third, and fourth quarters of the year ended December 31, 2014, approximately 820,000, 724,000, 797,000, and 791,000 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. For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
[4]	Includes an asset impairment charge of $573.8 million in the fourth quarter of 2014.

Summary of Significant Accoun44

Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Limited Partner Units) (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Weighted average number of common limited partner units—basic	93,745,000	74,716,000	52,528,000
Weighted average number of common limited partner units—diluted	93,745,000	74,716,000	52,528,000
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units	453,000	783,000	900,000

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
7.75% Senior Notes
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.75%
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
Partners' Capital Account, Units, Sale of Units	15,525,000	15,525,000
Business Acquisition, Purchase Price Allocation, Methodology			The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership 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 common limited partner units associated with the acquisition, the Partnership recorded $11.6 million of transaction fees, which were included with common limited partners’ interests for the year ended December 31, 2014 on the Partnership’s 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
Rangely Acquisition | 7.75% Senior Notes
Business Acquisition [Line Items]
Proceed from additional senior notes	$ 100
Debt Instrument, Interest Rate, Stated Percentage	7.75%

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, 2013
9.25% Senior Notes
Business Acquisition [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			9.25%
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' Capital Account, Units, Sale of Units	14,950,000	14,950,000
Business Acquisition, Purchase Price Allocation, Methodology			The Partnership accounted for this transaction under the acquisition method of accounting. Accordingly, the Partnership evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values (see Note 9).
Business Acquisition, Purchase Price Allocation, Status			All other costs associated with the acquisition of assets were expensed as incurred
Business Acquisition, Cost of Acquired Entity, Transaction Costs				$ 12.1
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
EP Energy Acquisition | Class C Convertible Preferred Units | Atlas Parent Company "ATLS"
Business Acquisition [Line Items]
Partners' Capital Account, Units, Sale of Units	3,749,986

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, net income (loss) and basic and diluted net income (loss) per unit for the Partnership as if the Rangely and EP Energy acquisitions, including the related borrowings, net proceeds from the issuance of debt and issuances of common and preferred units had occurred on January 1, 2013. The Partnership 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 had occurred on January 1, 2013 or the results that will be attained in future periods

Acquisitions (Pro Forma Finan50

Acquisitions (Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Total revenues and other	$ 747,655	$ 656,677
Net loss	(588,823)	(21,144)
Net loss attributable to common limited partners	$ (588,353)	$ (26,131)
Net loss attributable to common limited partners per unit: Basic and Diluted	$ (7.28)	$ (0.32)

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

Sep. 30, 2015

Dec. 31, 2014

Oct. 31, 2014

Mar. 31, 2014

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2015

Arkoma Acquisition

Business Acquisition [Line Items]

Cash Consideration

$ 31.5

Issuances of Partnership Units to Fund the Purchase Price

6,500,000

Business Acquisition, Effective Date of Acquisition

Jan. 1, 2015

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

Eagle Ford Acquisition | Class D Preferred Units

Business Acquisition [Line Items]

Issuances of Partnership Units to Fund the Purchase Price

3,200,000

800,000

Eagle Ford Acquisition | Atlas Growth Partners L P

Business Acquisition [Line Items]

Cash Consideration

$ 1.4

Deferred portion of purchase price

$ 19.9

$ 36.3

$ 35

$ 16

$ 28.3

Eagle Ford Acquisition | Atlas Resource Partners L P

Business Acquisition [Line Items]

Deferred portion of purchase price

$ 17.5

$ 0.6

$ 21.6

Eagle Ford Acquisition | Atlas Resource Partners L P | Class D Preferred Units

Business Acquisition [Line Items]

Deferred portion of purchase price by issuing preferred units

$ 20

GeoMet Acquisition

Business Acquisition [Line Items]

Cash Consideration

$ 97.9

Issuances of Partnership Units to Fund the Purchase Price

6,325,000

Business Acquisition, Effective Date of Acquisition

Jan. 1, 2014

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]

Cash Consideration

$ 5.4

Business Acquisition, Effective Date of Acquisition

Jun. 1, 2013

Business Acquisition, Description of Acquired Entity

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

Property, Plant and Equipment52

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	$ 503,586	$ 441,548
Proved Properties: Pre-development costs	6,014	7,223
Proved Properties: Wells and related equipment	3,076,239	3,026,416
Total proved properties	3,585,839	3,475,187
Unproved properties	213,047	217,321
Support equipment	44,921	37,359
Total natural gas and oil properties	3,843,807	3,729,867
Pipelines, processing and compression facilities	56,738	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	3,929,577	3,807,340
Less – accumulated depreciation, depletion and amortization	(2,737,966)	(1,543,520)
Property, plant and equipment, Net, Total	$ 1,191,611	$ 2,263,820

Property, Plant and Equipment53

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 Equipment54

Property, Plant and Equipment (Narrative) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment [Line Items]
Loss on asset sales and disposal	[1]	$ 1,181,000	$ 1,869,000	$ 987,000
Impairments of Unproved Gas And Oil Properties		6,600,000	0	13,500,000
Asset impairment		966,635,000	573,774,000	38,014,000
Non-cash property plant and equipment additions		22,600,000	25,000,000	26,000,000
Barnett and Coal-bed Methane
Property Plant And Equipment [Line Items]
Asset impairment		960,000,000
Appalachian Basin
Property Plant And Equipment [Line Items]
Asset impairment			555,700,000
New Albany Shale
Property Plant And Equipment [Line Items]
Asset impairment				$ 24,500,000
Reclassification out of Accumulated Other Comprehensive Income
Property Plant And Equipment [Line Items]
Future hedge gains reclassified from accumulated other comprehensive income		$ 85,800,000	$ 82,300,000
[1]	Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.

Other Assets (Summary of Other

Other Assets (Summary of Other Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred Costs Capitalized Prepaid And Other Assets Disclosure [Abstract]
Accumulated amortization	$ 36,582	$ 18,622
Deferred financing costs, net of accumulated amortization	50,884	40,637
Notes receivable	3,708	3,866
Other	5,452	5,578
Total Other Assets	$ 60,044	$ 50,081

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]
Amortization of financing costs	$ 12,400,000	$ 8,600,000	$ 6,400,000
Accelerated amortization of deferred financing costs	$ 5,600,000	600,000	3,200,000
Notes Receivable
Other Assets [Line Items]
Note Agreement, Maturity Date	Mar. 31, 2022
Note Agreement, Interest Rate Per Annum	2.25%
Note Agreement, Extension Fee Percent	1.00%
Other Interest and Dividend Income	$ 100,000	100,000	$ 100,000
Note Receivable, Allowance for Credit Losses	$ 0	$ 0
Note Agreement, Option to Extend Maturity Date
Other Assets [Line Items]
Note Agreement, Maturity Date	Mar. 31, 2027
7.75% Senior Notes
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, end of year	$ 113,740	$ 107,950	$ 91,179	$ 64,794
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 | Common Limited Partners' Interests
Asset Retirement Obligations [Line Items]
Asset retirement obligations, end of year	$ 44,200

Asset Retirement Obligations 58

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 period	$ 107,950	$ 91,179	$ 64,794
Liabilities incurred	2,070	3,512	6,366
Adjustment to liability due to acquisitions		6,997	16,728
Liabilities settled	(2,591)	(1,664)	(1,188)
Accretion expense	6,311	5,747	4,479
Revisions		2,179
Asset retirement obligations, end of period	$ 113,740	$ 107,950	$ 91,179

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]
Revolving credit facility	$ 592,000	$ 696,000
Total debt	1,534,482	1,394,460
Long-term debt	1,534,482	1,394,460
Term Loan
Debt Instrument [Line Items]
Term loan facility	243,783
7.75% Senior Notes
Debt Instrument [Line Items]
Senior Notes	374,619	374,544
9.25% Senior Notes
Debt Instrument [Line Items]
Senior Notes	$ 324,080	$ 323,916

Debt (Credit Facility) (Details

Debt (Credit Facility) (Details) - USD ($)

Nov. 23, 2015

Feb. 23, 2015

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

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

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

Distribution per common 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

$ 0.1933

$ 0.5800

$ 0.5600

$ 0.5400

$ 0.5100

Revolving credit facility

$ 696,000,000

$ 592,000,000

Second Amendment

Line Of Credit Facility [Line Items]

Line of Credit Facility, Current Borrowing Capacity

700,000,000

Line Of Credit Facility Maximum Borrowing Capacity

$ 1,500,000,000

Line of Credit Facility, Expiration Date

Jul. 1, 2018

Eighth Amendment

Line Of Credit Facility [Line Items]

Line of Credit Facility, Current Borrowing Capacity

$ 700,000,000

$ 750,000,000

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

25.00%

Required Total Funded Debt To EBITDA Ratio

5.00%

Ratio of First Lien Debt to EBITDA

2.75%

Distribution per common unit

$ 0.15

Liquidity percentage under borrowing base

85.00%

Eighth Amendment | Quarter ended March 31, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.75%

Eighth Amendment | Quarter ended June 30, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.75%

Eighth Amendment | Quarter ended September 30, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.50%

Eighth Amendment | Quarter ended December 31, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.50%

Eighth Amendment | Quarter ended March 31, 2018

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.25%

Eighth Amendment | Fiscal quarters ending thereafter

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.00%

Eighth Amendment | Eurodollar

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Eighth Amendment | Alternate Base Rate

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Sixth Amendment

Line Of Credit Facility [Line Items]

Line of Credit Facility, Current Borrowing Capacity

$ 750,000,000

$ 900,000,000

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

Sixth Amendment | Quarter ended March 31, 2017

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

4.50%

Sixth Amendment | Fiscal quarters ending thereafter

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

4.00%

Sixth Amendment | Borrowing base utilization is less than 90%

Line Of Credit Facility [Line Items]

Percentage of borrowing base utilized

90.00%

Sixth Amendment | Quarter ended March 31, 2015

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.25%

Sixth Amendment | Quarter ended June 30, 2015

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.25%

Sixth Amendment | Quarter ended September 30, 2015

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.25%

Sixth Amendment | Quarter ended December 31, 2015

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.25%

Sixth Amendment | Quarter ended March 31, 2016

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.25%

Sixth Amendment | Quarter ended June 30, 2016

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.00%

Sixth Amendment | Quarter ended September 30, 2016

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.00%

Sixth Amendment | Quarter ended December 31, 2016

Line Of Credit Facility [Line Items]

Required Total Funded Debt To EBITDA Ratio

5.00%

Sixth Amendment | Eurodollar | Borrowing base utilization is less than 90%

Line Of Credit Facility [Line Items]

Increase in applicable margin

0.25%

Sixth Amendment | 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

Line Of Credit Facility [Line Items]

Aggregate Principal Amount of Second Lien Debt

$ 300,000,000

Revolving credit facility

592,000,000

Letters Of Credit Outstanding Maximum

20,000,000

Letters Of Credit Outstanding Amount

$ 4,200,000

Line Of Credit Facility Collateral

The 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. Additionally, obligations under the facility are guaranteed by certain of the Partnership’s material subsidiaries, and any non-guarantor subsidiaries of the Partnership 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). The Partnership 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 Partnership’s 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%

Line of Credit Facility, Covenant Terms

The Credit Agreement contains customary covenants including, without limitation, covenants that limit the Partnership’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, merger or consolidate with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Credit Agreement also requires the Partnership to 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 Credit Agreement) to current liabilities (as defined in the 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

The Partnership was in compliance with these covenants as of December 31, 2015.

Required Current Assets To Current Liabilities Ratio

100.00%

Current Assets To Current Liabilities Ratio

1.30%

Debt to EBITDA Ratio

2.30%

Revolving Credit Facility | Third Lien Credit Agreement

Line Of Credit Facility [Line Items]

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

25.00%

Debt (Term Loan Facility) (Deta

Debt (Term Loan Facility) (Details) - USD ($) $ in Thousands	Feb. 23, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount		$ 7,827
Second Lien Term Loan Facility
Debt Instrument [Line Items]
Increase in borrowing base under revolving credit facility	$ 250,000
Line of Credit Facility, Expiration Date	Feb. 23, 2020
Debt Instrument, Unamortized Discount		$ 6,200
Percentage of net cash proceeds from the issuance or incurrence of debt used to prepay Term Loan Facility	100.00%
Percentage of excess net cash proceeds from certain asset sales and condemnation recoveries used to prepay Term Loan Facility	100.00%
Line Of Credit Facility Interest Rate Description		Borrowings under the Term Loan Facility bear interest, at the Partnership’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.
Line of Credit Facility, Weighted Average Interest Rate		10.00%
Aggregate outstanding principal amount of Term Loan Facility plus principal amount of incremental term loan	$ 300,000
Second Lien Term Loan Facility | Incremental Term Loans
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Feb. 23, 2020
Second Lien Term Loan Facility | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	9.00%
Second Lien Term Loan Facility | Federal Funds Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.50%
Second Lien Term Loan Facility | One-month LIBOR
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.00%
Second Lien Term Loan Facility | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2.00%
Second Lien Term Loan Facility | Alternate Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	8.00%
Second Lien Term Loan Facility | Between 12 months and 24 months after closing date
Debt Instrument [Line Items]
Percentage of principal amount prepaid for repayments	4.50%
Second Lien Term Loan Facility | Between 24 months and 36 months after closing date
Debt Instrument [Line Items]
Percentage of principal amount prepaid for repayments	2.25%
Second Lien Term Loan Facility | Following 36 months after closing date
Debt Instrument [Line Items]
Percentage of principal amount prepaid for repayments	0.00%

Debt (Senior Notes) (Details)

Debt (Senior Notes) (Details) - USD ($)	Dec. 29, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 17, 2015
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount		$ 7,827,000
Maximum debt indebtedness in exchange of senior notes	$ 100,000,000
Debt Instrument, Restrictive Covenants		The indentures governing the 7.75% Senior Notes and 9.25% Senior Notes contain covenants including, without limitation, covenants that limit the Partnership’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 the Partnership’s assets.
Debt Instrument, Covenant Compliance		The Partnership was in compliance with these covenants as of December 31, 2015.
Cash Payments For Interest On Debt		$ 98,500,000	$ 58,700,000	$ 17,900,000
7.75% Senior Notes
Debt Instrument [Line Items]
Senior notes, Face Amount	500,000,000	$ 374,600,000
Senior notes, maturity		2,021
Debt Instrument, Interest Rate, Stated Percentage		7.75%
Debt Instrument, Unamortized Discount		$ 400,000
Senior Notes Interest Payment Dates and Terms		Interest on the 7.75% 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% 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% 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, the Partnership may redeem the 7.75%
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
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor		$ 0
9.25% Senior Notes
Debt Instrument [Line Items]
Senior notes, Face Amount		$ 324,100,000			$ 500,000,000
Senior notes, maturity		2,021
Debt Instrument, Interest Rate, Stated Percentage		9.25%
Debt Instrument, Unamortized Discount		$ 900,000
Senior Notes Interest Payment Dates and Terms		Interest on the 9.25% Senior Notes is payable semi-annually on February 15 and August 15.
Maximum debt indebtedness in exchange of senior notes					100,000,000
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 Instrument, Call Feature		At any time prior to August 15, 2017, the Partnership may redeem the 9.25% 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% Senior Notes Indenture”)), plus accrued and unpaid interest, if any. At any time on or after August 15, 2017, the Partnership may redeem some or all of the 9.25% Senior Notes at a redemption price of 104.625%. On or after August 15, 2018, the Partnership may redeem some or all of the 9.25% Senior Notes at the redemption price of 102.313% and on or after August 15, 2019,
Senior Notes Indenture
Debt Instrument [Line Items]
Percentage Of Senior Secured Outstanding Debt	8.00%
Senior Notes Indenture | 7.75% Senior Notes
Debt Instrument [Line Items]
Senior notes, Face Amount	$ 1,000,000,000
Senior Notes Indenture | 9.25% Senior Notes
Debt Instrument [Line Items]
Senior notes, Face Amount					$ 1,050,000,000
Maximum | Senior Notes Indenture
Debt Instrument [Line Items]
Senior Secured Notes Interest Expense	$ 80,000,000

Debt (Debt Maturities) (Details

Debt (Debt Maturities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
2,018	$ 592,000
2,020	250,000
Thereafter	700,000
Total principle maturities	1,542,000
Unamortized premium	309
Unamortized discounts	(7,827)
Total debt	$ 1,534,482	$ 1,394,460

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	$ 357,700,000	$ 274,900,000
Net gain in accumulated other comprehensive income	19,400,000
Cash Flow Hedge Gain (Losses) expected to be Reclassified within Twelve Months	16,700,000
Cash Flow Hedge Gain (Loss) To Be Reclassified In Later Periods	2,700,000
Reclassification of gain (loss) from accumulated other comprehensive income losses on settled contracts	86,328,000	(7,739,000)	$ 10,216,000
Gains or losses recognized during the period		0	0
Hedge Monetization Cash Proceeds		$ 200,000
Net Unrealized Derivative Assets Payable To Limited Partners	$ 2,400,000
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

Derivative Instruments (Summary

Derivative Instruments (Summary of Cash Settlement on Commodity Derivatives 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		92,732
Total cash settlements on commodity derivative contracts		179,060
Gains recognized prior to settlement	[2]	40,480
Gains recognized on open derivative contracts, net of amounts recognized in income in prior year	[2]	226,743
Gains on mark-to-market derivatives		$ 267,223	$ 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 Partnership's Derivative Instruments Table) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Assets	$ 357,722	$ 275,329
Gross Amounts Recognized, Liabilities		(468)
Current portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(98)
Gross Amounts Offset, Liabilities		98
Long-term portion of derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(370)
Gross Amounts Offset, Liabilities		370
Total derivative liabilities
Derivatives Fair Value [Line Items]
Gross Amounts Recognized, Liabilities		(468)
Gross Amounts Offset, Liabilities		468
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
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
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 (Commodi

Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) $ in Thousands	Dec. 31, 2015USD ($)MMBTUbbl$ / MMBTU$ / bbl
Derivatives Fair Value [Line Items]
Fair Value Asset	$ 357,722	[1]
Natural Gas - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset	221,039	[2]
Natural Gas - Put Options - Drilling Partnerships
Derivatives Fair Value [Line Items]
Fair Value Asset	2,393	[2]
Natural Gas Liquids – Crude Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset	5,775	[1]
Crude Oil - Fixed Price Swaps
Derivatives Fair Value [Line Items]
Fair Value Asset	$ 128,515	[1]
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	$ 92,131	[2]
Production Period Ending December 31 2016 | Natural Gas - Put Options - Drilling Partnerships | 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	$ 2,393	[2]
Production Period Ending December 31 2016 | Natural Gas Liquids – Crude 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	$ 3,651	[1]
Production Period Ending December 31 2016 | 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	$ 61,284	[1]
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	$ 67,916	[2]
Production Period Ending December 31 2017 | Natural Gas Liquids – Crude 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	$ 2,124	[1]
Production Period Ending December 31 2017 | 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	$ 33,335	[1]
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	$ 47,153	[2]
Production Period Ending December 31 2018 | 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	$ 26,248	[1]
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	$ 13,839	[2]
Production Period Ending December 31 2019 | 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	$ 7,648	[1]
[1]	Fair value based on forward WTI crude oil prices, as applicable.
[2]	Fair value based on forward NYMEX natural gas prices, as applicable.
[3]	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

Fair Value of Financial Instr68

Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets	$ 357,722	$ 275,329
Gross Amounts of Recognized Liabilities		(468)
Total derivatives, fair value, net	357,722	274,861
Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets	357,722	275,329
Gross Amounts of Recognized Liabilities		(468)
Total derivatives, fair value, net	357,722	274,861
Commodity Swaps
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets	355,329	267,242
Gross Amounts of Recognized Liabilities		(401)
Commodity Swaps | Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets	355,329	267,242
Gross Amounts of Recognized Liabilities		(401)
Commodity Puts
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets	2,393	2,767
Commodity Puts | Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets	$ 2,393	2,767
Commodity Option
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets		5,320
Gross Amounts of Recognized Liabilities		(67)
Commodity Option | Level 2
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Gross Amounts of Recognized Assets		5,320
Gross Amounts of Recognized Liabilities		$ (67)

Fair Value of Financial Instr69

Fair Value of Financial Instruments - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Long-term Debt, Fair Value	$ 907,800	$ 1,219,800
Long-term debt	$ 1,534,482	$ 1,394,460

Fair Value of Financial Instr70

Fair Value of Financial Instruments (Schedule of Asset Retirement Obligations Measured on Non Recurring Basis) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Fair value, liabilities	$ 2,070	$ 3,512	$ 6,366
Level 3
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Fair value, liabilities	2,070	10,509
Asset Retirement Obligations | Level 3
Fair Value Option Qualitative Disclosures Related To Election [Line Items]
Fair value, liabilities	$ 2,070	$ 10,509

Certain Relationships and Rel71

Certain Relationships and Related Party Transactions (Narrative) (Details) $ in Millions	Sep. 21, 2015installment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Relationship with ATLS
Related Party Transaction [Line Items]
Accounts payable		$ 1.3	$ 8.8
Relationship with AGP
Related Party Transaction [Line Items]
Accounts payable		$ 8.7
Remaining purchase price installments | installment	2
Accounts receivable			$ 6.6

Commitments and Contingencies72

Commitments and Contingencies (General Commitments) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating leases, rent expense, net	$ 15,700,000	$ 17,000,000	$ 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
Long-term purchase commitment, amount	7,100,000
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
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%
Period of return on unhedged revenue	5 years
Maximum
Partnership obligations to purchase units from investor partners	10.00%
Percentage on unhedged revenue	50.00%
Investor partners return on investment	12.00%
Period of return on unhedged revenue	8 years

Commitments and Contingencies73

Commitments and Contingencies (Schedule of Future Minimum Lease Payments) (Details) $ in Thousands	Dec. 31, 2015USD ($)
Commitments and Contingencies [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 (Details)

Issuances of Units (Details) - USD ($)

Apr. 30, 2015

Jan. 15, 2015

Nov. 30, 2015

Jul. 31, 2015

May. 31, 2015

Oct. 31, 2014

Aug. 31, 2014

Jun. 30, 2014

May. 31, 2014

Mar. 31, 2014

Jul. 31, 2013

Jun. 30, 2013

Mar. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Capital Unit [Line Items]

Net proceeds from issuance of common limited partner units

$ 93,635,000

$ 426,290,000

$ 320,017,000

Partners' Capital Account, Units, Sold in Private Placement

$ 120,391,000

$ 503,591,000

$ 406,641,000

Arkoma Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

6,500,000

Net Proceeds from Issuance of Common Limited Partners Units

$ 49,700,000

Partners' Capital Account, Units, Date Of Sale

May 2,015

Subsidiary or Equity Method Investee, Price-Per-Share

$ 7.97

Rangely Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

15,525,000

15,525,000

Net Proceeds from Issuance of Common Limited Partners Units

$ 297,300,000

Partners' Capital Account, Units, Date Of Sale

May 2,014

Subsidiary or Equity Method Investee, Price-Per-Share

$ 19.90

GeoMet Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

6,325,000

Net Proceeds from Issuance of Common Limited Partners Units

$ 129,000,000

Partners' Capital Account, Units, Date Of Sale

March 2,014

Subsidiary or Equity Method Investee, Price-Per-Share

$ 21.18

EP Energy Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

14,950,000

14,950,000

Net Proceeds from Issuance of Common Limited Partners Units

$ 313,100,000

Partners' Capital Account, Units, Date Of Sale

June 2,013

Subsidiary or Equity Method Investee, Price-Per-Share

$ 21.75

Class B Preferred Units

Capital Unit [Line Items]

Conversion of Class B preferred units (units)

39,654

Class D Preferred Units

Capital Unit [Line Items]

Redemption price per unit

$ 25

Class E Preferred Units

Capital Unit [Line Items]

Redemption price per unit

$ 25

Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co.

Capital Unit [Line Items]

Aggregate Offering Price Of Common Units (Maximum)

$ 100,000,000

Weighted average price of preferred units percentage

97.00%

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

3.00%

Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co. | August 2015 ATM Agreement

Capital Unit [Line Items]

Net Proceeds from Issuance of Common Limited Partners Units

$ 900,000

Payments for commissions and offering expenses

300,000

Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co. | November 2015 ATM Agreement

Capital Unit [Line Items]

Payments for commissions and offering expenses

100,000

Class E Cumulative Redeemable Perpetual Preferred Units

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

255,000

Net Proceeds from Issuance of Common Limited Partners Units

$ 6,000,000

Public offer price per share

$ 25

Preferred Unit Regular Quarterly Cash Distributions Per Unit there after

$ 2.6875

Percentage of Preferred Unit Regular Quarterly Cash Distributions

10.75%

Preferred Stock Liquidation Preference

$ 25

Equity Distribution Agreement with Deutsche Bank Securities Inc.

Capital Unit [Line Items]

Aggregate Offering Price Of Common Units (Maximum)

$ 100,000,000

$ 25,000,000

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

2.00%

Partners' Capital Account, Units, Sale of Units

9,803,451

0

309,174

Payments for commissions and offering expenses

$ 1,100,000

$ 400,000

Net proceeds from issuance of common limited partner units

$ 44,200,000

$ 6,900,000

Equity Distribution Agreement Commencement Date

May 1, 2013

Equity Distribution Agreement Effective Date

Dec. 27, 2013

Over Allotment Units Issued | Rangely Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

2,025,000

Over Allotment Units Issued | GeoMet Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

825,000

Over Allotment Units Issued | EP Energy Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

1,950,000

Class C Convertible Preferred Units | EP Energy Acquisition | Atlas Parent Company "ATLS"

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

3,749,986

Subsidiary or Equity Method Investee, Price-Per-Share

$ 23.10

Partners' Capital Account, Units, Sold in Private Placement

$ 86,600,000

Preferred Units, Description

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

Registration Rights Agreement Description And Terms

Upon issuance of the Class C preferred units and warrants on July 31, 2013, the Partnership 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. The Partnership 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.

Registration statement effective date

Mar. 27, 2015

Class D Preferred Units

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

8.625%

Class D Preferred Units | Eagle Ford Acquisition

Capital Unit [Line Items]

Partners' Capital Account, Units, Percentage

8.625%

Partners' Capital Account, Units, Sale of Units

3,200,000

800,000

Net Proceeds from Issuance of Common Limited Partners Units

$ 77,300,000

Partners' Capital Account, Units, Date Of Sale

October 2,014

Subsidiary or Equity Method Investee, Price-Per-Share

$ 25

$ 25

Preferred Unit Regular Quarterly Cash Distributions Per Unit there after

$ 2.15625

Percentage of Preferred Unit Regular Quarterly Cash Distributions

8.625%

Preferred Stock Liquidation Preference

$ 25

Preferred Unit Regular Quarterly Cash Distributions Per Unit

$ 0.616927

Class D Preferred Units | Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co. | August 2015 ATM Agreement

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

90,328

Class D Preferred Units | Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co. | November 2015 ATM Agreement

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

0

Class E Preferred Units | Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co. | August 2015 ATM Agreement

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

1,083

Class E Preferred Units | Equity Distribution Agreement with MLV & Co. LLC and FBR Capital Markets and Co. | November 2015 ATM Agreement

Capital Unit [Line Items]

Partners' Capital Account, Units, Sale of Units

0

Cash Distributions - Additional

Cash Distributions - Additional Information (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Minimum
Distribution Made To Limited Partner [Line Items]
Percentage of Distributions in Excess of Targets	13.00%
Maximum
Distribution Made To Limited Partner [Line Items]
Percentage of Distributions in Excess of Targets	48.00%
Preferred Class B
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Monthly Cash Distributions Per Unit	$ 0.1333
Preferred Class B | Minimum
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit	0.40
Preferred Class C
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Monthly Cash Distributions Per Unit	0.17
Preferred Class C | Minimum
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit	0.51
Preferred Class D
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit	0.5390625
Preferred Unit Regular Annually Cash Distributions Per Unit	$ 2.15625
Partners' Capital Account, Units, Percentage	8.625%
Preferred Stock Liquidation Preference	$ 25
Preferred Class E
Distribution Made To Limited Partner [Line Items]
Preferred Unit Regular Quarterly Cash Distributions Per Unit	0.671875
Preferred Unit Regular Annually Cash Distributions Per Unit	$ 2.6875
Partners' Capital Account, Units, Percentage	10.75%
Preferred Stock Liquidation Preference	$ 25

Cash Distributions (Schedule of

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

1 Months Ended

3 Months Ended

12 Months Ended

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

Feb. 28, 2015

Jan. 31, 2015

Dec. 31, 2014

Nov. 30, 2014

Oct. 31, 2014

Sep. 30, 2014

Aug. 31, 2014

Jul. 31, 2014

Jun. 30, 2014

May. 31, 2014

Apr. 30, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Jan. 14, 2016

Oct. 14, 2015

Jul. 14, 2015

Apr. 14, 2015

Jan. 14, 2015

Dec. 31, 2015

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

$ 0.1933

$ 0.5800

$ 0.5600

$ 0.5400

$ 0.5100

Preferred Class B

Distribution Made To Limited Partner [Line Items]

Preferred Units Outstanding

0

Common Limited Partners' Interests

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

$ 12,719

$ 12,718

$ 34,489

$ 33,291

$ 32,097

$ 22,428

Preferred Limited Partners' Interest

Distribution Made To Limited Partner [Line Items]

Distribution Made to Limited Partner, Cash Distributions Paid

638

637

637

637

638

637

643

642

643

643

643

745

745

1,491

1,492

1,491

1,493

1,492

1,466

1,466

1,466

1,466

1,467

4,400

4,248

2,072

1,957

General Partners' Interest

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

$ 1,054

$ 1,055

$ 1,055

$ 2,891

$ 2,443

$ 1,884

$ 946

Class D Preferred Limited Partners

Distribution Made To Limited Partner [Line Items]

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

$ 0.5390625

$ 0.5390625

$ 0.539063

$ 0.616927

Distribution Made to Limited Partner, Cash Distributions Paid

$ 2,205

$ 2,157

$ 2,156

$ 1,974

Class D Preferred Limited Partners | Subsequent Event

Distribution Made To Limited Partner [Line Items]

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

$ 0.5390625

Distribution Made to Limited Partner, Cash Distributions Paid

$ 2,205

Class E Preferred Limited Partners

Distribution Made To Limited Partner [Line Items]

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

$ 0.671875

$ 0.6793

Distribution Made to Limited Partner, Cash Distributions Paid

$ 172

$ 173

Class E Preferred Limited Partners | Subsequent Event

Distribution Made To Limited Partner [Line Items]

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

$ 0.671875

Distribution Made to Limited Partner, Cash Distributions Paid

$ 172

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 31, 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

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

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 Oct 14, 2015

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Oct. 15, 2015

October 15, 2015 to January 14, 2016

Distribution Made To Limited Partner [Line Items]

Distribution Made to Member or Limited Partner, Distribution Date

Jan. 15, 2016

Benefit Plan (2012 Long Term In

Benefit Plan (2012 Long Term Incentive Plan Narrative) (Details) - 2012 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 Partnership’s 2012 Long-Term Incentive Plan (“2012 LTIP”), effective March 2012, provides incentive awards to officers, employees and directors and employees of the general partner and its affiliates, consultants and joint venture partners (collectively, the “Participants”), who perform services for the Partnership. The 2012 LTIP is administered by the board of the general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “LTIP Committee”). Under the 2012 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 2,900,000 common limited partner units.
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 Plan (2012 LTIP Phantom

Benefit Plan (2012 LTIP Phantom Units Activity) (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]
Distribution equivalent rights paid on unissued units under incentive plans		$ 558,000		$ 2,158,000		$ 1,939,000
Partnership 2012 Long Term Incentive Plans - Phantom Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Distribution equivalent rights paid on unissued units under incentive plans		$ 700,000		$ 2,000,000		$ 1,900,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights		Phantom units granted under the 2012 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
Outstanding, beginning of year (Units)		799,192	[1],[2]	839,808	[1],[2]	948,476
Granted (Units)		9,730		264,173		145,813
Vested and issued (Units)	[3]	(472,278)		(274,414)		(215,981)
Forfeited (Units)		(34,539)		(30,375)		(38,500)
Outstanding, end of year (Units)	[1],[2]	302,105		799,192		839,808
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 year	[1],[2]	$ 20.87		$ 22.70		$ 24.31
Non-cash compensation expense recognized		$ 4,124		$ 6,367		$ 9,166
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 units		$ 1,800,000
Unrecognized compensation expenses related to unvested, expected weighted average period		1 year 6 months
Partnership 2012 Long Term Incentive Plans - Phantom Units | 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%
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		4 years
[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 Partnership’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 Plan (2012 Unit Option

Benefit Plan (2012 Unit Option Activity) (Details) - Partnership 2012 Long Term Incentive Plans - 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 restrictions applicable to an 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 2012 LTIP generally will vest 25% on each of the next four anniversaries of the date of grant.
Share Based Compensation Arrangement By Share Based Payment Award Fair Value Assumptions Outstanding Options To Vest Within Next Twelve Months		80,038
Years From Date Of Grant Unit Option Awards Expire		10 years
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, end of year (Units)	[3]	1,273,487		730,775		370,700
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 period	[3]	$ 24.67		$ 24.67		$ 24.67
Non-cash compensation expense recognized		$ 820,000		$ 1,700,000		$ 3,514,000
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
Aggregate Intrinsic Value Of Options Exercisable		$ 0		$ 0		$ 0
Unrecognized compensation expense related to unvested unit options		$ 44,000
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used		The Partnership used the Black-Scholes option pricing model, which is based on Level 3 inputs, to estimate the weighted average fair value of options granted.
Unrecognized compensation expenses related to unvested, expected weighted average period		4 months 24 days
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						$ 2.95
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 Units - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units, granted	0	0	0
Units, issued	0	0	0
Units, outstanding	0	0	0

Operating Segment Information81

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

Operating Segment Information82

Operating Segment Information (Operating Segment Data) (Details) - USD ($) $ in Thousands		3 Months Ended																12 Months Ended
		Dec. 31, 2015	[1],[2]	Sep. 30, 2015	[1],[2]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2014	[3],[4]	Sep. 30, 2014	[3]	Jun. 30, 2014	[3]	Mar. 31, 2014	[3]	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenues		$ 142,424		$ 257,895		$ 96,125		$ 243,589		$ 194,701		$ 206,699		$ 138,897		$ 161,357		$ 740,033	$ 701,654	$ 474,476
Depreciation, depletion and amortization expense																		(157,978)	(239,923)	(139,783)
Asset impairment																		(966,635)	(573,774)	(38,014)
Segment income (loss)																		(639,534)	(470,726)	23,069
Gas And Oil Production
Segment Reporting Information [Line Items]
Revenues	[5]																	624,222	472,870	273,604
Operating costs and expenses																		(169,653)	(182,226)	(100,098)
Depreciation, depletion and amortization expense																		(145,161)	(229,482)	(132,727)
Asset impairment																		(966,635)	(573,774)	(38,014)
Segment income (loss)																		(657,227)	(512,612)	2,765
Well Construction And Completion
Segment Reporting Information [Line Items]
Revenues																		76,505	173,564	167,883
Operating costs and expenses																		(66,526)	(150,925)	(145,985)
Segment income (loss)																		9,979	22,639	21,898
Other Partnership Management
Segment Reporting Information [Line Items]
Revenues	[6]																	39,306	55,220	32,989
Operating costs and expenses	[6]																	(18,775)	(25,532)	(27,527)
Depreciation, depletion and amortization expense	[6]																	(12,817)	(10,441)	(7,056)
Segment income (loss)																		$ 7,714	$ 19,247	$ (1,594)
[1]	For the second, third, and fourth quarters of the year ended December 31, 2015, approximately 469,000, 346,000 and 309,000 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. For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
[2]	Includes asset impairment charges of $672.2 million and $294.4 million in the third and fourth quarters of 2015, respectively.
[3]	For the first, second, third, and fourth quarters of the year ended December 31, 2014, approximately 820,000, 724,000, 797,000, and 791,000 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. For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
[4]	Includes an asset impairment charge of $573.8 million in the fourth quarter of 2014.
[5]	Gas and oil production segment revenues include gains on mark to market derivatives.
[6]	Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information.

Operating Segment Information83

Operating Segment Information (Reconciliation of Segment Income (loss) to Net Income (Loss) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total segment income (loss)		$ (639,534)	$ (470,726)	$ 23,069
General and administrative expenses	[1]	(65,968)	(72,349)	(78,063)
Interest expense	[1]	(102,133)	(62,144)	(34,324)
Loss on asset sales and disposal	[1]	(1,181)	(1,869)	(987)
Net loss		(808,816)	(607,088)	(90,305)
Gas And Oil Production
Segment Reporting Information [Line Items]
Total segment income (loss)		(657,227)	(512,612)	2,765
Well Construction And Completion
Segment Reporting Information [Line Items]
Total segment income (loss)		9,979	22,639	21,898
Other Partnership Management
Segment Reporting Information [Line Items]
Total segment income (loss)		$ 7,714	$ 19,247	$ (1,594)
[1]	Gain (loss) on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to reportable segments as it would be impracticable to reasonably do so for the periods presented.

Operating Segment Information84

Operating Segment Information (Reconciliation of Segment Revenues to Total Revenues) (Details) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2015

[1],[2]

Sep. 30, 2015

[1],[2]

Jun. 30, 2015

[1]

Mar. 31, 2015

[1]

Dec. 31, 2014

[3],[4]

Sep. 30, 2014

[3]

Jun. 30, 2014

[3]

Mar. 31, 2014

[3]

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Segment Reporting Information [Line Items]

Total revenues

$ 142,424

$ 257,895

$ 96,125

$ 243,589

$ 194,701

$ 206,699

$ 138,897

$ 161,357

$ 740,033

$ 701,654

$ 474,476

Gas And Oil Production

Segment Reporting Information [Line Items]

Total revenues

[5]

624,222

472,870

273,604

Well Construction And Completion

Segment Reporting Information [Line Items]

Total revenues

76,505

173,564

167,883

Other Partnership Management

Segment Reporting Information [Line Items]

Total revenues

[6]

$ 39,306

$ 55,220

$ 32,989

[1]

For the second, third, and fourth quarters of the year ended December 31, 2015, approximately 469,000, 346,000 and 309,000 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. For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.

[2]

Includes asset impairment charges of $672.2 million and $294.4 million in the third and fourth quarters of 2015, respectively.

[3]

For the first, second, third, and fourth quarters of the year ended December 31, 2014, approximately 820,000, 724,000, 797,000, and 791,000 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. For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.

[4]

Includes an asset impairment charge of $573.8 million in the fourth quarter of 2014.

[5]

Gas and oil production segment revenues include gains on mark to market derivatives.

[6]

Includes revenues and expenses from well services, gathering and processing, administration and oversight, and other, net that do not meet the quantitative threshold for reporting segment information.

Operating Segment Information85

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	$ 127,138	$ 212,728	$ 263,886
Gas And Oil Production
Segment Reporting Information [Line Items]
Capital expenditures	111,329	193,131	238,291
Other Partnership Management
Segment Reporting Information [Line Items]
Capital expenditures	14,050	14,202	17,032
Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 1,759	$ 5,395	$ 8,563

Operating Segment Information86

Operating Segment Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Goodwill, net	$ 13,639	$ 13,639
Total assets	1,731,004	2,798,120
Gas And Oil Production
Segment Reporting Information [Line Items]
Total assets	1,551,450	2,601,171
Well Construction And Completion
Segment Reporting Information [Line Items]
Goodwill, net	6,389	6,389
Total assets	27,039	39,558
Other Partnership Management
Segment Reporting Information [Line Items]
Goodwill, net	7,250	7,250
Total assets	66,641	65,896
Corporate and Other
Segment Reporting Information [Line Items]
Total assets	$ 85,874	$ 91,495

Subsequent Events (Senior Note

Subsequent Events (Senior Note Repurchases) (Details) - USD ($) $ in Millions	2 Months Ended	3 Months Ended
	Feb. 29, 2016	Mar. 31, 2016
Scenario, Forecast
Subsequent Event [Line Items]
Gain on early extinguishment of debt		$ 25.9
Subsequent Event
Subsequent Event [Line Items]
Payment for repurchase of senior notes	$ 5.5
Subsequent Event | 7.75% Senior Notes
Subsequent Event [Line Items]
Debt instrument repurchased, amount	20.3
Subsequent Event | 9.25% Senior Notes
Subsequent Event [Line Items]
Debt instrument repurchased, amount	$ 12.1

Subsequent Events (Cash Distrib

Subsequent Events (Cash Distribution) (Details) - USD ($)	Feb. 24, 2016	Jan. 28, 2016	Jan. 15, 2016	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	Feb. 28, 2015	Jan. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Oct. 31, 2014	Sep. 30, 2014	Aug. 31, 2014	Jul. 31, 2014	Jun. 30, 2014	May. 31, 2014	Apr. 30, 2014	Mar. 31, 2014	Feb. 28, 2014	Jan. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
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	$ 0.1933	$ 0.5800	$ 0.5600	$ 0.5400	$ 0.5100
General Partners' Interest
Subsequent Event [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid				$ 39,000	$ 39,000	$ 239,000	$ 236,000	$ 229,000	$ 223,000	$ 223,000	$ 221,000	$ 206,000	$ 204,000	$ 203,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,378,000	$ 1,377,000	$ 1,279,000	$ 1,279,000	$ 1,054,000	$ 1,055,000	$ 1,055,000	$ 2,891,000	$ 2,443,000	$ 1,884,000	$ 946,000
Subsequent Event | Cash Distribution Declared
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Declaration Date	Feb. 24, 2016	Jan. 28, 2016
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.0125	$ 0.0125
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
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. 8, 2016
Subsequent Event | Cash Distribution Paid | Class C Convertible Preferred Units
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 600,000	$ 600,000
Subsequent Event | Cash Distribution Paid | Class D Cumulative Redeemable Perpetual Preferred Units
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Date of Record			Jan. 4, 2016
Preferred Unit Regular Quarterly Cash Distributions Per Unit			$ 0.5390625
Distribution Made to Limited Partner, Cash Distributions Paid			$ 2,200,000
Subsequent Event | Cash Distribution Paid | Class E Cumulative Redeemable Perpetual Preferred Units
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Date of Record			Jan. 4, 2016
Preferred Unit Regular Quarterly Cash Distributions Per Unit			$ 0.671875
Distribution Made to Limited Partner, Cash Distributions Paid			$ 200,000
Subsequent Event | Cash Distribution Paid | General Partners' Interest
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 39,000	$ 39,000

Subsequent Events (NYSE Complia

Subsequent Events (NYSE Compliance) (Details) - Subsequent Event	Jan. 12, 2016$ / shares
Subsequent Event [Line Items]
Number of consecutive trading days	30 days
Maximum
Subsequent Event [Line Items]
Average closing price for common unit	$ 1

Supplemental Oil and Gas Info90

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
Reserve Quantities [Line Items]
Balance | Mcf		1,056,384,780	1,003,538,038	573,774,257
Extensions, discoveries and other additions | Mcf	[1]	6,441,969	58,454,544	90,098,219
Sales of reserves in-place | Mcf		(2,713,428)	(169,035)	(2,755,155)
Purchase of reserves in-place | Mcf	[2]	3,555,062	82,279,988	493,232,119
Transfers to limited partnerships | Mcf		(2,958,882)	(4,887,095)	(2,485,210)
Revisions | Mcf	[3]	(377,067,441)	3,805,952	(88,484,468)
Production | Mcf		(79,063,564)	(86,637,612)	(59,841,724)
Balance | Mcf		604,578,496	1,056,384,780	1,003,538,038
Proved developed reserves | Mcf		567,992,268	887,818,577	766,630,929	338,655,325
Proved undeveloped reserves | Mcf		36,586,228	168,566,203	236,907,109	235,118,932
Oil
Reserve Quantities [Line Items]
Balance		48,018,176	14,988,802	8,868,836
Extensions, discoveries and other additions	[1]	2,492,424	3,372,177	8,255,531
Sales of reserves in-place		(2,393)	(1,519)
Purchase of reserves in-place	[2]	8,645,686	36,538,935	1,942
Transfers to limited partnerships		(481,771)	(684,613)	(239,910)
Revisions	[3]	(11,992,308)	(4,941,359)	(1,412,371)
Production		(1,875,654)	(1,254,247)	(485,226)
Balance		44,804,160	48,018,176	14,988,802
Proved developed reserves		25,484,491	30,537,868	3,459,238	3,400,447
Proved undeveloped reserves		19,319,669	17,480,308	11,529,564	5,468,389
Natural Gas Liquids
Reserve Quantities [Line Items]
Balance		21,757,477	18,957,016	16,061,897
Extensions, discoveries and other additions	[1]	218,726	3,986,986	8,197,272
Sales of reserves in-place			(11,326)	(4,625)
Purchase of reserves in-place	[2]	653,416	3,567,531	55,187
Transfers to limited partnerships		(342,156)	(665,486)	(258,381)
Revisions	[3]	(13,382,104)	(2,689,379)	(3,826,744)
Production		(1,055,345)	(1,387,865)	(1,267,590)
Balance		7,850,014	21,757,477	18,957,016
Proved developed reserves		6,334,327	12,004,774	7,676,389	7,884,778
Proved undeveloped reserves		1,515,687	9,752,703	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 the Rangely, Eagle Ford and Geomet Acquisitions. For the year ended December 31, 2013, the increase was primarily due to the addition of Marble Falls wells.
[2]	Represents purchase of proved reserves in the Rangely, Eagle Ford and GeoMet Acquisitions for the year ended December 31, 2014.
[3]	The downward revisions for the year ended December 31, 2015 were primarily due to unfavorable economic conditions primarily related to gas and oil commodity prices. For the year ended December 31, 2014, the downward revision on oil and NGL was primarily due to production underperforming previous year’s forecasts. The upward revision for the year ended December 31, 2014 on gas was primarily due to production outperforming previous year’s forecast.  The downward revisions for the year ended December 31, 2013 were primarily due to a reduction of the Partnership’s five year drilling plans in the Barnett Shale and pricing scenario revisions.

Supplemental Oil and Gas Info91

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	$ 3,585,839	$ 3,475,187
Unproved properties	213,047	217,321
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	3,585,839	3,475,186
Unproved properties	213,047	217,322
Support equipment	44,921	37,359
Total natural gas and oil properties	3,843,807	3,729,867
Accumulated depreciation, depletion and amortization	(2,691,692)	(1,509,509)
Net capitalized costs	$ 1,152,115	$ 2,220,358

Supplemental Oil and Gas Info92

Supplemental Oil and Gas Information (Schedule of Results of Operations from Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Revenues				$ 356,999		$ 470,051		$ 273,604
Production costs				(169,653)		(182,226)		(100,098)
Depletion				(145,161)		(229,482)		(132,727)
Long-lived asset impairment	$ (294,400)	$ (672,200)	$ (573,800)	(966,635)	[1]	(573,774)	[1]	(38,014)	[1]
Results of Operations, Income before Income Taxes, Total				(924,450)		(515,431)		2,765
Asset impairment				(966,635)		(573,774)		$ (38,014)
Reclassification out of Accumulated Other Comprehensive Income
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Future hedge gains reclassified from accumulated other comprehensive income				$ 85,800		82,300
Appalachian Basin
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Asset impairment						(555,700)
Goodwill impairment						$ 18,100
[1]	During the year ended December 31, 2015, the Partnership recognized $966.6 million of asset impairment primarily related to 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 Partnership recognized $573.8 million of asset impairment primarily consisting of $555.7 million related to oil and gas properties within property, plant, and equipment, net on its consolidated balance sheet for its 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 of goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, the Partnership 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 Info93

Supplemental Oil and Gas Information (Schedule of Costs Incurred in Oil and Gas Producing Activities) (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)Wells	Dec. 31, 2014USD ($)Wells	Dec. 31, 2013USD ($)Wells
Supplemental Oil and Gas Information (Unaudited) [Abstract]
Proved properties		$ 11,513	$ 699,451	$ 859,827
Unproved properties		43,820	10,978	895
Exploration costs	[1]	1,601	722	1,053
Development costs		73,288	164,853	214,383
Total costs incurred in oil & gas producing activities		$ 130,222	$ 876,004	$ 1,076,158
Number of exploratory wells drilled | Wells		0	0	0
[1]	There were no exploratory wells drilled during the years ended December 31, 2015, 2014 and 2013.

Supplemental Oil and Gas Info94

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	$ 3,514,198	$ 9,317,915	$ 5,259,688
Future production costs	(1,836,779)	(4,188,364)	(2,393,814)
Future development costs	(1,156,367)	(1,157,305)	(752,349)
Future net cash flows	521,052	3,972,246	2,113,525
Less 10% annual discount for estimated timing of cash flows	(18,283)	(1,987,975)	(1,037,343)
Standardized measure of discounted future net cash flows	$ 502,769	$ 1,984,271	$ 1,076,182

Supplemental Oil and Gas Info95

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		$ 1,984,271	$ 1,076,182	$ 623,676
Sales of oil and gas produced, net of related costs	[1]	(129,352)	(272,961)	(171,300)
Net changes in prices and production costs	[2]	(1,453,854)	339,718	85,191
Revisions of previous quantity estimates		(52,775)	4,352	(1,880)
Development costs incurred		58,117	52,077	27,245
Changes in future development costs		(152,305)	(90,887)	(21,579)
Transfers to limited partnerships		(13,291)	(2,966)	(53,392)
Extensions, discoveries, and improved recovery less related costs		13,980	60,832	143,338
Purchases of reserves in-place	[3]	53,102	737,101	513,744
Sales of reserves in-place		(2,162)	(332)	(2,053)
Accretion of discount		198,427	107,618	62,368
Estimated settlement of asset retirement obligations		(216)	(16,708)	(18,823)
Estimated proceeds on disposals of well equipment		(1,173)	(21,906)	17,039
Changes in production rates (timing) and other			12,151	(127,392)
Outstanding, end of year		$ 502,769	$ 1,984,271	$ 1,076,182
[1]	(1) Includes the amount of sales of oil and gas previously included in proved reserves and sold during the period ended.
[2]	(1) 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 the Rangely, Eagle Ford and 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) - 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	[1]	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	$ 142,424	[1],[2]	$ 257,895	[1],[2]	$ 96,125	[1]	$ 243,589		$ 194,701	[3],[4]	$ 206,699	[3]	$ 138,897	[3]	$ 161,357	[3]	$ 740,033		$ 701,654		$ 474,476
Net loss attributable to common limited partners and the general partner’s interests	(293,013)	[1],[2]	(565,147)	[1],[2]	(51,044)	[1],[2]	83,919	[2]	(585,499)	[3],[4]	(2,590)	[3],[4]	(23,803)	[3],[4]	(14,463)	[3],[4]	(825,285)		(626,355)		(102,297)
Allocation of net income (loss) attributable to common limited partners and the general partner:
Common limited partners’ interest	(287,153)	[1],[2]	(553,844)	[1],[2]	(50,023)	[1]	82,240		(576,850)	[3],[4]	(5,599)	[3]	(26,203)	[3]	(16,481)	[3]	(808,780)		(625,133)		(105,661)
General partner’s interest	(5,860)	[1],[2]	(11,303)	[1],[2]	(1,021)	[1]	1,679		(8,649)	[3],[4]	3,009	[3]	2,400	[3]	2,018	[3]	(16,505)		(1,222)		3,364
Net loss attributable to common limited partners and the general partner	$ (293,013)	[1],[2]	$ (565,147)	[1],[2]	$ (51,044)	[1],[2]	$ 83,919	[2]	$ (585,499)	[3],[4]	$ (2,590)	[3],[4]	$ (23,803)	[3],[4]	$ (14,463)	[3],[4]	$ (825,285)		$ (626,355)		$ (102,297)
Basic	$ (2.81)	[1],[2]	$ (5.73)	[1],[2]	$ (0.55)	[1]	$ 0.95		$ (7.04)	[3],[4]	$ (0.07)	[3]	$ (0.35)	[3]	$ (0.27)	[3]
Diluted	$ (2.81)	[1],[2]	$ (5.73)	[1],[2]	$ (0.55)	[1]	$ 0.93		$ (7.04)	[3],[4]	$ (0.07)	[3]	$ (0.35)	[3]	$ (0.27)	[3]	$ (8.63)		$ (8.37)		$ (2.01)
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units	309,000		346,000		469,000				820,000		724,000		797,000		791,000
All Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units																	For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.		For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
Asset impairment charges	$ 294,400		$ 672,200						$ 573,800								$ 966,635	[5]	$ 573,774	[5]	$ 38,014	[5]
[1]	For the second, third, and fourth quarters of the year ended December 31, 2015, approximately 469,000, 346,000 and 309,000 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. For the second, third, and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2015, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
[2]	Includes asset impairment charges of $672.2 million and $294.4 million in the third and fourth quarters of 2015, respectively.
[3]	For the first, second, third, and fourth quarters of the year ended December 31, 2014, approximately 820,000, 724,000, 797,000, and 791,000 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. For the first, second, third, and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s Class B and Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive. For the first, second, third and fourth quarters of the year ended December 31, 2014, potential common limited partner units issuable upon exercise of the common unit warrants issued with the Class C preferred units were excluded from the computation of diluted earnings attributable to common limited partners per unit, because the inclusion of such units would have been anti-dilutive.
[4]	Includes an asset impairment charge of $573.8 million in the fourth quarter of 2014.
[5]	During the year ended December 31, 2015, the Partnership recognized $966.6 million of asset impairment primarily related to 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 Partnership recognized $573.8 million of asset impairment primarily consisting of $555.7 million related to oil and gas properties within property, plant, and equipment, net on its consolidated balance sheet for its 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 of goodwill impairment resulting from the decline in overall commodity prices. During the year ended December 31, 2013, the Partnership 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