Titan Energy 10-Q 7 May 14 2014 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	5-May-14
Document Document And Entity Information [Line Items]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
Entity Registrant Name	'Atlas Resource Partners, L.P.	'
Entity Central Index Key	'0001532750	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Units Outstanding	'	65,797,358
Trading Symbol	'ARP	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$1,965	$1,828
Accounts receivable	78,127	58,822
Current portion of derivative asset	161	1,891
Subscriptions receivable	'	47,692
Prepaid expenses and other	17,481	10,097
Total current assets	97,734	120,330
Property, plant and equipment, net	2,125,189	2,120,818
Goodwill and intangible assets, net	32,679	32,747
Long-term derivative asset	23,749	27,084
Other assets, net	42,554	42,821
Total assets	2,321,905	2,343,800
Current liabilities:	'	'
Accounts payable	94,472	69,346
Advances from affiliates	24,413	26,742
Liabilities associated with drilling contracts	'	49,377
Current portion of derivative liability	22,372	6,353
Accrued well drilling and completion costs	66,199	40,481
Accrued interest	7,843	20,622
Accrued liabilities	31,118	30,794
Total current liabilities	246,417	243,715
Long-term debt	889,388	942,334
Asset retirement obligations	91,389	89,776
Other long-term liabilities	721	684
Commitments and contingencies	'	'
Partners’ Capital:	'	'
General partner’s interest	1,485	4,482
Preferred limited partners’ interests	180,543	183,477
Class C common limited partner warrants	1,176	1,176
Common limited partners’ interests	905,888	852,457
Accumulated other comprehensive income	4,898	25,699
Total partners’ capital	1,093,990	1,067,291
Total liabilities and partners' capital	$2,321,905	$2,343,800

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Revenues:	'		'
Gas and oil production	$96,245		$46,064
Well construction and completion	49,377		56,478
Gathering and processing	4,468		3,585
Administration and oversight	1,729		1,085
Well services	5,479		4,816
Other, net	47		20
Total revenues	157,345		112,048
Costs and expenses:	'		'
Gas and oil production	36,792		15,216
Well construction and completion	42,936		49,112
Gathering and processing	4,413		4,413
Well services	2,482		2,318
General and administrative	16,455	[1]	17,567	[1]
Depreciation, depletion and amortization	50,237		21,208
Total costs and expenses	153,315		109,834
Operating income	4,030		2,214
Interest expense	-13,188	[1]	-6,889	[1]
Loss on asset sales and disposal	-1,603	[1]	-702	[1]
Net loss	-10,761		-5,377
Preferred limited partner dividends	-4,399		-1,957
Net loss attributable to common limited partners and the general partner	-15,160		-7,334
Allocation of net income (loss) attributable to common limited partners and the general partner:	'		'
Common limited partners’ interest	-17,164		-7,635
General partner’s interest	2,004		301
Net loss attributable to common limited partners and the general partner	($15,160)		($7,334)
Net loss attributable to common limited partners per unit:	'		'
Basic and Diluted	($0.28)		($0.17)
Weighted average common limited partner units outstanding:	'		'
Basic and Diluted	61,219		43,974
[1]	Loss on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Net loss	($10,761)	($5,377)
Other comprehensive income (loss):	'	'
Changes in fair value of derivative instruments accounted for as cash flow hedges	-34,844	-24,944
Less: reclassification adjustment for realized (gains) losses of cash flow hedges in net loss	14,043	-993
Total other comprehensive loss	-20,801	-25,937
Comprehensive loss attributable to common and preferred limited partners and the general partner	($31,562)	($31,314)

Consolidated_Statements_of_Par

Consolidated Statements of Partners' Capital (USD $)	Total	General Partners’ Interest	Preferred Limited Partners Interests	Preferred Limited Partners Interests	Common Limited Partners’ Interests	Class C Common Limited Partner Warrants	Accumulated Other Comprehensive Income
In Thousands, except Share data		General Class A	Preferred Class B	Preferred Class C
Balance at Dec. 31, 2013	$1,067,291	$4,482	$96,539	$86,938	$852,457	$1,176	$25,699
Balance (units) at Dec. 31, 2013	'	1,368,058	3,836,554	3,749,986	59,448,308	562,497	'
Issuance of units	129,011	'	'	'	129,011	'	'
Issuance of units (units)	'	129,538	'	'	6,325,000	'	'
Issuance of common units under incentive plans	'	'	'	'	'	'	'
Issuance of common units under incentive plans (units)	'	'	'	'	22,375	'	'
Unissued common units under incentive plans	2,300	'	'	'	2,300	'	'
Distributions payable	-15,396	-1,055	-742	-724	-12,875	'	'
Distributions paid to common and preferred limited partners and the general partner	-57,020	-3,946	-2,967	-2,900	-47,207	'	'
Distribution equivalent rights paid on unissued units under incentive plan	-634	'	'	'	-634	'	'
Net loss	-10,761	2,004	2,224	2,175	-17,164	'	'
Other comprehensive loss	-20,801	'	'	'	'	'	-20,801
Balance at Mar. 31, 2014	$1,093,990	$1,485	$95,054	$85,489	$905,888	$1,176	$4,898
Balance (units) at Mar. 31, 2014	'	1,497,596	3,836,554	3,749,986	65,795,683	562,497	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'		'
Net loss	($10,761)		($5,377)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:	'		'
Depreciation, depletion and amortization	50,237		21,208
Loss on asset sales and disposal	1,603	[1]	702	[1]
Non-cash compensation expense	2,344		4,247
Amortization of deferred financing costs	1,758		4,644
Changes in operating assets and liabilities:	'		'
Accounts receivable, prepaid expenses and other	16,111		40,828
Accounts payable and accrued liabilities	-38,611		-66,936
Net cash provided by (used in) operating activities	22,681		-684
CASH FLOWS FROM INVESTING ACTIVITIES:	'		'
Capital expenditures	-39,897		-58,487
Other	-514		11
Net cash used in investing activities	-40,411		-58,476
CASH FLOWS FROM FINANCING ACTIVITIES:	'		'
Borrowings under credit facilities	162,000		121,000
Repayments under credit facilities	-215,000		-327,425
Net proceeds from issuance of long-term debt	'		267,926
Distributions paid to unitholders	-57,020		-23,566
Net proceeds from issuance of common limited partner units	129,011		'
Deferred financing costs, distribution equivalent rights and other	-1,124		-825
Net cash provided by financing activities	17,867		37,110
Net change in cash and cash equivalents	137		-22,050
Cash and cash equivalents, beginning of year	1,828		23,188
Cash and cash equivalents, end of period	$1,965		$1,138
[1]	Loss on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

Basis_of_Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2014
Basis of Presentation	'
	NOTE 1 – BASIS OF PRESENTATION
	Atlas Resource Partners, L.P. (the “Partnership”) is a publicly traded Delaware master-limited partnership (NYSE: ARP) and an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States. 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. At March 31, 2014, Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS), owned 100% of the general partner Class A units, all of the incentive distribution rights through which it manages and effectively controls the Partnership and an approximate 33.7% limited partner interest (20,962,485 common and 3,749,986 preferred limited partner units) in the Partnership.
	The Partnership was formed in October 2011 to own and operate substantially all of ATLS’ exploration and production assets (“Atlas Energy E&P Operations”), which were transferred to the Partnership on March 5, 2012. In February 2012, the board of ATLS’ general partner approved the distribution of approximately 5.24 million of the Partnership’s common units which were distributed on March 13, 2012 to ATLS’ unitholders using a ratio of 0.1021 of the Partnership’s limited partner units for each of ATLS’ common units owned on the record date of February 28, 2012.
	The accompanying consolidated financial statements, which are unaudited except that the balance sheet at December 31, 2013 is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim consolidated financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation. The results of operations for the three months ended March 31, 2014 may not necessarily be indicative of the results of operations for the full year ending December 31, 2014.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2014
Summary of Significant Accounting Policies	'
	NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Principles of Consolidation
	The Partnership’s consolidated balance sheets at March 31, 2014 and December 31, 2013 and the consolidated statements of operations for the three months ended March 31, 2014 and 2013 include the accounts of the Partnership and its wholly-owned subsidiaries. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheets and related consolidated statements of operations. Actual balances and results could be different from those estimates. 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.
	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 as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.
	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. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”).
	Receivables
	Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Partnership’s customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At March 31, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.
	Inventory
	The Partnership had $9.6 million and $4.6 million of inventory at March 31, 2014 and December 31, 2013, 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.
	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 which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which 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 Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount 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 futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, 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 the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. 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 partner 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.
	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, 2013, the Partnership recognized $13.5 million of asset impairments related to its 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 three months ended March 31, 2014 and 2013.
	Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, the Partnership recognized $24.5 million of asset impairments related to its 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. There were no impairments of proved gas and oil properties recorded by the Partnership for the three months ended March 31, 2014 and 2013.
	The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2013 and management’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
	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 5.6% and 6.2% for the three months ended March 31, 2014 and 2013, respectively. The aggregate amount of interest capitalized by the Partnership was $2.6 million and $3.4 million for the three months ended March 31, 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 following table reflects the components of intangible assets being amortized at March 31, 2014 and December 31, 2013 (in thousands):
			March 31,			December 31,			Estimated
									Useful Lives
			2014			2013			In Years
	Gross Carrying Amount		$	14,344		$	14,344			13
	Accumulated Amortization			(13,449	)		(13,381	)
	Net Carrying Amount		$	895		$	963
	Amortization expense on intangible assets was $0.1 million for both the three months ended March 31, 2014 and 2013. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $0.3 million; 2015 - $0.2 million; 2016 - $0.1 million, 2017 - $0.1 million and 2018 - $0.1 million.
	Goodwill
	At March 31, 2014 and December 31, 2013, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three months ended March 31, 2014 and 2013.
	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 and the available market data of the industry group. 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. During the three months ended March 31, 2014 and 2013, no impairment indicators arose, and no goodwill impairments were recognized by the Partnership.
	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 accompanying 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 accompanying 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 three months ended March 31, 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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 31, 2014.
	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 when considered in the calculation of earnings per unit under the two-class method. 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 share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. 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 loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data):
			Three Months Ended
			March 31,
			2014			2013
	Net loss		$	(10,761	)	$	(5,377	)
	Preferred limited partner dividends			(4,399	)		(1,957	)
	Net loss attributable to common limited partners and the general partner			(15,160	)		(7,334	)
	Less: General partner’s interest			(2,004	)		(301	)
	Net loss attributable to common limited partners			(17,164	)		(7,635	)
	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		$	(17,164	)	$	(7,635	)
	(1)	Net income 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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 820,000 and 998,000 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.
	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 method. 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):
		Three Months Ended
		March 31,
		2014			2013
Weighted average number of common limited partner units - basic			61,219			43,974
Add effect of dilutive incentive awards(1)			—			—
Add effect of dilutive convertible preferred limited partner units and warrants(2)			—			—
Weighted average number of common limited partner units - diluted			61,219			43,974
(1)	For the three months ended March 31, 2014 and 2013, approximately 820,000 units and 998,000 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 three months ended March 31, 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 three months ended March 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s 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 three months ended March 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.
Revenue Recognition
Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within its consolidated statements of operations.
The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
The Partnership accrues 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 from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues at March 31, 2014 and December 31, 2013 $83.0 million and $55.3 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.
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 Shale and the Chattanooga Shale. 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%.
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 at March 31, 2014, 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 Adopted Accounting Standards
In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.
In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2014
Acquisitions	'
	NOTE 3 – ACQUISITIONS
	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 (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.
	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. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date.
	The following table presents the preliminary 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		723,657
	Total current assets	$	728,925
	Liabilities:
	Accounts payable		2,562
	Asset retirement obligation		16,728
	Total liabilities assumed		19,290
	Net assets acquired	$	709,635
	Other Acquisitions
	On February 13, 2014, the Partnership entered into a definitive asset purchase and sale agreement to acquire certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $107.0 million in cash with an effective date of January 1, 2014, subject to certain purchase price adjustments. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia. On May 5, 2014, closing of the transaction was approved by GeoMet’s shareholder vote, and is expected to occur during the second quarter of 2014, subject to certain customary closing conditions.
	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	3 Months Ended
	Mar. 31, 2014
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):
		March 31,			December 31,			Estimated
								Useful Lives
		2014			2013			in Years
	Natural gas and oil properties:
	Proved properties:
	Leasehold interests	$	321,179		$	320,459
	Pre-development costs		4,038			4,367
	Wells and related equipment		2,204,347			2,164,760
	Total proved properties		2,529,564			2,489,586
	Unproved properties		216,598			211,536
	Support equipment		26,403			23,005
	Total natural gas and oil properties		2,772,565			2,724,127
	Pipelines, processing and compression facilities		43,135			42,949			2 – 40
	Rights of way		829			830			20 – 40
	Land, buildings and improvements		8,981			9,462			3 – 40
	Other		16,185			15,318			3 – 10
			2,841,695			2,792,686
	Less – accumulated depreciation, depletion and amortization		(716,506	)		(671,868	)
		$	2,125,189		$	2,120,818
	During the three months ended March 31, 2014, the Partnership recognized $1.6 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 three months ended March 31, 2013, the Partnership recognized $0.7 million of loss on asset disposal pertaining to its decision not to drill wells on leasehold property that expired during the three months ended March 31, 2013 in Indiana and Tennessee.
	During the year ended December 31, 2013, the Partnership recognized $38.0 million of asset impairments related to its oil and gas properties within property, plant and equipment, net on its consolidated balance sheet primarily for its shallow natural gas wells in the New Albany Shale and unproved acreage in the Chattanooga and New Albany Shales. These impairments related to the carrying amounts of gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2013, and management’s intention not to drill on certain expiring unproved acreage. The estimate of fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.

Other_Assets

Other Assets (Noncurrent)	3 Months Ended
	Mar. 31, 2014
Noncurrent	'
Other Assets	'
	NOTE 5 – OTHER ASSETS
	The following is a summary of other assets at the dates indicated (in thousands):
		March 31,		December 31,
		2014		2013
	Deferred financing costs, net of accumulated amortization of $13,706 and $11,948 at March 31, 2014 and December 31, 2013, respectively	$	34,077	$	35,292
	Notes receivable		4,012		3,978
	Long-term derivative asset receivable from Drilling Partnerships		1,007		863
	Other		3,458		2,688
		$	42,554	$	42,821
	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 $1.8 million and $1.4 million for the three months ended March 31, 2014 and 2013, respectively, which was recorded within interest expense on the Partnership’s consolidated statements of operations. During the three months ended March 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 due 2021 (see Note 7).
	At March 31, 2014 and December 31, 2013, 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 the three months ended March 31, 2014, approximately $23,000 of interest income was recognized within other, net on the Partnership’s consolidated statements of operations. There was no interest income recognized for the three months ended March 31, 2013. At March 31, 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	3 Months Ended
	Mar. 31, 2014
Asset Retirement Obligations	'
	NOTE 6 – ASSET RETIREMENT OBLIGATIONS
	The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depreciation, depletion and amortization.
	The estimated liability for asset retirement obligations was based on the Partnership’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability 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 March 31, 2014, the Drilling Partnerships had $57.9 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. During the three months ended March 31, 2014, the Partnership withheld $0.6 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. No amounts were withheld during the three months ended March 31, 2013. 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):
		Three Months Ended
		March 31,
		2014			2013
	Asset retirement obligations, beginning of year	$	89,776		$	64,794
	Liabilities incurred		529			645
	Liabilities settled		(217	)		(7	)
	Accretion expense		1,301			954
	Asset retirement obligations, end of period	$	91,389		$	66,386
	The above accretion expense was included in depreciation, depletion and amortization in the Partnership’s consolidated statements of operations and the asset retirement obligation liabilities were included within asset retirement obligations in the Partnership’s consolidated balance sheets. During the year ended December 31, 2013, the Partnership incurred $16.7 million of future plugging and abandonment costs related to the EP Energy Acquisition it consummated during the period.

Debt

Debt	3 Months Ended
	Mar. 31, 2014
Debt	'
	NOTE 7 - DEBT
	Total debt consists of the following at the dates indicated (in thousands):
		March 31,		December 31,
		2014		2013
	Revolving credit facility	$	366,000	$	419,000
	7.75 % Senior Notes – due 2021		275,000		275,000
	9.25 % Senior Notes – due 2021		248,388		248,334
	Total debt		889,388		942,334
	Less current maturities		—		—
	Total long-term debt	$	889,388	$	942,334
	Credit Facility
	At March 31, 2014, the Partnership has a credit agreement with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (the “Credit Agreement”) that provides for a senior secured revolving credit facility with a maximum facility amount of $1.5 billion scheduled to mature in July 2018. The Partnership’s borrowing base under the credit facility, which was $735.0 million at March 31, 2014, is scheduled for semi-annual redeterminations on May 1 and November 1 of each year. At March 31, 2014, $366.0 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 $3.7 million was outstanding at March 31, 2014. 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 1.75% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and 1.75% per annum. The Partnership is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations. At March 31, 2014, the weighted average interest rate on outstanding borrowings under the credit facility was 2.3%.
	The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Partnership was in compliance with these covenants as of March 31, 2014. The Credit Agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended March 31, 2014 and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ending September 30, 2014, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter 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. Based on the definitions contained in the Partnership’s Credit Agreement, at March 31, 2014, the Partnership’s ratio of current assets to current liabilities was 2.1 to 1.0, and its ratio of Total Funded Debt to EBITDA was 3.9 to 1.0.
	Senior Notes
	On July 30, 2013, the Partnership issued $250.0 million of its 9.25% senior notes due August 15, 2021 (“9.25% Senior Notes”), in a private placement transaction at an offering price of 99.297% of par value, yielding net proceeds of approximately $242.8 million. The net proceeds were used to partially fund the EP Energy Acquisition (see Note 3). The 9.25% Senior Notes were presented net of a $1.6 million unamortized discount as of March 31, 2014. Interest on the 9.25% Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014. 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%. In addition, at any time prior to August 15, 2016, the Partnership may redeem up to 35% of the 9.25% Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. 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.
	In connection with the issuance of the 9.25% Senior Notes due 2021, the Partnership entered into a registration rights agreement, whereby it agreed to (a) file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) to exchange the privately issued notes for registered notes, and (b) cause the exchange offer to be consummated by July 30, 2014. On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.
	On January 23, 2013, the Partnership issued $275.0 million of its 7.75% senior notes due 2021 (“7.75% Senior Notes”) in a private placement transaction at par. The Partnership used the net proceeds of approximately $267.6 million to repay all of the indebtedness and accrued interest outstanding under its then-existing term loan credit facility and a portion of the amounts outstanding under its revolving credit facility. In connection with the retirement of the Partnership’s term loan credit facility and the reduction in its revolving credit facility borrowing base, the Partnership accelerated $3.2 million of amortization expense related to deferred financing costs during the three months ended March 31, 2013 (see Note 5). 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 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 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing 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.
	On July 1, 2013, the Partnership filed a registration statement relating to the exchange offer for the 7.75% Senior Notes and the exchange offer was completed on January 2, 2014.
	The 9.25% Senior Notes and 7.75% Senior Notes are guaranteed by certain of the Partnership’s material subsidiaries. The guarantees under the 9.25% Senior Notes and 7.75% Senior Notes are full and unconditional and joint and several, 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 9.25% Senior Notes and 7.75% Senior Notes contain covenants, including limitations of 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 March 31, 2014.
	Cash payments for interest by the Partnership were $26.5 million and $2.4 million for the three months ended March 31, 2014 and 2013, respectively.

Derivative_Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2014
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 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.
	Management formally documents all relationships between the Partnership’s hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. Management assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which are determined by management of the Partnership through the utilization of market data, will be recognized immediately within other, net in the Partnership’s consolidated statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues within the Partnership’s consolidated statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, management recognizes changes in fair value within other, net in the Partnership’s consolidated statements of operations as they occur.
	The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s 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 reflected net derivative assets on its consolidated balance sheets of $1.5 million and $22.6 million at March 31, 2014 and December 31, 2013, respectively. Of the $4.9 million of net gain in accumulated other comprehensive income on the Partnership’s consolidated balance sheet at March 31, 2014, if the fair values of the instruments remain at current market values, the Partnership will reclassify $22.4 million of losses to gas and oil production revenue on its consolidated statement of operations over the next twelve month period as these contracts expire. Aggregate gains of $27.3 million of gas and oil production revenues will be reclassified to the Partnership’s consolidated statements of operations in later periods as the remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future commodity price changes.  No amounts were reclassified from other comprehensive income related to derivative instruments entered into during the three months ended March 31, 2014 and 2013.
	The following table summarizes the gains recognized in the Partnership’s consolidated statements of operations for effective derivative instruments for the periods indicated (in thousands):
			Three Months Ended
			March 31,
			2014				2013
	(Gain) loss reclassified from accumulated other comprehensive income (loss):
	Gas and oil production revenue		$	14,043			$	(993	)
	Total		$	14,043			$	(993	)
	The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):
	Offsetting Derivative Assets		Gross				Gross				Net Amount of
			Amounts of				Amounts				Assets
			Recognized				Offset in the				Presented in the
			Assets				Consolidated				Consolidated
							Balance Sheets				Balance Sheets
	As of March 31, 2014
	Current portion of derivative assets		$	161			$	—			$	161
	Long-term portion of derivative assets			25,859				(2,110	)			23,749
	Current portion of derivative liabilities			4,382				(4,382	)			—
	Long-term portion of derivative liabilities			114			$	(114	)		$	—
	Total derivative assets		$	30,516				(6,606	)			23,910
	As of December 31, 2013
	Current portion of derivative assets		$	2,664			$	(773	)		$	1,891
	Long-term portion of derivative assets			31,146				(4,062	)			27,084
	Current portion of derivative liabilities			4,341				(4,341	)			—
	Long-term portion of derivative liabilities			122				(122	)			—
	Total derivative assets		$	38,273			$	(9,298	)		$	28,975
	Offsetting Derivative Liabilities		Gross				Gross				Net Amount of
			Amounts of				Amounts				Liabilities
			Recognized				Offset in the				Presented in the
			Liabilities				Consolidated				Consolidated
							Balance Sheets				Balance Sheets
	As of March 31, 2014
	Current portion of derivative assets		$	—			$	—			$	—
	Long-term portion of derivative assets			(2,110	)			2,110				—
	Current portion of derivative liabilities			(26,754	)			4,382				(22,372	)
	Long-term portion of derivative liabilities			(127	)			114				(13	)
	Total derivative liabilities		$	(28,991	)		$	6,606			$	(22,385	)
	As of December 31, 2013
	Current portion of derivative assets		$	(773	)		$	773			$	—
	Long-term portion of derivative assets			(4,062	)			4,062				—
	Current portion of derivative liabilities			(10,694	)			4,341				(6,353	)
	Long-term portion of derivative liabilities			(189	)			122				(67	)
	Total derivative liabilities		$	(15,718	)		$	9,298			$	(6,420	)
	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 New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. 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 have qualified and been designated as cash flow hedges and were recorded at their fair values.
	The Partnership recognized losses of $14.0 million and gains of $1.0 million for the three months ended March 31, 2014 and 2013, respectively, on settled contracts covering commodity production. These gains and losses 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 three months ended March 31, 2014 and 2013, respectively, for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
	At March 31, 2014, the Partnership had the following commodity derivatives:
	Natural Gas Fixed Price Swaps
	Production					Volumes				Average				Fair Value
	Period Ending									Fixed Price				Asset/
	December 31,													(Liability)
						(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
	2014						45,114,700			$	4.152			$	(14,068	)
	2015						51,924,500			$	4.239				1,799
	2016						45,746,300			$	4.311				7,193
	2017						24,840,000			$	4.532				6,734
	2018						3,960,000			$	4.716				1,306
														$	2,964
	Natural Gas Costless Collars
	Production		Option Type			Volumes				Average Floor				Fair Value
	Period Ending									and Cap				Asset/
December 31,										(Liability)
					(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014		Puts purchased				2,880,000			$	4.221			$	642
2014		Calls sold				2,880,000			$	5.12				(418	)
2015		Puts purchased				3,480,000			$	4.234				1,636
2015		Calls sold				3,480,000			$	5.129				(721	)
													$	1,139
Natural Gas Put Options – Drilling Partnerships
Production		Option Type			Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset
December 31,
					(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014		Puts purchased				1,350,000			$	3.8			$	84
2015		Puts purchased				1,440,000			$	4				447
2016		Puts purchased				1,440,000			$	4.15				613
													$	1,144
WAHA Basis Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Liability
December 31,
					(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
2014						8,100,000			$	(0.110	)		$	(42	)
													$	(42	)
Natural Gas Liquids Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset/
December 31,													(Liability)
					(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014						79,500			$	91.568			$	(486	)
2015						96,000			$	88.55				(129	)
2016						84,000			$	85.651				92
2017						60,000			$	83.78				127
													$	(396	)
Natural Gas Liquids Ethane Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset
December 31,
					(Gal)(1)				(per Gal)(1)				(in thousands)(4)
2014						1,890,000			$	0.303			$	25
													$	25
Natural Gas Liquids Propane Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Liability
December 31,
					(Gal)(1)				(per Gal)(1)				(in thousands)(5)
2014						9,261,000			$	1			$	(727	)
2015						8,064,000			$	1.016				(149	)
													$	(876	)
Natural Gas Liquids Butane Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset
December 31,
					(Gal)(1)				(per Gal)(1)				(in thousands)(6)
2014						1,134,000			$	1.308			$	35
2015						1,512,000			$	1.248				28
													$	63
Natural Gas Liquids Iso Butane Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset
December 31,
					(Gal)(1)				(per Gal)(1)				(in thousands)(7)
2014						1,134,000			$	1.323			$	33
2015						1,512,000			$	1.263				24
													$	57
Crude Oil Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset/
December 31,													(Liability)
					(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014						409,500			$	92.692			$	(2,091	)
2015						567,000			$	88.144				(969	)
2016						225,000			$	85.523				218
2017						132,000			$	83.305				220
													$	(2,622	)
Crude Oil Costless Collars
Production		Option Type			Volumes				Average				Fair Value
Period Ending									Floor				Asset/
December 31,									and Cap				(Liability)
					(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014		Puts purchased				30,870			$	84.169			$	38
2014		Calls sold				30,870			$	113.308				(33	)
2015		Puts purchased				29,250			$	83.846				125
2015		Calls sold				29,250			$	110.654				(61	)
													$	69
										Total net assets			$	1,525
-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.
(4)	Fair value based on forward Mt. Belvieu ethane prices, as applicable.
-5	Fair value based on forward Mt. Belvieu propane prices, as applicable.
-6	Fair value based on forward Mt. Belvieu butane prices, as applicable.
(7)	Fair value based on forward Mt. Belvieu iso butane prices, as applicable
At March 31, 2014, the Partnership had net cash proceeds of $1.9 million related to hedging positions monetized on behalf of the Drilling Partnerships’ limited partners, which were included within cash and cash equivalents on the Partnership’s consolidated balance sheet. The Partnership will allocate 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. The Partnership reflected the remaining hedge monetization proceeds within current and long-term portion of derivative payable to Drilling Partnerships on its consolidated balance sheets as of March 31, 2014 and December 31, 2013.
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 unrealized derivative gain or loss is allocable to the limited partners of the Drilling Partnerships based on their share of estimated gas production related to the derivatives not yet settled. At March 31, 2014, net unrealized derivative assets of $1.1 million were payable to the limited partners in the Drilling Partnerships related to these natural gas put option contracts.
At March 31, 2014, 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 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_Instru

Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2014
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 March 31, 2014 and December 31, 2013 was as follows (in thousands):
		Level 1		Level 2			Level 3		Total
	As of March 31, 2014
	Derivative assets, gross
	Commodity swaps	$	—	$	26,771		$	—	$	26,771
	Commodity basis swaps		—		159			—		159
	Commodity puts		—		1,144			—		1,144
	Commodity options		—		2,442			—		2,442
	Total derivative assets, gross		—		30,516			—		30,516
	Derivative liabilities, gross
	Commodity swaps		—		(27,556	)		—		(27,556	)
	Commodity basis swaps		—		(201	)		—		(201	)
	Commodity options		—		(1,234	)		—		(1,234	)
	Total derivative liabilities, gross		—		(28,991	)		—		(28,991	)
	Total derivatives, fair value, net	$	—	$	1,525		$	—	$	1,525
		Level 1		Level 2			Level 3		Total
	As of December 31, 2013
	Derivative assets, gross
	Commodity swaps	$	—	$	33,594		$	—	$	33,594
	Commodity puts		—		1,374			—		1,374
	Commodity options		—		3,305			—		3,305
	Total derivative assets, gross		—		38,273			—		38,273
	Derivative liabilities, gross
	Commodity swaps		—		(14,624	)		—		(14,624	)
	Commodity options		—		(1,094	)		—		(1,094	)
	Total derivative liabilities, gross		—		(15,718	)		—		(15,718	)
	Total derivatives, fair value, net	$	—	$	22,555		$	—	$	22,555
	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 value of the Partnership’s long-term debt at March 31, 2014 and December 31, 2013, which consists of its Senior Notes and outstanding borrowings under its revolving credit facility (see Note 7), were $925.9 million and $938.6 million, respectively, compared with the carrying amounts of $889.4 million and $942.3 million, respectively. At March 31, 2014 and December 31, 2013, the carrying values of outstanding borrowings under the Partnership’s revolving credit facility (see Note 7), which bears interest at variable interest rates, approximated its estimated fair value. The estimated fair values of the Partnership’s Senior Notes were based upon the market approach and calculated using yields of the Partnership as provided by financial institutions and thus was categorized as a Level 3 value.
	Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
	Management estimates the fair value of its 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 assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2014 and 2013 were as follows (in thousands):
		Three Months Ended March 31,
		2014					2013
		Level 3		Total			Level 3		Total
	Asset retirement obligations	$	529	$	529		$	645	$	645
	Total	$	529	$	529		$	645	$	645
	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. For the year ended December 31, 2013, the Partnership recognized $38.0 million of impairment of long-lived assets which were defined as a Level 3 fair value measurements (see Note 2 – Impairment of Long-Lived Assets). No impairments were recognized during the three months ended March 31, 2014 and 2013.
	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 this acquisition are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The estimate of fair value of the EP Energy Acquisition as of the respective acquisition date, which are reflected in the Partnership’s consolidated balance sheet as of March 31, 2014, are subject to change as the final valuation has not yet been completed, and such changes could be material. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under the 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 require significant judgments and estimates by the Partnership’s management at the time of the valuation and are subject to change.
	The fair value of the warrants associated with the Class C preferred units (see Note 12) was measured using a Black-Scholes pricing model which is based on Level 3 inputs including conversion price of $23.10, discount rate of 0.21% and estimated volatility rate of 35%.

Certain_Relationships_and_Rela

Certain Relationships and Related Party Transactions	3 Months Ended
	Mar. 31, 2014
Certain Relationships And Related Party Transactions	'
	NOTE 10 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
	Relationship with Drilling Partnerships. The Partnership conducts certain activities through, and a portion of its revenues are attributable to, 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 Atlas Pipeline Partners, L.P. The Partnership’s general partner, ATLS, also maintains a general partner ownership interest in Atlas Pipeline Partners, L.P. (“APL”), a publicly traded Delaware master limited partnership (NYSE: APL) and midstream energy service provider engaged in the gathering, processing and treating of natural gas in the mid-continent and southwestern regions of the United States. In the Chattanooga Shale, a portion of the natural gas produced by the Partnership is gathered and processed by APL. For the three months ended March 31, 2014 and 2013, $0.1 million and $0.1 million, respectively, of gathering fees were paid by the Partnership to APL.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies	'
	NOTE 11 — COMMITMENTS AND CONTINGENCIES
	General Commitments
	The Partnership is the managing general partner of the Drilling Partnerships and has agreed to indemnify each investor partner from any liability that exceeds such partner’s share of Drilling Partnership assets. Subject to certain conditions, investor partners in certain Drilling Partnerships have the right to present their interests for purchase by the Partnership, as managing general partner. The Partnership is not obligated to purchase more than 5% to 10% of the units in any calendar year. Based on its historical experience, as of March 31, 2014, the management of the Partnership believes that any such liability incurred would not be material. Also, the Partnership has agreed to subordinate a portion of its share of net partnership revenues from certain of the Drilling Partnerships to the benefit of the investor partners until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specific period, typically the first five to eight years, in accordance with the terms of the partnership agreements. For the three months ended March 31, 2014 and 2013, $3.5 million and $2.1 million, respectively, of the Partnership’s revenues, net of corresponding production costs, were subordinated, which reduced its cash distributions received from the Drilling Partnerships.
	Certain of the Partnership’s executives are parties to employment agreements with ATLS that provide compensation and certain other benefits. The agreements also provide for severance payments under certain circumstances.
	In connection with the EP Energy 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 March 31, 2014 were as follows: 2014 - $6.6 million; 2015 ‑ $8.6 million; 2016 ‑ $2.1 million; and 2017 to 2018 ‑ none.
	As of March 31, 2014, the Partnership is committed to expend approximately $10.3 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	3 Months Ended
	Mar. 31, 2014
Issuances of Units	'
	NOTE 12 —ISSUANCES OF UNITS
	In March 2014, 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. The units were registered under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to a shelf registration statement on Form S-3, which was automatically effective on the filing date of February 3, 2014.
	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 initial Class C preferred distribution was paid for the quarter ending September 30, 2013. 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.
	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 the equity distribution agreement effective December 27, 2013.

Cash_Distributions

Cash Distributions	3 Months Ended
	Mar. 31, 2014
Cash Distributions	'
	NOTE 13 – CASH DISTRIBUTIONS
	The Partnership has a cash distribution policy under which it distributes, within 45 days following the end of each calendar quarter, all of its available cash (as defined in the partnership agreement) for that quarter to its common unitholders and general partner. In January 2014, the Partnership’s board of directors approved the modification of its cash distribution payment practice to a monthly cash distribution program beginning for the month of January 2014, whereby the monthly cash distribution will be paid within 45 days from the month end. 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.
	Distributions declared by the Partnership for the period from January 1, 2013 through March 31, 2014 were as follows (in thousands, except per unit amounts):
	Date Cash	For	Cash		Total Cash		Total Cash		Total Cash
		Quarter/Month	Distribution		Distribution		Distribution		Distribution
	Distribution	Ended	per Common		to Common		To		to the General
			Limited		Limited		Preferred		Partner’s
	Paid		Partner Unit		Partners		Limited		Class
							Partners		A Units
	May 15, 2013	31-Mar-13	$	0.51	$	22,428	$	1,957	$	946
	August 14, 2013	30-Jun-13	$	0.54	$	32,097	$	2,072	$	1,884
	November 14, 2013	September 30, 2013	$	0.56	$	33,291	$	4,248	$	2,443
	14-Feb-14	31-Dec-13	$	0.58	$	34,489	$	4,400	$	2,891
	17-Mar-14	31-Jan-14	$	0.1933	$	12,718	$	1,467	$	1,055
	14-Apr-14	28-Feb-14	$	0.1933	$	12,719	$	1,466	$	1,055
	On April 23, 2014, the Partnership declared a monthly distribution of $0.1933 per common unit for the month of March 2014. The $15.3 million distribution, including $1.1 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2014 to holders of record as of May 7, 2014.

Benefit_Plan

Benefit Plan	3 Months Ended
	Mar. 31, 2014
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 March 31, 2014, the Partnership had 2,284,983 phantom units, restricted units and restricted options outstanding under the 2012 LTIP with 372,711 phantom units, restricted units and unit options available for grant.
	In the case of awards held by eligible employees, following a “change in control”, as defined in the 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. 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 distribution equivalent rights (“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 March 31, 2014, 275,545 units will vest within the following twelve months. All phantom units outstanding under the 2012 LTIP at March 31, 2014 include DERs. During the three months ended March 31, 2014 and 2013, the Partnership paid $0.6 million and $0.5 million, respectively, with respect to the 2012 LTIP’s DERs. These amounts were recorded as reductions of partners’ capital on the Partnership’s consolidated balance sheets.
	The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated:
			Three Months Ended March 31,
			2014						2013
			Number			Weighted			Number			Weighted
			of Units			Average			of Units			Average
						Grant Date						Grant Date
						Fair Value						Fair Value
	Outstanding, beginning of year			839,808		$	24.31			948,476		$	24.76
	Granted			3,500			20.99			83,250			21.96
	Vested and issued(1)			(15,500	)		22.69			(2,465	)		24.67
	Forfeited			(15,500	)		22.63			(4,000	)		25.14
	Outstanding, end of period(2)(3)			812,308		$	24.35			1,025,261		$	24.53
	Vested and not yet issued(4)			6,875		$	22.76			—		$	—
	Non-cash compensation expense recognized (in thousands)					$	1,731					$	3,053
	-1	The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively.
	-2	The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $17.0 million.
	-3	There was $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at the periods ended March 31, 2014 and December 31, 2013, representing 16,084 units for the periods ending March 31, 2014 and December 31, 2013 due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $22.15 for the periods ending March 31, 2014 and December 31, 2013, respectively. There was approximately $44,000 recognized as liabilities on the Partnership’s consolidated balance sheet at March 31, 2013, representing 3,476 units, due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $28.75 at March 31, 2013.
	-4	The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.1 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013.
	At March 31, 2014, the Partnership had approximately $6.9 million in unrecognized compensation expense related to unvested phantom units outstanding under the 2012 LTIP based upon the fair value of the awards.
	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 367,575 unit options outstanding under the 2012 LTIP at March 31, 2014 that will vest within the following twelve months. No cash was received from the exercise of options for the three months ended March 31, 2014 and 2013, respectively.
	The following table sets forth the 2012 LTIP unit option activity for the periods indicated:
			Three Months Ended March 31,
			2014						2013
			Number			Weighted			Number			Weighted
			of Units			Average			of Units			Average
						Exercise						Exercise
						Price						Price
	Outstanding, beginning of year			1,482,675		$	24.66			1,515,500		$	24.68
	Granted			—			—			2,000			22.27
	Exercised (1)			—			—			—			—
	Forfeited			(10,000	)		23.4			(4,000	)		25.14
	Outstanding, end of period(2)(3)			1,472,675		$	24.66			1,513,500		$	24.67
	Options exercisable, end of period(4)			368,825		$	24.67			—		$	—
	Non-cash compensation expense recognized (in thousands)					$	612					$	1,194
	-1	No options were exercised during the three months ended March 31, 2014, and 2013, respectively.
	-2	The weighted average remaining contractual life for outstanding options at March 31, 2014 was 8.1 years.
	-3	The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000.
	-4	The weighted average remaining contractual life for exercisable options at March 31, 2014 was 8.1 years. There were no intrinsic values for options exercisable at March 31, 2014 and 2013.
	At March 31, 2014, the Partnership had approximately $2.2 million in unrecognized compensation expense related to unvested unit options outstanding under the 2012 LTIP based upon the fair value of the awards. 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 periods indicated:
			Three Months Ended
			March 31,
			2014			2013
	Expected dividend yield			—	%		6.6	%
	Expected unit price volatility			—	%		44	%
	Risk-free interest rate			—	%		1.1	%
	Expected term (in years)			—			6.25
	Fair value of unit options granted		$	—		$	4.85

Operating_Segment_Information

Operating Segment Information	3 Months Ended
	Mar. 31, 2014
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):
			Three Months Ended
			March 31,
			2014			2013
	Gas and oil production:
	Revenues		$	96,245		$	46,064
	Operating costs and expenses			(36,792	)		(15,216	)
	Depreciation, depletion and amortization expense			(48,029	)		(19,696	)
	Segment income		$	11,424		$	11,152
	Well construction and completion:
	Revenues		$	49,377		$	56,478
	Operating costs and expenses			(42,936	)		(49,112	)
	Segment income		$	6,441		$	7,366
	Other partnership management:(1)
	Revenues		$	11,723		$	9,506
	Operating costs and expenses			(6,895	)		(6,731	)
	Depreciation, depletion and amortization expense			(2,208	)		(1,512	)
	Segment income		$	2,620		$	1,263
	Reconciliation of segment income to net loss:
	Segment income:
	Gas and oil production		$	11,424		$	11,152
	Well construction and completion			6,441			7,366
	Other partnership management			2,620			1,263
	Total segment income			20,485			19,781
	General and administrative expenses(2)			(16,455	)		(17,567	)
	Interest expense(2)			(13,188	)		(6,889	)
	Loss on asset sales and disposal(2)			(1,603	)		(702	)
	Net loss		$	(10,761	)	$	(5,377	)
	Capital expenditures:
	Gas and oil production		$	34,983		$	55,773
	Other partnership management			3,340			912
	Corporate and other			1,574			1,802
	Total capital expenditures		$	39,897		$	58,487
			March 31,			December 31,
			2014			2013
	Balance sheet
	Goodwill:
	Gas and oil production		$	18,145		$	18,145
	Well construction and completion			6,389			6,389
	Other partnership management			7,250			7,250
			$	31,784		$	31,784
	Total assets:
	Gas and oil production		$	2,193,901		$	2,170,712
	Well construction and completion			7,204			55,031
	Other partnership management			56,199			56,493
	Corporate and other			64,601			61,564
			$	2,321,905		$	2,343,800
	-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	Loss on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2014
Subsequent Events	'
	NOTE 16 — SUBSEQUENT EVENTS
	Cash Distribution Policy. On April 23, 2014, the Partnership declared a cash distribution of $0.1933 per common unit for the month of March 2014. The $15.3 million distribution, including $1.1 million and $1.5 million to the general partner and preferred limited partners, respectively, will be paid on May 15, 2014 to holders of record as of May 7, 2014.
	Merit Acquisition. On May 7, 2014, the Partnership entered into a definitive purchase and sale agreement to acquire Merit Energy Company’s (“Merit”) non-operated producing oil wells in the Rangely field of northwest Colorado for $420 million in cash, subject to customary closing adjustments. The transaction is expected to close during the second quarter of 2014 and has an effective date of April 1, 2014.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2014
Principles of Consolidation	'
	Principles of Consolidation
	The Partnership’s consolidated balance sheets at March 31, 2014 and December 31, 2013 and the consolidated statements of operations for the three months ended March 31, 2014 and 2013 include the accounts of the Partnership and its wholly-owned subsidiaries. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheets and related consolidated statements of operations. Actual balances and results could be different from those estimates. 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.
	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 as further explained under the heading “Property, Plant and Equipment” elsewhere within this note.
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. Actual results could differ from those estimates.
	The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2014 and 2013 represent actual results in all material respects (see “Revenue Recognition”).
Receivables	'
	Receivables
	Accounts receivable on the consolidated balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the Partnership’s management performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the Partnership’s customers’ credit information. The Partnership extends credit on sales on an unsecured basis to many of its customers. At March 31, 2014 and December 31, 2013, the Partnership had recorded no allowance for uncollectible accounts receivable on its consolidated balance sheets.
Inventory	'
	Inventory
	The Partnership had $9.6 million and $4.6 million of inventory at March 31, 2014 and December 31, 2013, 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.
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 which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which 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 Long-Lived Assets	'
	Impairment of Long-Lived Assets
	The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount 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 futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
	The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, 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 the limited partners in the Drilling Partnerships paying to the Partnership their proportionate share of these expenses plus a profit margin. 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 partner 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.
	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, 2013, the Partnership recognized $13.5 million of asset impairments related to its 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 three months ended March 31, 2014 and 2013.
	Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. During the year ended December 31, 2013, the Partnership recognized $24.5 million of asset impairments related to its 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. There were no impairments of proved gas and oil properties recorded by the Partnership for the three months ended March 31, 2014 and 2013.
	The impairments of proved and unproved properties during the year ended December 31, 2013 related to the carrying amounts of these gas and oil properties being in excess of the Partnership’s estimate of their fair values at December 31, 2013 and management’s intention not to drill on certain expiring unproved acreage. The estimate of the fair values of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
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 5.6% and 6.2% for the three months ended March 31, 2014 and 2013, respectively. The aggregate amount of interest capitalized by the Partnership was $2.6 million and $3.4 million for the three months ended March 31, 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 following table reflects the components of intangible assets being amortized at March 31, 2014 and December 31, 2013 (in thousands):
			March 31,			December 31,			Estimated
									Useful Lives
			2014			2013			In Years
	Gross Carrying Amount		$	14,344		$	14,344			13
	Accumulated Amortization			(13,449	)		(13,381	)
	Net Carrying Amount		$	895		$	963
	Amortization expense on intangible assets was $0.1 million for both the three months ended March 31, 2014 and 2013. Aggregate estimated annual amortization expense for all of the contracts described above for the next five years ending December 31 is as follows: 2014 - $0.3 million; 2015 - $0.2 million; 2016 - $0.1 million, 2017 - $0.1 million and 2018 - $0.1 million.
Goodwill	'
	Goodwill
	At March 31, 2014 and December 31, 2013, the Partnership had $31.8 million of goodwill recorded in connection with its prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded for the three months ended March 31, 2014 and 2013.
	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 and the available market data of the industry group. 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. During the three months ended March 31, 2014 and 2013, no impairment indicators arose, and no goodwill impairments were recognized by the Partnership.
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 accompanying 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 accompanying 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 three months ended March 31, 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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 31, 2014.
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 when considered in the calculation of earnings per unit under the two-class method. 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 share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and are included in the computation of earnings per unit pursuant to the two-class method. 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 loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data):
			Three Months Ended
			March 31,
			2014			2013
	Net loss		$	(10,761	)	$	(5,377	)
	Preferred limited partner dividends			(4,399	)		(1,957	)
	Net loss attributable to common limited partners and the general partner			(15,160	)		(7,334	)
	Less: General partner’s interest			(2,004	)		(301	)
	Net loss attributable to common limited partners			(17,164	)		(7,635	)
	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		$	(17,164	)	$	(7,635	)
	(1)	Net income 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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 820,000 and 998,000 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.
	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 method. 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):
			Three Months Ended
			March 31,
			2014			2013
	Weighted average number of common limited partner units - basic			61,219			43,974
	Add effect of dilutive incentive awards(1)			—			—
	Add effect of dilutive convertible preferred limited partner units and warrants(2)			—			—
	Weighted average number of common limited partner units - diluted			61,219			43,974
	(1)	For the three months ended March 31, 2014 and 2013, approximately 820,000 units and 998,000 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 three months ended March 31, 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 three months ended March 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s 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 three months ended March 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.
Revenue Recognition	'
	Revenue Recognition
	Certain energy activities are conducted by the Partnership through, and a portion of its revenues are attributable to, the Drilling Partnerships. The Partnership contracts with the Drilling Partnerships to drill partnership wells. The contracts require that the Drilling Partnerships pay the Partnership the full contract price upon execution. The income from a drilling contract is recognized as the services are performed using the percentage of completion method. The contracts are typically completed between 60 and 270 days. On an uncompleted contract, the Partnership classifies the difference between the contract payments it has received and the revenue earned as a current liability titled “Liabilities Associated with Drilling Contracts” on the Partnership’s consolidated balance sheets. The Partnership recognizes well services revenues at the time the services are performed. The Partnership is also entitled to receive management fees according to the respective partnership agreements and recognizes such fees as income when earned, which are included in administration and oversight revenues within its consolidated statements of operations.
	The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Typically, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
	The Partnership accrues 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 from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (see “Use of Estimates” for further description). The Partnership had unbilled revenues at March 31, 2014 and December 31, 2013 $83.0 million and $55.3 million, respectively, which were included in accounts receivable within the Partnership’s consolidated balance sheets.
	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 Shale and the Chattanooga Shale. 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%.
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 at March 31, 2014, 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 Adopted Accounting Standards	'
	Recently Adopted Accounting Standards
	In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, Income Taxes (Topic 740) – Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“Update 2013-11”), which, among other changes, requires an entity to present an unrecognized tax benefit as a liability and not net with deferred tax assets when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes under the tax law of the applicable jurisdiction that would result from the disallowance of a tax position or when the tax law of the applicable tax jurisdiction does not require, and the entity does not intend to, use the deferred tax asset for such purpose. These requirements are effective for interim and annual reporting periods beginning after December 15, 2013. Early adoption was permitted. These amendments should be applied prospectively to all unrecognized tax benefits that exist at the effective date. Retrospective application is permitted. The Partnership adopted the requirements of Update 2013-11 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.
	In February 2013, the FASB issued ASU 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“Update 2013-04”). Update 2013-04 provides guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements, for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations and settled litigation and judicial rulings. Update 2013-04 requires an entity to measure joint and several liability arrangements, for which the total amount of the obligation is fixed at the reporting date as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. In addition, Update 2013-04 provides disclosure guidance on the nature and amount of the obligation as well as other information. Update 2013-04 is effective for fiscal years and interim periods within those years, beginning after December 15, 2013. The Partnership adopted the requirements of Update 2013-04 upon its effective date of January 1, 2014, and it had no material impact on its financial position, results of operations or related disclosures.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2014
Schedule of the Components of Intangible Assets Being Amortized	'
	The following table reflects the components of intangible assets being amortized at March 31, 2014 and December 31, 2013 (in thousands):
			March 31,			December 31,			Estimated
									Useful Lives
			2014			2013			In Years
	Gross Carrying Amount		$	14,344		$	14,344			13
	Accumulated Amortization			(13,449	)		(13,381	)
	Net Carrying Amount		$	895		$	963
Reconciliation of Net Loss	'
	The following is a reconciliation of net loss allocated to the common limited partners for purposes of calculating net loss attributable to common limited partners per unit (in thousands, except unit data):
			Three Months Ended
			March 31,
			2014			2013
	Net loss		$	(10,761	)	$	(5,377	)
	Preferred limited partner dividends			(4,399	)		(1,957	)
	Net loss attributable to common limited partners and the general partner			(15,160	)		(7,334	)
	Less: General partner’s interest			(2,004	)		(301	)
	Net loss attributable to common limited partners			(17,164	)		(7,635	)
	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		$	(17,164	)	$	(7,635	)
	(1)	Net income 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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 820,000 and 998,000 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.
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):
			Three Months Ended
			March 31,
			2014			2013
	Weighted average number of common limited partner units - basic			61,219			43,974
	Add effect of dilutive incentive awards(1)			—			—
	Add effect of dilutive convertible preferred limited partner units and warrants(2)			—			—
	Weighted average number of common limited partner units - diluted			61,219			43,974
	(1)	For the three months ended March 31, 2014 and 2013, approximately 820,000 units and 998,000 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 three months ended March 31, 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 three months ended March 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s 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 three months ended March 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.

Acquisitions_Tables

Acquisitions (Tables) (EP Energy Acquisition)	3 Months Ended
	Mar. 31, 2014
EP Energy Acquisition	'
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	'
	The following table presents the preliminary 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		723,657
	Total current assets	$	728,925
	Liabilities:
	Accounts payable		2,562
	Asset retirement obligation		16,728
	Total liabilities assumed		19,290
	Net assets acquired	$	709,635

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2014
Property, Plant and Equipment	'
	The following is a summary of property, plant and equipment at the dates indicated (in thousands):
		March 31,			December 31,			Estimated
								Useful Lives
		2014			2013			in Years
	Natural gas and oil properties:
	Proved properties:
	Leasehold interests	$	321,179		$	320,459
	Pre-development costs		4,038			4,367
	Wells and related equipment		2,204,347			2,164,760
	Total proved properties		2,529,564			2,489,586
	Unproved properties		216,598			211,536
	Support equipment		26,403			23,005
	Total natural gas and oil properties		2,772,565			2,724,127
	Pipelines, processing and compression facilities		43,135			42,949			2 – 40
	Rights of way		829			830			20 – 40
	Land, buildings and improvements		8,981			9,462			3 – 40
	Other		16,185			15,318			3 – 10
			2,841,695			2,792,686
	Less – accumulated depreciation, depletion and amortization		(716,506	)		(671,868	)
		$	2,125,189		$	2,120,818

Other_Assets_Tables

Other Assets (Tables)	3 Months Ended
	Mar. 31, 2014
Schedule of Other Assets	'
	The following is a summary of other assets at the dates indicated (in thousands):
		March 31,		December 31,
		2014		2013
	Deferred financing costs, net of accumulated amortization of $13,706 and $11,948 at March 31, 2014 and December 31, 2013, respectively	$	34,077	$	35,292
	Notes receivable		4,012		3,978
	Long-term derivative asset receivable from Drilling Partnerships		1,007		863
	Other		3,458		2,688
		$	42,554	$	42,821

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2014
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):
		Three Months Ended
		March 31,
		2014			2013
	Asset retirement obligations, beginning of year	$	89,776		$	64,794
	Liabilities incurred		529			645
	Liabilities settled		(217	)		(7	)
	Accretion expense		1,301			954
	Asset retirement obligations, end of period	$	91,389		$	66,386

Debt_Tables

Debt (Tables)	3 Months Ended
	Mar. 31, 2014
Schedule of Long-term Debt Instruments	'
	Total debt consists of the following at the dates indicated (in thousands):
		March 31,		December 31,
		2014		2013
	Revolving credit facility	$	366,000	$	419,000
	7.75 % Senior Notes – due 2021		275,000		275,000
	9.25 % Senior Notes – due 2021		248,388		248,334
	Total debt		889,388		942,334
	Less current maturities		—		—
	Total long-term debt	$	889,388	$	942,334

Derivative_Instruments_Tables

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2014
Summary of Gain or Loss Derivative Instruments Recognized in Statements of Operations	'
	The following table summarizes the gains recognized in the Partnership’s consolidated statements of operations for effective derivative instruments for the periods indicated (in thousands):
			Three Months Ended
			March 31,
			2014				2013
	(Gain) loss reclassified from accumulated other comprehensive income (loss):
	Gas and oil production revenue		$	14,043			$	(993	)
	Total		$	14,043			$	(993	)
Fair Value 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 on the Partnership’s consolidated balance sheets for the periods indicated (in thousands):
	Offsetting Derivative Assets		Gross				Gross				Net Amount of
			Amounts of				Amounts				Assets
			Recognized				Offset in the				Presented in the
			Assets				Consolidated				Consolidated
							Balance Sheets				Balance Sheets
	As of March 31, 2014
	Current portion of derivative assets		$	161			$	—			$	161
	Long-term portion of derivative assets			25,859				(2,110	)			23,749
	Current portion of derivative liabilities			4,382				(4,382	)			—
	Long-term portion of derivative liabilities			114			$	(114	)		$	—
	Total derivative assets		$	30,516				(6,606	)			23,910
	As of December 31, 2013
	Current portion of derivative assets		$	2,664			$	(773	)		$	1,891
	Long-term portion of derivative assets			31,146				(4,062	)			27,084
	Current portion of derivative liabilities			4,341				(4,341	)			—
	Long-term portion of derivative liabilities			122				(122	)			—
	Total derivative assets		$	38,273			$	(9,298	)		$	28,975
	Offsetting Derivative Liabilities		Gross				Gross				Net Amount of
			Amounts of				Amounts				Liabilities
			Recognized				Offset in the				Presented in the
			Liabilities				Consolidated				Consolidated
							Balance Sheets				Balance Sheets
	As of March 31, 2014
	Current portion of derivative assets		$	—			$	—			$	—
	Long-term portion of derivative assets			(2,110	)			2,110				—
	Current portion of derivative liabilities			(26,754	)			4,382				(22,372	)
	Long-term portion of derivative liabilities			(127	)			114				(13	)
	Total derivative liabilities		$	(28,991	)		$	6,606			$	(22,385	)
	As of December 31, 2013
	Current portion of derivative assets		$	(773	)		$	773			$	—
	Long-term portion of derivative assets			(4,062	)			4,062				—
	Current portion of derivative liabilities			(10,694	)			4,341				(6,353	)
	Long-term portion of derivative liabilities			(189	)			122				(67	)
	Total derivative liabilities		$	(15,718	)		$	9,298			$	(6,420	)
Commodity Derivative Instruments by Type Table	'
	At March 31, 2014, the Partnership had the following commodity derivatives:
	Natural Gas Fixed Price Swaps
	Production					Volumes				Average				Fair Value
	Period Ending									Fixed Price				Asset/
	December 31,													(Liability)
						(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
	2014						45,114,700			$	4.152			$	(14,068	)
	2015						51,924,500			$	4.239				1,799
	2016						45,746,300			$	4.311				7,193
	2017						24,840,000			$	4.532				6,734
	2018						3,960,000			$	4.716				1,306
														$	2,964
	Natural Gas Costless Collars
	Production		Option Type			Volumes				Average Floor				Fair Value
	Period Ending									and Cap				Asset/
	December 31,													(Liability)
						(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
	2014		Puts purchased				2,880,000			$	4.221			$	642
	2014		Calls sold				2,880,000			$	5.12				(418	)
	2015		Puts purchased				3,480,000			$	4.234				1,636
	2015		Calls sold				3,480,000			$	5.129				(721	)
														$	1,139
	Natural Gas Put Options – Drilling Partnerships
	Production		Option Type			Volumes				Average				Fair Value
	Period Ending									Fixed Price				Asset
	December 31,
						(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
	2014		Puts purchased				1,350,000			$	3.8			$	84
	2015		Puts purchased				1,440,000			$	4				447
	2016		Puts purchased				1,440,000			$	4.15				613
														$	1,144
	WAHA Basis Swaps
	Production					Volumes				Average				Fair Value
	Period Ending									Fixed Price				Liability
	December 31,
						(MMBtu)(1)				(per MMBtu)(1)				(in thousands)(2)
	2014						8,100,000			$	(0.110	)		$	(42	)
														$	(42	)
	Natural Gas Liquids Fixed Price Swaps
	Production					Volumes				Average				Fair Value
	Period Ending									Fixed Price				Asset/
	December 31,													(Liability)
						(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
	2014						79,500			$	91.568			$	(486	)
	2015						96,000			$	88.55				(129	)
	2016						84,000			$	85.651				92
	2017						60,000			$	83.78				127
														$	(396	)
	Natural Gas Liquids Ethane Fixed Price Swaps
	Production					Volumes				Average				Fair Value
	Period Ending									Fixed Price				Asset
	December 31,
						(Gal)(1)				(per Gal)(1)				(in thousands)(4)
	2014						1,890,000			$	0.303			$	25
														$	25
	Natural Gas Liquids Propane Fixed Price Swaps
	Production					Volumes				Average				Fair Value
	Period Ending									Fixed Price				Liability
	December 31,
						(Gal)(1)				(per Gal)(1)				(in thousands)(5)
	2014						9,261,000			$	1			$	(727	)
	2015						8,064,000			$	1.016				(149	)
														$	(876	)
Natural Gas Liquids Butane Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset
December 31,
					(Gal)(1)				(per Gal)(1)				(in thousands)(6)
2014						1,134,000			$	1.308			$	35
2015						1,512,000			$	1.248				28
													$	63
Natural Gas Liquids Iso Butane Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset
December 31,
					(Gal)(1)				(per Gal)(1)				(in thousands)(7)
2014						1,134,000			$	1.323			$	33
2015						1,512,000			$	1.263				24
													$	57
Crude Oil Fixed Price Swaps
Production					Volumes				Average				Fair Value
Period Ending									Fixed Price				Asset/
December 31,													(Liability)
					(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014						409,500			$	92.692			$	(2,091	)
2015						567,000			$	88.144				(969	)
2016						225,000			$	85.523				218
2017						132,000			$	83.305				220
													$	(2,622	)
Crude Oil Costless Collars
Production		Option Type			Volumes				Average				Fair Value
Period Ending									Floor				Asset/
December 31,									and Cap				(Liability)
					(Bbl)(1)				(per Bbl)(1)				(in thousands)(3)
2014		Puts purchased				30,870			$	84.169			$	38
2014		Calls sold				30,870			$	113.308				(33	)
2015		Puts purchased				29,250			$	83.846				125
2015		Calls sold				29,250			$	110.654				(61	)
													$	69
										Total net assets			$	1,525
-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.
(4)	Fair value based on forward Mt. Belvieu ethane prices, as applicable.
-5	Fair value based on forward Mt. Belvieu propane prices, as applicable.
-6	Fair value based on forward Mt. Belvieu butane prices, as applicable.
(7)	Fair value based on forward Mt. Belvieu iso butane prices, as applicable

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2014
Schedule of Assets/Liabilities at Fair Value	'
	Information for assets and liabilities measured at fair value at March 31, 2014 and December 31, 2013 was as follows (in thousands):
		Level 1		Level 2			Level 3		Total
	As of March 31, 2014
	Derivative assets, gross
	Commodity swaps	$	—	$	26,771		$	—	$	26,771
	Commodity basis swaps		—		159			—		159
	Commodity puts		—		1,144			—		1,144
	Commodity options		—		2,442			—		2,442
	Total derivative assets, gross		—		30,516			—		30,516
	Derivative liabilities, gross
	Commodity swaps		—		(27,556	)		—		(27,556	)
	Commodity basis swaps		—		(201	)		—		(201	)
	Commodity options		—		(1,234	)		—		(1,234	)
	Total derivative liabilities, gross		—		(28,991	)		—		(28,991	)
	Total derivatives, fair value, net	$	—	$	1,525		$	—	$	1,525
		Level 1		Level 2			Level 3		Total
	As of December 31, 2013
	Derivative assets, gross
	Commodity swaps	$	—	$	33,594		$	—	$	33,594
	Commodity puts		—		1,374			—		1,374
	Commodity options		—		3,305			—		3,305
	Total derivative assets, gross		—		38,273			—		38,273
	Derivative liabilities, gross
	Commodity swaps		—		(14,624	)		—		(14,624	)
	Commodity options		—		(1,094	)		—		(1,094	)
	Total derivative liabilities, gross		—		(15,718	)		—		(15,718	)
	Total derivatives, fair value, net	$	—	$	22,555		$	—	$	22,555
Schedule of Assets and Liabilities Measured on Non Recurring Basis	'
	Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the three months ended March 31, 2014 and 2013 were as follows (in thousands):
		Three Months Ended March 31,
		2014					2013
		Level 3		Total			Level 3		Total
	Asset retirement obligations	$	529	$	529		$	645	$	645
	Total	$	529	$	529		$	645	$	645

Cash_Distribution_Distribution

Cash Distribution (Distributions Declared) (Tables) (General Partner and Preferred Partner)	3 Months Ended
	Mar. 31, 2014
General Partner and Preferred Partner	'
Schedule of Distributions Made to Members or Limited Partners, by Distribution	'
	Distributions declared by the Partnership for the period from January 1, 2013 through March 31, 2014 were as follows (in thousands, except per unit amounts):
	Date Cash	For	Cash		Total Cash		Total Cash		Total Cash
		Quarter/Month	Distribution		Distribution		Distribution		Distribution
	Distribution	Ended	per Common		to Common		To		to the General
			Limited		Limited		Preferred		Partner’s
	Paid		Partner Unit		Partners		Limited		Class
							Partners		A Units
	May 15, 2013	31-Mar-13	$	0.51	$	22,428	$	1,957	$	946
	August 14, 2013	30-Jun-13	$	0.54	$	32,097	$	2,072	$	1,884
	November 14, 2013	September 30, 2013	$	0.56	$	33,291	$	4,248	$	2,443
	14-Feb-14	31-Dec-13	$	0.58	$	34,489	$	4,400	$	2,891
	17-Mar-14	31-Jan-14	$	0.1933	$	12,718	$	1,467	$	1,055
	14-Apr-14	28-Feb-14	$	0.1933	$	12,719	$	1,466	$	1,055

Benefit_Plan_Tables

Benefit Plan (Tables)	3 Months Ended
	Mar. 31, 2014
2012 LTIP Phantom Unit Activity	'
	The following table sets forth the 2012 LTIP phantom unit activity for the periods indicated:
			Three Months Ended March 31,
			2014						2013
			Number			Weighted			Number			Weighted
			of Units			Average			of Units			Average
						Grant Date						Grant Date
						Fair Value						Fair Value
	Outstanding, beginning of year			839,808		$	24.31			948,476		$	24.76
	Granted			3,500			20.99			83,250			21.96
	Vested and issued(1)			(15,500	)		22.69			(2,465	)		24.67
	Forfeited			(15,500	)		22.63			(4,000	)		25.14
	Outstanding, end of period(2)(3)			812,308		$	24.35			1,025,261		$	24.53
	Vested and not yet issued(4)			6,875		$	22.76			—		$	—
	Non-cash compensation expense recognized (in thousands)					$	1,731					$	3,053
	-1	The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively.
	-2	The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $17.0 million.
	-3	There was $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at the periods ended March 31, 2014 and December 31, 2013, representing 16,084 units for the periods ending March 31, 2014 and December 31, 2013 due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $22.15 for the periods ending March 31, 2014 and December 31, 2013, respectively. There was approximately $44,000 recognized as liabilities on the Partnership’s consolidated balance sheet at March 31, 2013, representing 3,476 units, due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $28.75 at March 31, 2013.
2012 Unit Option Activity	'
	The following table sets forth the 2012 LTIP unit option activity for the periods indicated:
			Three Months Ended March 31,
			2014						2013
			Number			Weighted			Number			Weighted
			of Units			Average			of Units			Average
						Exercise						Exercise
						Price						Price
	Outstanding, beginning of year			1,482,675		$	24.66			1,515,500		$	24.68
	Granted			—			—			2,000			22.27
	Exercised (1)			—			—			—			—
	Forfeited			(10,000	)		23.4			(4,000	)		25.14
	Outstanding, end of period(2)(3)			1,472,675		$	24.66			1,513,500		$	24.67
	Options exercisable, end of period(4)			368,825		$	24.67			—		$	—
	Non-cash compensation expense recognized (in thousands)					$	612					$	1,194
	-1	No options were exercised during the three months ended March 31, 2014, and 2013, respectively.
	-2	The weighted average remaining contractual life for outstanding options at March 31, 2014 was 8.1 years.
	-3	The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000.
	-4	The weighted average remaining contractual life for exercisable options at March 31, 2014 was 8.1 years. There were no intrinsic values for options exercisable at March 31, 2014 and 2013.
Weighted Average Assumptions	'
	The following weighted average assumptions were used for the periods indicated:
			Three Months Ended
			March 31,
			2014			2013
	Expected dividend yield			—	%		6.6	%
	Expected unit price volatility			—	%		44	%
	Risk-free interest rate			—	%		1.1	%
	Expected term (in years)			—			6.25
	Fair value of unit options granted		$	—		$	4.85

Operating_Segment_Information_

Operating Segment Information (Tables)	3 Months Ended
	Mar. 31, 2014
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):
			Three Months Ended
			March 31,
			2014			2013
	Gas and oil production:
	Revenues		$	96,245		$	46,064
	Operating costs and expenses			(36,792	)		(15,216	)
	Depreciation, depletion and amortization expense			(48,029	)		(19,696	)
	Segment income		$	11,424		$	11,152
	Well construction and completion:
	Revenues		$	49,377		$	56,478
	Operating costs and expenses			(42,936	)		(49,112	)
	Segment income		$	6,441		$	7,366
	Other partnership management:(1)
	Revenues		$	11,723		$	9,506
	Operating costs and expenses			(6,895	)		(6,731	)
	Depreciation, depletion and amortization expense			(2,208	)		(1,512	)
	Segment income		$	2,620		$	1,263
	Reconciliation of segment income to net loss:
	Segment income:
	Gas and oil production		$	11,424		$	11,152
	Well construction and completion			6,441			7,366
	Other partnership management			2,620			1,263
	Total segment income			20,485			19,781
	General and administrative expenses(2)			(16,455	)		(17,567	)
	Interest expense(2)			(13,188	)		(6,889	)
	Loss on asset sales and disposal(2)			(1,603	)		(702	)
	Net loss		$	(10,761	)	$	(5,377	)
	Capital expenditures:
	Gas and oil production		$	34,983		$	55,773
	Other partnership management			3,340			912
	Corporate and other			1,574			1,802
	Total capital expenditures		$	39,897		$	58,487
			March 31,			December 31,
			2014			2013
	Balance sheet
	Goodwill:
	Gas and oil production		$	18,145		$	18,145
	Well construction and completion			6,389			6,389
	Other partnership management			7,250			7,250
			$	31,784		$	31,784
	Total assets:
	Gas and oil production		$	2,193,901		$	2,170,712
	Well construction and completion			7,204			55,031
	Other partnership management			56,199			56,493
	Corporate and other			64,601			61,564
			$	2,321,905		$	2,343,800
	-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	Loss on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

Basis_of_Presentation_Narrativ

Basis of Presentation (Narrative) (Details)	1 Months Ended	3 Months Ended
	Feb. 29, 2012	Mar. 31, 2014
General Partner Interest	'	'
General Partner interest in Atlas Resource Partners, L.P	'	100.00%
Limited Partner Interest	'	'
Common limited partner interest in Atlas Resource Partners, L.P	'	33.70%
Common limited partner interest in Atlas Resource Partners, L.P., Units	'	20,962,485
Board Approval Date For Issuance of Common Units	'	'2012-02
Distribution Made to Member or Limited Partner, Share Distribution	5,240,000	'
Distribution Made to Member or Limited Partner, Distribution Date	'	13-Mar-12
Ratio Of ARP Limited Partner Units	0.1021	'
Distribution Made to Member or Limited Partner, Date of Record	'	28-Feb-12
Exploration And Production Assets Transferred	'	5-Mar-12
Limited Partner Interest | Preferred Limited Partners Interests	'	'
Common limited partner interest in Atlas Resource Partners, L.P., Units	'	3,749,986

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Pro-rata share in Drilling Partnerships	30.00%	'	'
Allowance for Doubtful Accounts Receivable	$0	'	$0
Materials, supplies and other inventory	9,600,000	'	4,600,000
Impairments of Unproved Gas And Oil Properties	0	0	13,500,000
Impairment of Oil and Gas Properties	0	0	24,500,000
Weighted Average Interest Rate Used To Capitalize Interest	5.60%	6.20%	'
Interest Costs Capitalized	2,600,000	3,400,000	'
Amortization of Intangible Assets	100,000	100,000	'
Future Amortization Expense, 2014	300,000	'	'
Future Amortization Expense, 2015	200,000	'	'
Future Amortization Expense, 2016	100,000	'	'
Future Amortization Expense, 2017	100,000	'	'
Future Amortization Expense, 2018	100,000	'	'
Goodwill, net	31,784,000	31,784,000	31,784,000
Goodwill, Period Increase (Decrease)	0	0	'
Goodwill, Impairment Loss	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 accompanying 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 accompanying consolidated financial statements.	'	'
Deferred Income Tax Expense (Benefit)	0	0	'
Income Tax Examination, Penalties and Interest Expense	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 2010. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of March 31, 2014.	'	'
Unbilled Contracts Receivable	$83,000,000	'	$55,300,000
Gathering Fee Percentage	16.00%	'	'
Gathering Fee Percentage Net Margin	3.00%	'	'
Drilling Partnership wells	'	'	'
Gathering Fee Percentage	13.00%	'	'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Schedule of the Components of Intangible Assets Being Amortized) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Summary of Significant Accounting Policies [Abstract]	'	'
Gross Carrying Amount	$14,344	$14,344
Accumulated Amortization	-13,449	-13,381
Net Carrying Amount	$895	$963
Estimated Useful Lives In Years	'13 years	'

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Schedule of Net Income Reconciliation) (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Net loss	($10,761)		($5,377)
Preferred limited partner dividends	-4,399		-1,957
Net loss attributable to common limited partners and the general partner	-15,160		-7,334
Less: General partner’s interest	-2,004		-301
Net loss attributable to common limited partners	-17,164		-7,635
Less: Net income attributable to participating securities – phantom units	'	[1]	'	[1]
Net loss utilized in the calculation of net loss attributable to common limited partners per unit	($17,164)		($7,635)
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units	820,000		998,000
[1]	Net income 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 three months ended March 31, 2014 and 2013, net loss attributable to common limited partners’ ownership interest is not allocated to approximately 820,000 and 998,000 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.

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Reconciliation of Weighted Average Number Of Common Limited Partner Units) (Details)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Weighted Average Limited Partnership Units Outstanding, Basic	61,219,000		43,974,000
Add effect of dilutive incentive awards	'	[1]	'	[1]
Add effect of dilutive convertible preferred limited partner units	'	[2]	'	[2]
Antidilutive Securities Excluded From Computation Of Diluted Earnings Attributable To Common Limited Partners Outstanding Units	820,000		998,000
Exclusions from the computation of diluted earnings attributable to common limited partners per unit, description	'For the three months ended March 31, 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 three months ended March 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s 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 three months ended March 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.		'
Common Limited Partnership Units	'		'
Weighted Average Limited Partnership Units Outstanding, Basic	61,219,000		43,974,000
Weighted Average Limited Partnership Units Outstanding, Diluted	61,219,000		43,974,000
[1]	For the three months ended March 31, 2014 and 2013, approximately 820,000 units and 998,000 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 three months ended March 31, 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 three months ended March 31, 2014, potential common limited partner units issuable upon conversion of the Partnership’s 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 three months ended March 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.

Acquisitions_EP_Energy_Acquisi

Acquisitions (EP Energy Acquisition) (Narrative) (Details) (USD $)	1 Months Ended		3 Months Ended
In Millions, except Share data, unless otherwise specified	Jul. 31, 2013	Jun. 10, 2013	Mar. 31, 2014
Business Acquisition [Line Items]	'	'	'
Partners' Capital Account, Units, Sale of Units	'	'	6,325,000
EP Energy Acquisition	'	'	'
Business Acquisition [Line Items]	'	'	'
Business Acquisition, Date of Acquisition Agreement	'	'	31-Jul-13
Business Acquisition, Name of Acquired Entity	'EP Energy E&P Company, L.P. (“EP Energy”)	'	'
Business Acquisition, Cost of Acquired Entity, Cash Paid	$709.60	'	'
Senior notes, interest rate	9.25%	'	'
Senior notes, maturity	15-Aug-21	'	'
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, Cost of Acquired Entity, Transaction Costs	'	'	$12.10
Business Acquisition, Purchase Price Allocation, Status	'All other costs associated with the acquisition of assets were expensed as incurred. Due to the recent date of the acquisition, the accounting for the business combination is based upon preliminary data that remains subject to adjustment and could further change as the Partnership continues to evaluate the facts and circumstances that existed as of the acquisition date.	'	'
Atlas Parent Company "ATLS" | EP Energy Acquisition | Class C Convertible Preferred Units	'	'	'
Business Acquisition [Line Items]	'	'	'
Partners' Capital Account, Units, Sale of Units	3,749,986	'	'

Acquisitions_EP_Energy_Acquisi1

Acquisitions (EP Energy Acquisition Schedule of Assets Acquired and Liabilities Assumed) (Table) (Details) (EP Energy Acquisition, USD $)	Jul. 31, 2013
In Thousands, unless otherwise specified
EP Energy Acquisition	'
Business Acquisition [Line Items]	'
Prepaid expenses and other	$5,268
Property, plant and equipment	723,657
Total current assets	728,925
Accounts payable	2,562
Asset retirement obligation	16,728
Total liabilities assumed	19,290
Net assets acquired	$709,635

Acquisitions_Other_Acquisition

Acquisitions (Other Acquisition) (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Feb. 13, 2014	Mar. 31, 2014	Sep. 20, 2013	Mar. 31, 2014
	GeoMet Acquisition	GeoMet Acquisition	Norwood Natural Resources	Norwood Natural Resources
Business Acquisition [Line Items]	'	'	'	'
Business Acquisition, Date of Acquisition Agreement	'	13-Feb-14	'	20-Sep-13
Business Acquisition, Name of Acquired Entity	'GeoMet, Inc	'	'Norwood Natural Resources	'
Business Acquisition, Cost of Acquired Entity, Cash Paid	$107	'	$5.40	'
Business Acquisition, Effective Date of Acquisition	1-Jan-14	'	1-Jun-13	'
Business Acquisition Closing Date Of Acquisition	5-May-14	'	'	'

Property_Plant_and_Equipment_S

Property, Plant and Equipment (Summary of Property, Plant and Equipment) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property Plant And Equipment [Line Items]	'	'
Proved properties: Leasehold interests	$321,179	$320,459
Proved Properties: Pre-development costs	4,038	4,367
Proved Properties: Wells and related equipment	2,204,347	2,164,760
Total proved properties	2,529,564	2,489,586
Unproved properties	216,598	211,536
Support equipment	26,403	23,005
Total natural gas and oil properties	2,772,565	2,724,127
Pipelines, processing and compression facilities	43,135	42,949
Rights of way	829	830
Land, buildings and improvements	8,981	9,462
Other	16,185	15,318
Total gross property, plant and equipment	2,841,695	2,792,686
Less – accumulated depreciation, depletion and amortization	-716,506	-671,868
Property, plant and equipment, Net, Total	$2,125,189	$2,120,818

Property_Plant_and_Equipment_U

Property, Plant and Equipment (Useful Life Narrative) (Details)	3 Months Ended
	Mar. 31, 2014
Pipelines, processing and compression facilities | Minimum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'2 years
Pipelines, processing and compression facilities | Maximum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'40 years
Rights of way | Minimum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'20 years
Rights of way | Maximum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'40 years
Land, buildings and improvements | Minimum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'3 years
Land, buildings and improvements | Maximum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'40 years
Other | Minimum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'3 years
Other | Maximum	'
Property Plant And Equipment [Line Items]	'
Property, Plant and Equipment, Useful Life	'10 years

Property_Plant_and_Equipment_N

Property, Plant and Equipment (Narrative) (Details) (USD $)	3 Months Ended				12 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Disclosure Property Plant And Equipment Narrative Details [Line Items]	'		'		'
Gain (loss) on asset sales	($1,603,000)	[1]	($702,000)	[1]	'
Long-lived asset impairment	$0		$0		$38,000,000
[1]	Loss on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.

Other_Assets_Details

Other Assets (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accumulated amortization	$13,706	$11,948
Deferred financing costs, net of accumulated amortization	34,077	35,292
Notes receivable	4,012	3,978
Long-term derivative asset receivable from Drilling Partnerships	1,007	863
Other	3,458	2,688
Total Other Assets	$42,554	$42,821

Other_Assets_Narrative_Details

Other Assets (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Amortization of Financing Costs	$1,800,000	'	$1,400,000
Accelerated amortization of deferred financing costs	'	'	3,200,000
Notes Receivable	'	'	'
Note Agreement, Maturity Date	31-Mar-22	31-Mar-22	'
Note Agreement, Interest Rate Per Annum	2.25%	2.25%	'
Note Agreement, Extension Fee Percent	1.00%	1.00%	'
Other Interest and Dividend Income	23,000	'	0
Note Receivable, Allowance for Credit Losses	$0	'	'
Note Agreement, Option to Extend Maturity Date	'	'	'
Note Agreement, Maturity Date	31-Mar-27	31-Mar-27	'

Asset_Retirement_Obligations_R

Asset Retirement Obligations (Reconciliation of Liability For Well Plugging And Abandonment Costs (Narrative)(Details)) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014
					Series of Individually Immaterial Business Acquisitions	Relationship With Drilling Partnerships	Relationship With Drilling Partnerships	Relationship With Drilling Partnerships
								Limited Partners
Asset retirement obligations	$91,389,000	$89,776,000	$66,386,000	$64,794,000	'	'	'	$57,900,000
Limited partner distributions withheld related to the asset retirement obligations of certain Drilling Partnerships	'	'	'	'	'	600,000	0	'
Oil and gas reclamation liabilities noncurrent	'	'	'	'	$16,700,000	'	'	'

Asset_Retirement_Obligations_R1

Asset Retirement Obligations (Reconciliation of Liability for Well Plugging and Abandonment Costs) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Asset retirement obligations, beginning of year	$89,776	$64,794
Liabilities incurred	529	645
Liabilities settled	-217	-7
Accretion expense	1,301	954
Asset retirement obligations, end of period	$91,389	$66,386

Debt_Schedule_of_Total_Debt_Ou

Debt (Schedule of Total Debt Outstanding) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Revolving credit facility	$366,000	$419,000
Total debt	889,388	942,334
Less current maturities	'	'
Long-term debt	889,388	942,334
Senior Notes Seven Point Seven Five Percentage	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	275,000	275,000
Senior Notes Nine Point Two Five Percentage	'	'
Debt Instrument [Line Items]	'	'
Senior Notes	$248,388	$248,334

Debt_Credit_Facility_Details

Debt (Credit Facility) (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Line Of Credit Facility [Line Items]	'	'
Line of Credit Facility, Expiration Date	1-Jul-18	'
Letters Of Credit Outstanding Maximum	$20,000,000	'
Letters of Credit Outstanding, Amount	366,000,000	'
Line of Credit Facility, Interest Rate Description	'at either an adjusted LIBOR rate plus an applicable margin between 1.75% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and 1.75% per annum.	'
Revolving credit facility	366,000,000	419,000,000
Line of Credit Facility, Weighted Average Interest Rate	2.30%	'
Line of Credit Facility, Covenant Terms	'The Credit Agreement contains customary covenants that limit the Partnership’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a borrowing base deficiency or default exists or would result from the distribution, merger or consolidation with other persons, or engage in certain asset dispositions including a sale of all or substantially all of its assets. The Partnership was in compliance with these covenants as of March 31, 2014. The Credit Agreement also requires the Partnership to maintain a ratio of Total Funded Debt (as defined in the Credit Agreement) to EBITDA (as defined in the Credit Agreement) (actual or annualized, as applicable), calculated over a period of four consecutive fiscal quarters, of not greater than 4.50 to 1.0 as of the last day of the quarters ended March 31, 2014 and June 30, 2014, 4.25 to 1.0 as of the last day of the quarter ending September 30, 2014, and 4.00 to 1.0 as of the last day of fiscal quarters ending thereafter 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 March 31, 2014.	'
Required Total Funded Debt To EBITDA Ratio	'4.50 to 1.0	'4.50 to 1.0
Required Current Assets To Current Liabilities Ratio	'1.0 to 1.0	'
Total Funded Debt to EBITDA Ratio	'3.9 to 1.0	'
Current Assets To Current Liabilities Ratio	'2.1 to 1.0	'
Quarter ended June 30, 2014	'	'
Line Of Credit Facility [Line Items]	'	'
Required Total Funded Debt To EBITDA Ratio	'4.50 to 1.0	'
Quarter ended September 30, 2014	'	'
Line Of Credit Facility [Line Items]	'	'
Required Total Funded Debt To EBITDA Ratio	'4.25 to 1.0	'
Quarter Ended December 31, 2014	'	'
Line Of Credit Facility [Line Items]	'	'
Required Total Funded Debt To EBITDA Ratio	'4.00 to 1.0	'
Line of Credit	'	'
Line Of Credit Facility [Line Items]	'	'
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, Current Borrowing Capacity	735,000,000	'
Line of Credit Facility, Maximum Borrowing Capacity	1,500,000,000	'
Line of Credit Facility, Interest Rate Description	'The Partnership is also required to pay a fee on the unused portion of the borrowing base at a rate of 0.5% per annum if 50% or more of the borrowing base is utilized and 0.375% per annum if less than 50% of the borrowing base is utilized, which is included within interest expense on the Partnership’s consolidated statements of operations.	'
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%	'
Revolving credit facility	$3,700,000	'

Debt_Senior_Notes_Details

Debt (Senior Notes) (Details) (USD $)	3 Months Ended		1 Months Ended		3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Jul. 30, 2013	Mar. 31, 2014	Mar. 31, 2014
			Senior Notes Nine Point Two Five Percentage	Senior Notes Nine Point Two Five Percentage	Senior Notes Seven Point Seven Five Percentage
Debt Instrument [Line Items]	'	'	'	'	'
Debt Instrument, Issuance Date	'	'	30-Jul-13	'	23-Jan-13
Debt Instrument, Face Amount	'	'	$250	'	$275
Senior notes, interest rate	'	'	9.25%	'	7.75%
Senior notes, maturity	'	'	15-Aug-21	'	'
Debt Instrument, Interest Rate, Effective Percentage	'	'	99.30%	'	'
Proceeds from Debt, Net of Issuance Costs	'	'	242.8	'	267.6
Debt Instrument, Unamortized Discount	'	'	'	1.6	'
Senior Notes Interest Payment Dates and Terms	'	'	'Interest on the 9.25% Senior Notes accrued from July 30, 2013, and is payable semi-annually on February 15 and August 15, with the first interest payment date on February 15, 2014.	'	'
Debt Instrument, Call Feature	'	'	'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%. In addition, at any time prior to August 15, 2016, the Partnership may redeem up to 35% of the 9.25% Senior Notes with the proceeds received from certain equity offerings at a redemption price of 109.250%. 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.	'	'
Registration Rights Agreement, Description And Terms	'	'	'	'On March 28, 2014, the registration statement relating to the exchange offer for the 9.25% Senior Notes was declared effective, and the exchange offer was completed on April 29, 2014.	'On July 1, 2013, the Partnership filed a registration statement relating to the exchange offer for the 7.75% Senior Notes and the exchange offer was completed on January 2, 2014.
Deferred Finance Costs, Own-share Lending Arrangement, Issuance Costs, Amortization Expense	3.2	'	'	'	'
Line of Credit Facility, Interest Rate Description	'at either an adjusted LIBOR rate plus an applicable margin between 1.75% and 2.75% per annum or the base rate (which is the higher of the bank’s prime rate, the Federal funds rate plus 0.5% or one-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and 1.75% per annum.	'	'	'	'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, 2017, the 7.75% Senior Notes are redeemable, in whole or in part, at a redemption price as defined in the governing 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.
Line of Credit Facility, Collateral	'	'	'	'	'The 9.25% Senior Notes and 7.75% Senior Notes are guaranteed by certain of the Partnership’s material subsidiaries. The guarantees under the 9.25% Senior Notes and 7.75% Senior Notes are full and unconditional and joint and several, 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.
Restrictions as to the ability to obtain cash or any other distribution of funds from the guarantor	'	'	'	'	0
Debt Instrument, Restrictive Covenants	'The indentures governing the 9.25% Senior Notes and 7.75% Senior Notes contain covenants, including limitations of 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 March 31, 2014.	'	'	'	'
Cash Payments For Interest On Debt	$26.50	$2.40	'	'	'

Derivative_Instruments_Narrati

Derivative Instruments (Narrative) (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
			Gas And Oil Production Revenue	Gas And Oil Production Revenue
Cash Flow Hedges Derivative Instruments at Fair Value, Net	$1,500,000	$22,600,000	'	'
Net gain in accumulated other comprehensive income	4,898,000	25,699,000	'	'
Cash Flow Hedge Gain (Losses) to be Reclassified within Twelve Months	22,400,000	'	'	'
Cash Flow Hedge Gain (Loss) To Be Reclassified In Later Periods	27,300,000	'	'	'
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0	0	-14,043,000	993,000
Gains recognized on settled contracts covering commodity production	'	'	'	1,000,000
Loss recognized on settled contracts covering commodity production	'	'	14,000,000	'
Gain (Loss) Recognized for Hedge Ineffectiveness or as a Result of Discontinuance of Cash Flow Hedges	'	'	0	0
Hedge Monetization Cash Proceeds	1,900,000	'	'	'
Net Unrealized Derivative Assets Payable To Limited Partners	$1,100,000	'	'	'

Derivative_Instruments_Summary

Derivative Instruments (Summary of Gain or Loss Derivative Instruments Recognized In Statements of Operations) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
(Gain) loss reclassified from accumulated other comprehensive income:	$0	$0	'
(Gain) loss reclassified from accumulated other comprehensive income:	14,043	'	-993
Gas And Oil Production Revenue	'	'	'
(Gain) loss reclassified from accumulated other comprehensive income:	14,043	'	-993
(Gain) loss reclassified from accumulated other comprehensive income:	$14,043	'	($993)

Derivative_Instruments_Fair_Va

Derivative Instruments (Fair Value of the Partnership's Derivative Instruments Table) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Assets	$30,516	$38,273
Gross Amounts of Recognized Liabilities	-28,991	-15,718
Current portion of derivative assets	'	'
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Assets	161	2,664
Gross Amounts Offset in the Consolidated Balance Sheets	'	-773
Net Amount of Assets Presented in the Consolidated Balance Sheets	161	1,891
Gross Amounts of Recognized Liabilities	'	-773
Gross Amounts Offset in the Consolidated Balance Sheets	'	773
Long-term portion of derivative assets	'	'
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Assets	25,859	31,146
Gross Amounts Offset in the Consolidated Balance Sheets	-2,110	-4,062
Net Amount of Assets Presented in the Consolidated Balance Sheets	23,749	27,084
Gross Amounts of Recognized Liabilities	-2,110	-4,062
Gross Amounts Offset in the Consolidated Balance Sheets	2,110	4,062
Current portion of derivative liabilities	'	'
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Assets	4,382	4,341
Gross Amounts Offset in the Consolidated Balance Sheets	-4,382	-4,341
Gross Amounts of Recognized Liabilities	-26,754	-10,694
Gross Amounts Offset in the Consolidated Balance Sheets	4,382	4,341
Net Amount of Liabilities Presented in the Consolidated Balance Sheets	-22,372	-6,353
Long-term portion of derivative liabilities	'	'
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Assets	114	122
Gross Amounts Offset in the Consolidated Balance Sheets	-114	-122
Gross Amounts of Recognized Liabilities	-127	-189
Gross Amounts Offset in the Consolidated Balance Sheets	114	122
Net Amount of Liabilities Presented in the Consolidated Balance Sheets	-13	-67
Total derivative assets	'	'
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Assets	30,516	38,273
Gross Amounts Offset in the Consolidated Balance Sheets	-6,606	-9,298
Net Amount of Assets Presented in the Consolidated Balance Sheets	23,910	28,975
Total derivative liabilities	'	'
Derivatives Fair Value [Line Items]	'	'
Gross Amounts of Recognized Liabilities	-28,991	-15,718
Gross Amounts Offset in the Consolidated Balance Sheets	6,606	9,298
Net Amount of Liabilities Presented in the Consolidated Balance Sheets	($22,385)	($6,420)

Derivative_Instruments_Commodi

Derivative Instruments (Commodity Derivative Instruments by Type Table) (Details) (USD $)	Mar. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives Fair Value [Line Items]	'		'
Cash Flow Hedges Derivative Instruments at Fair Value, Net	$1,500		$22,600
Natural Gas Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	2,964	[1]	'
Natural Gas Costless Collars	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	1,139	[1]	'
Natural Gas Put Options Drilling Partnerships	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	1,144	[1]	'
WAHA Basis Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	-42	[1]	'
Natural Gas Liquids Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	-396	[2]	'
Natural Gas Liquids Ethane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	25	[3]	'
Natural Gas Liquids Propane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	-876	[4]	'
Natural Gas Liquids Butane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	63	[5]	'
Natural Gas Liquids Iso Butane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	57	[6]	'
Crude Oil Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	-2,622	[2]	'
Crude Oil Costless Collars	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	69	[2]	'
Cash Flow Hedges Derivative Instruments at Fair Value, Net	1,525	[2]	'
Production Period Ending December 31 2014 | Natural Gas Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	45,114,700	[7]	'
Derivative, Swap Type, Average Fixed Price	4.152	[7]	'
Fair Value Asset / (Liability)	-14,068	[1]	'
Production Period Ending December 31 2014 | Natural Gas Costless Collars | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	2,880,000	[7]	'
Fair Value Asset / (Liability)	642	[1]	'
Average Floor And Cap	4.221	[7]	'
Production Period Ending December 31 2014 | Natural Gas Costless Collars | Calls Sold	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	2,880,000	[7]	'
Fair Value Asset / (Liability)	-418	[1]	'
Average Floor And Cap	5.12	[7]	'
Production Period Ending December 31 2014 | Natural Gas Put Options Drilling Partnerships | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	1,350,000	[7]	'
Derivative, Swap Type, Average Fixed Price	3.8	[7]	'
Fair Value Asset / (Liability)	84	[1]	'
Production Period Ending December 31 2014 | WAHA Basis Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	8,100,000	[7]	'
Derivative, Swap Type, Average Fixed Price	-0.11	[7]	'
Fair Value Asset / (Liability)	-42	[1]	'
Production Period Ending December 31 2014 | Natural Gas Liquids Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	91.568	[7]	'
Fair Value Asset / (Liability)	-486	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	79,500	[7]	'
Production Period Ending December 31 2014 | Natural Gas Liquids Ethane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	0.303	[7]	'
Fair Value Asset / (Liability)	25	[3]	'
Derivatives Nonmonetary Volume Notional Amount Gallons	1,890,000	[7]	'
Production Period Ending December 31 2014 | Natural Gas Liquids Propane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	1	[7]	'
Fair Value Asset / (Liability)	-727	[4]	'
Derivatives Nonmonetary Volume Notional Amount Gallons	9,261,000	[7]	'
Production Period Ending December 31 2014 | Natural Gas Liquids Butane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	1.308	[7]	'
Fair Value Asset / (Liability)	35	[5]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	1,134,000	[7]	'
Production Period Ending December 31 2014 | Natural Gas Liquids Iso Butane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	1.323	[7]	'
Fair Value Asset / (Liability)	33	[6]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	1,134,000	[7]	'
Production Period Ending December 31 2014 | Crude Oil Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	92.692	[7]	'
Fair Value Asset / (Liability)	-2,091	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	409,500	[7]	'
Production Period Ending December 31 2014 | Crude Oil Costless Collars | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	38	[2]	'
Average Floor And Cap	84.169	[7]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	30,870	[7]	'
Production Period Ending December 31 2014 | Crude Oil Costless Collars | Calls Sold	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	-33	[2]	'
Average Floor And Cap	113.308	[7]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	30,870	[7]	'
Production Period Ending December 31 2015 | Natural Gas Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	51,924,500	[7]	'
Derivative, Swap Type, Average Fixed Price	4.239	[7]	'
Fair Value Asset / (Liability)	1,799	[1]	'
Production Period Ending December 31 2015 | Natural Gas Costless Collars | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	3,480,000	[7]	'
Fair Value Asset / (Liability)	1,636	[1]	'
Average Floor And Cap	4.234	[7]	'
Production Period Ending December 31 2015 | Natural Gas Costless Collars | Calls Sold	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	3,480,000	[7]	'
Fair Value Asset / (Liability)	-721	[1]	'
Average Floor And Cap	5.129	[7]	'
Production Period Ending December 31 2015 | Natural Gas Put Options Drilling Partnerships | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	1,440,000	[7]	'
Derivative, Swap Type, Average Fixed Price	4	[7]	'
Fair Value Asset / (Liability)	447	[1]	'
Production Period Ending December 31 2015 | Natural Gas Liquids Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	88.55	[7]	'
Fair Value Asset / (Liability)	-129	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	96,000	[7]	'
Production Period Ending December 31 2015 | Natural Gas Liquids Propane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	1.016	[7]	'
Fair Value Asset / (Liability)	-149	[4]	'
Derivatives Nonmonetary Volume Notional Amount Gallons	8,064,000	[7]	'
Production Period Ending December 31 2015 | Natural Gas Liquids Butane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	1.248	[7]	'
Fair Value Asset / (Liability)	28	[5]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	1,512,000	[7]	'
Production Period Ending December 31 2015 | Natural Gas Liquids Iso Butane Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	1.263	[7]	'
Fair Value Asset / (Liability)	24	[6]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	1,512,000	[7]	'
Production Period Ending December 31 2015 | Crude Oil Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	88.144	[7]	'
Fair Value Asset / (Liability)	-969	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	567,000	[7]	'
Production Period Ending December 31 2015 | Crude Oil Costless Collars | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	125	[2]	'
Average Floor And Cap	83.846	[7]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	29,250	[7]	'
Production Period Ending December 31 2015 | Crude Oil Costless Collars | Calls Sold	'		'
Derivatives Fair Value [Line Items]	'		'
Fair Value Asset / (Liability)	-61	[2]	'
Average Floor And Cap	110.654	[7]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	29,250	[7]	'
Production Period Ending December 31 2016 | Natural Gas Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	45,746,300	[7]	'
Derivative, Swap Type, Average Fixed Price	4.311	[7]	'
Fair Value Asset / (Liability)	7,193	[1]	'
Production Period Ending December 31 2016 | Natural Gas Put Options Drilling Partnerships | Puts Purchased	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	1,440,000	[7]	'
Derivative, Swap Type, Average Fixed Price	4.15	[7]	'
Fair Value Asset / (Liability)	613	[1]	'
Production Period Ending December 31 2016 | Natural Gas Liquids Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	85.651	[7]	'
Fair Value Asset / (Liability)	92	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	84,000	[7]	'
Production Period Ending December 31 2016 | Crude Oil Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	85.523	[7]	'
Fair Value Asset / (Liability)	218	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	225,000	[7]	'
Production Period Ending December 31 2017 | Natural Gas Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	24,840,000	[7]	'
Derivative, Swap Type, Average Fixed Price	4.532	[7]	'
Fair Value Asset / (Liability)	6,734	[1]	'
Production Period Ending December 31 2017 | Natural Gas Liquids Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	83.78	[7]	'
Fair Value Asset / (Liability)	127	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	60,000	[7]	'
Production Period Ending December 31 2017 | Crude Oil Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivative, Swap Type, Average Fixed Price	83.305	[7]	'
Fair Value Asset / (Liability)	220	[2]	'
Derivatives Nonmonetary Volume Notional Amount Barrels Of Oil	132,000	[7]	'
Production Period Ending December 31 2018 | Natural Gas Fixed Price Swaps	'		'
Derivatives Fair Value [Line Items]	'		'
Derivatives Nonmonetary Volume Notional Amount Millions British Thermal Units	3,960,000	[7]	'
Derivative, Swap Type, Average Fixed Price	4.716	[7]	'
Fair Value Asset / (Liability)	$1,306	[1]	'
[1]	Fair value based on forward NYMEX natural gas prices, as applicable.
[2]	Fair value based on forward WTI crude oil prices, as applicable.
[3]	Fair value based on forward Mt. Belvieu ethane prices, as applicable.
[4]	Fair value based on forward Mt. Belvieu propane prices, as applicable.
[5]	Fair value based on forward Mt. Belvieu butane prices, as applicable.
[6]	Fair value based on forward Mt. Belvieu iso butane prices, as applicable
[7]	“MMBtu” represents million British Thermal Units; “Bbl” represents barrels; “Gal” represents gallons.

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Schedule of Assets/Liabilities at Fair Value) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Gross Amounts of Recognized Assets	$30,516	$38,273
Gross Amounts of Recognized Liabilities	-28,991	-15,718
Total derivatives, fair value, net	1,525	22,555
Level 1	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Total derivatives, fair value, net	'	'
Level 2	'	'
Gross Amounts of Recognized Assets	30,516	38,273
Gross Amounts of Recognized Liabilities	-28,991	-15,718
Total derivatives, fair value, net	1,525	22,555
Level 3	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Total derivatives, fair value, net	'	'
Commodity Swaps	'	'
Gross Amounts of Recognized Assets	26,771	33,594
Gross Amounts of Recognized Liabilities	-27,556	-14,624
Commodity Swaps | Level 1	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Commodity Swaps | Level 2	'	'
Gross Amounts of Recognized Assets	26,771	33,594
Gross Amounts of Recognized Liabilities	-27,556	-14,624
Commodity Swaps | Level 3	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Commodity Basis Swaps	'	'
Gross Amounts of Recognized Assets	159	'
Gross Amounts of Recognized Liabilities	-201	'
Commodity Basis Swaps | Level 1	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Commodity Basis Swaps | Level 2	'	'
Gross Amounts of Recognized Assets	159	'
Gross Amounts of Recognized Liabilities	-201	'
Commodity Basis Swaps | Level 3	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Commodity Puts	'	'
Gross Amounts of Recognized Assets	1,144	1,374
Commodity Puts | Level 1	'	'
Gross Amounts of Recognized Assets	'	'
Commodity Puts | Level 2	'	'
Gross Amounts of Recognized Assets	1,144	1,374
Commodity Puts | Level 3	'	'
Gross Amounts of Recognized Assets	'	'
Commodity Option	'	'
Gross Amounts of Recognized Assets	2,442	3,305
Gross Amounts of Recognized Liabilities	-1,234	-1,094
Commodity Option | Level 1	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'
Commodity Option | Level 2	'	'
Gross Amounts of Recognized Assets	2,442	3,305
Gross Amounts of Recognized Liabilities	-1,234	-1,094
Commodity Option | Level 3	'	'
Gross Amounts of Recognized Assets	'	'
Gross Amounts of Recognized Liabilities	'	'

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Long-term Debt, Fair Value	$925,900,000	'	$938,600,000
Long-term debt	889,388,000	'	942,334,000
Asset impairment	$0	$0	$38,000,000
Level 3	'	'	'
Conversion of Stock Conversion Price	$23.10	'	'
Fair Value Inputs, Discount Rate	0.21%	'	'
Fair Value Assumptions, Expected Volatility Rate	35.00%	'	'

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments (Schedule of Assets and Liabilities Measured on Non Recurring Basis) (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013
In Thousands, unless otherwise specified
Fair value, liabilities	$529	$645
Level 3	'	'
Fair value, liabilities	529	645
Asset Retirement Obligations	'	'
Fair value, liabilities	529	645
Asset Retirement Obligations | Level 3	'	'
Fair value, liabilities	$529	$645

Certain_Relationships_and_Rela1

Certain Relationships and Related Party Transactions (Relationship with Laurel Mountain) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Relationship With Drilling Partnerships	'	'
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Description of Transaction	'The Partnership conducts certain activities through, and a portion of its revenues are attributable to, 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 APL	'	'
Related Party Transaction [Line Items]	'	'
Related Party Transaction, Description of Transaction	'In the Chattanooga Shale, a portion of the natural gas produced by the Partnership is gathered and processed by APL. For the three months ended March 31, 2014 and 2013, $0.1 million and $0.1 million, respectively, of gathering fees were paid by the Partnership to APL.	'
Gathering Fees Paid	$0.10	$0.10

Commitments_and_Contingencies_

Commitments and Contingencies (General Commitments) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Minimum Investor Partners Return On Investment	10.00%	'
Net partnership revenues subordinated	$3.50	$2.10
Maximum Investor Partners Return On Investment	12.00%	'
Long-term Purchase Commitment, Amount	10.3	'
EP Energy Acquisition	'	'
Contractual Obligation, Due in Next Twelve Months	6.6	'
Contractual Obligation, Due in Second Year	8.6	'
Contractual Obligation, Due in Third Year	2.1	'
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%	'
Maximum	'	'
Partnership obligations to purchase units from investor partners	10.00%	'

Issuances_of_Units_Details

Issuances of Units (Details) (USD $)	3 Months Ended	1 Months Ended		6 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended
	Mar. 31, 2014	Jul. 31, 2013	Jun. 10, 2013	Jun. 30, 2013	Mar. 31, 2014	Jun. 10, 2013	Mar. 31, 2014	Jul. 31, 2013
		EP Energy Acquisition	EP Energy Acquisition	EP Energy Acquisition	Over-Allotment Units Issued	Over-Allotment Units Issued	Equity Distribution Agreement with Deutsche Bank Securities Inc.	Atlas Parent Company "ATLS"
						EP Energy Acquisition		Class C Convertible Preferred Units
								EP Energy Acquisition
Partners' Capital Account, Units, Date Of Sale	'March 2014	'	'	'June 2013	'	'	'	'
Partners' Capital Account, Units, Sale of Units	6,325,000	14,950,000	14,950,000	'	825,000	1,950,000	309,174	3,749,986
Subsidiary or Equity Method Investee, Price-Per-Share	$21.18	'	$21.75	'	'	'	'	$23.10
Partners' Capital Account, Sale of Units	$129,000,000	'	$313,100,000	'	'	'	'	'
Issuance of units	129,011,000	'	'	'	'	'	'	86,600,000
Preferred Units, Description	'	'	'	'	'	'	'	'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 initial Class C preferred distribution was paid for the quarter ending September 30, 2013. 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.
Equity Distribution Agreement Commencement Date	'	'	'	'	'	'	1-May-13	'
Aggregate Offering Price Of Common Units (Maximum)	'	'	'	'	'	'	25,000,000	'
Net proceeds from issuance of common limited partner units	129,011,000	'	'	'	'	'	6,900,000	'
Payments for Commissions	'	'	'	'	'	'	$400,000	'
Equity Distribution Agreement Effective Date	'	'	'	'	'	'	27-Dec-13	'

Cash_Distributions_Schedule_of

Cash Distributions (Schedule of Common Unit and General Partner Distributions) (Additional Information) (Details) (USD $)

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

In Millions, except Per Share data, unless otherwise specified

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Apr. 23, 2014

Apr. 23, 2014

Apr. 23, 2014

Apr. 23, 2014

Mar. 31, 2014

Mar. 31, 2014

Subsequent Event

Subsequent Event

Subsequent Event

Subsequent Event

Minimum

Maximum

Cash Distribution Declared

Cash Distribution Paid

Cash Distribution Paid

Cash Distribution Paid

General Partners’ Interest

Preferred Partner

Percentage of Distributions in Excess of Targets

'

'

'

'

'

'

'

'

'

'

13.00%

48.00%

Distribution Made to Limited Partner, Distributions Declared, Per Unit

$0.19

$0.19

$0.58

$0.56

$0.54

$0.51

$0.19

'

'

'

'

'

Distribution Made to Limited Partner, Declaration Date

'

'

'

'

'

'

23-Apr-14

'

'

'

'

'

Distribution Made to Limited Partner, Cash Distributions Paid

'

'

'

'

'

'

'

$15.30

$1.10

$1.50

'

'

Distribution Made to Member or Limited Partner, Distribution Date

'

'

'

'

'

'

'

15-May-14

'

'

'

'

Distribution Made to Member or Limited Partner, Date of Record

'

'

'

'

'

'

'

7-May-14

'

'

'

'

Distributions_Declared_by_Part

Distributions Declared by Partnership (Details) (USD $)

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Common Limited Partners’ Interests

Common Limited Partners’ Interests

Common Limited Partners’ Interests

Common Limited Partners’ Interests

Common Limited Partners’ Interests

Common Limited Partners’ Interests

Preferred Partner

Preferred Partner

Preferred Partner

Preferred Partner

Preferred Partner

Preferred Partner

General Partners’ Interest

General Partners’ Interest

General Partners’ Interest

General Partners’ Interest

General Partners’ Interest

General Partners’ Interest

Cash And Cash Equivalents [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Distributions Declared, Per Unit

$0.19

$0.19

$0.58

$0.56

$0.54

$0.51

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Distribution Made to Limited Partner, Cash Distributions Paid

'

'

'

'

'

'

'

'

'

'

'

'

$12,719

$12,718

$34,489

$33,291

$32,097

$22,428

$1,466

$1,467

$4,400

$4,248

$2,072

$1,957

$1,055

$1,055

$2,891

$2,443

$1,884

$946

Distribution Made to Member or Limited Partner, Distribution Date

'

'

'

'

'

'

15-May-13

14-Aug-13

14-Nov-13

14-Feb-14

17-Mar-14

14-Apr-14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Benefit_Plans_2012_Long_Term_I

Benefit Plans (2012 Long Term Incentive Plan Narrative) (Details) (Partnership 2012 Long Term Incentive Plan)	3 Months Ended
	Mar. 31, 2014
Partnership 2012 Long Term Incentive Plan	'
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	2,284,983
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	372,711

Benefit_Plans_2012_LTIP_Phanto

Benefit Plans (2012 LTIP Phantom Units Activity) (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'		'		'
Distribution Equivalent Rights Paid On Unissued Units Under Incentive Plans	$634,000		$500,000		'
Partnership 2012 Long Term Incentive Plans - Phantom Units	'		'		'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	'Phantom units granted under the 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	275,545		'		'
Outstanding, beginning of year (Units)	839,808		948,476		'
Granted (Units)	3,500		83,250		'
Vested and issued (Units)	-15,500	[1]	-2,465	[1]	'
Forfeited (Units)	-15,500		-4,000		'
Outstanding, end of year (Units)	812,308	[2],[3]	1,025,261	[2],[3]	'
Vested and not yet issued (Units)	6,875	[4]	'		'
Outstanding, beginning of year	$24.31		$24.76		'
Granted	$20.99		$21.96		'
Vested and issued	$22.69	[1]	$24.67	[1]	'
Forfeited	$22.63		$25.14		'
Outstanding, end of year	$24.35	[2],[3]	$24.53	[2],[3]	'
Vested and not yet issued	$22.76	[4]	'		'
Non-cash compensation expense recognized	1,731,000		3,053,000		'
Share Based Compensation Arrangement By Share Based Payment Award Other Than Options Outstanding Intrinsic Value	17,000,000		'		'
Liabilities Related to Outstanding Phantom Units	100,000		44,000		100,000
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Units Classified Within Liabilities	16,084		3,476		16,084
Share Based Compensation By Share Based Payment Award Equity Instruments Other Than Options Nonvested Weighted Average Grant Date Fair Value Units Classified Within Liabilities	$22.15		$28.75		$22.15
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Units Other Than Options Vested In Period Intrinsic Value	300,000		100,000		'
Unrecognized compensation expense related to unvested units	$6,900,000		'		'
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%		'		'
[1]	The intrinsic value of phantom unit awards vested and issued during the three months ended March 31, 2014 and 2013 was $0.3 million and $0.1 million, respectively.
[2]	The aggregate intrinsic value for phantom unit awards outstanding at March 31, 2014 was $17.0 million.
[3]	There was $0.1 million recognized as liabilities on the Partnership’s consolidated balance sheets at the periods ended March 31, 2014 and December 31, 2013, representing 16,084 units for the periods ending March 31, 2014 and December 31, 2013 due to the option of the participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $22.15 for the periods ending March 31, 2014 and December 31, 2013, respectively. There was approximately $44,000 recognized as liabilities on the Partnership’s consolidated balance sheet at March 31, 2013, representing 3,476 units, due to the option of the participants to settle in cash instead of units. The weighted average grant date fair value for these units was $28.75 at March 31, 2013.
[4]	The intrinsic value of phantom unit awards vested, but not yet issued at March 31, 2014 was $0.1 million. No phantom unit awards had vested, but had not yet been issued at March 31, 2013.

Benefit_Plans_2012_Unit_Option

Benefit Plans (2012 Unit Option Activity) (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
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%		'
Partnership 2012 Long Term Incentive Plans - Unit Options	'		'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'		'
Years From Date Of Grant Unit Option Awards Expire	'10 years		'
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	367,575		'
Proceeds From Stock Options Exercised	$0		$0
Outstanding, beginning of year (Units)	1,482,675		1,515,500
Granted (Units)	'		2,000
Exercised (Units)	'	[1]	'	[1]
Forfeited (Units)	-10,000		-4,000
Outstanding, end of year (Units)	1,472,675	[2],[3]	1,513,500	[2],[3]
Options Exercisable (Units)	368,825	[4]	'	[4]
Outstanding, beginning of year	$24.66		$24.68
Granted	'		$22.27
Exercised	'	[1]	'	[1]
Forfeited	$23.40		$25.14
Outstanding, end of period	$24.66	[2],[3]	$24.67	[2],[3]
Options exercisable	$24.67	[4]	'	[4]
Non-cash compensation expense recognized	612,000		1,194,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	0		0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	'8 years 1 month 6 days		'
Aggregate Intrinsic Value Of Options Outstanding	2,000		'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'8 years 1 month 6 days		'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	0		0
Unrecognized compensation expense related to unvested unit options	$2,200,000		'
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.		'
Expected dividend yield	'		6.60%
Expected unit price volatility	'		44.00%
Risk-free interest rate	'		1.10%
Expected term (in years)	'0 years		'6 years 3 months
Fair value of unit options granted	'		$4.85
[1]	No options were exercised during the three months ended March 31, 2014, and 2013, respectively.
[2]	The weighted average remaining contractual life for outstanding options at March 31, 2014 was 8.1 years.
[3]	The aggregate intrinsic value of options outstanding at March 31, 2014 was approximately $2,000.
[4]	The weighted average remaining contractual life for exercisable options at March 31, 2014 was 8.1 years. There were no intrinsic values for options exercisable at March 31, 2014 and 2013.

Operating_Segment_Information_1

Operating Segment Information (Narrative) (Details)	3 Months Ended
	Mar. 31, 2014
	Segment
Segment Reporting Information [Line Items]	'
Number of reportable operating segments	3

Operating_Segment_Information_2

Operating Segment Information (Operating Segment Data) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Segment Reporting Information [Line Items]	'		'
Revenues	$157,345		$112,048
Depreciation, depletion and amortization expense	-50,237		-21,208
Segment income	20,485		19,781
Operating Segments | Gas And Oil Production	'		'
Segment Reporting Information [Line Items]	'		'
Revenues	96,245		46,064
Operating costs and expenses	-36,792		-15,216
Depreciation, depletion and amortization expense	-48,029		-19,696
Segment income	11,424		11,152
Operating Segments | Well Construction And Completion	'		'
Segment Reporting Information [Line Items]	'		'
Revenues	49,377		56,478
Operating costs and expenses	-42,936		-49,112
Segment income	6,441		7,366
Operating Segments | Other Partnership Management	'		'
Segment Reporting Information [Line Items]	'		'
Revenues	11,723	[1]	9,506	[1]
Operating costs and expenses	-6,895	[1]	-6,731	[1]
Depreciation, depletion and amortization expense	-2,208	[1]	-1,512	[1]
Segment income	$2,620	[1]	$1,263	[1]
[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.

Operating_Segment_Information_3

Operating Segment Information (Reconciliation Of Segment Income (Loss) To Net Income (Loss) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014		Mar. 31, 2013
Segment Reporting Information [Line Items]	'		'
Total segment income (loss)	$20,485		$19,781
General and administrative expenses	-16,455	[1]	-17,567	[1]
Interest expense	-13,188	[1]	-6,889	[1]
Loss on asset sales and disposal	-1,603	[1]	-702	[1]
Net loss	-10,761		-5,377
Operating Segments | Gas And Oil Production	'		'
Segment Reporting Information [Line Items]	'		'
Total segment income (loss)	11,424		11,152
Operating Segments | Well Construction And Completion	'		'
Segment Reporting Information [Line Items]	'		'
Total segment income (loss)	6,441		7,366
Operating Segments | Other Partnership Management	'		'
Segment Reporting Information [Line Items]	'		'
Total segment income (loss)	$2,620	[2]	$1,263	[2]
[1]	Loss on asset sales and disposal, general and administrative expenses and interest expense have not been allocated to its reportable segments as it would be impracticable to reasonably do so for the periods presented.
[2]	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_Information_4

Operating Segment Information (Capital Expenditures) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Segment Reporting Information [Line Items]	'	'
Capital expenditures	$39,897	$58,487
Operating Segments | Gas And Oil Production	'	'
Segment Reporting Information [Line Items]	'	'
Capital expenditures	34,983	55,773
Operating Segments | Other Partnership Management	'	'
Segment Reporting Information [Line Items]	'	'
Capital expenditures	3,340	912
Operating Segments | Corporate and Other	'	'
Segment Reporting Information [Line Items]	'	'
Capital expenditures	$1,574	$1,802

Operating_Segment_Information_5

Operating Segment Information (Balance Sheet) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
In Thousands, unless otherwise specified
Segment Reporting Information [Line Items]	'	'	'
Goodwill	$31,784	$31,784	$31,784
Total assets	2,321,905	2,343,800	2,343,800
Operating Segments | Gas And Oil Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Goodwill	18,145	'	18,145
Total assets	2,193,901	'	2,170,712
Operating Segments | Well Construction And Completion	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Goodwill	6,389	'	6,389
Total assets	7,204	'	55,031
Operating Segments | Other Partnership Management	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Goodwill	7,250	'	7,250
Total assets	56,199	'	56,493
Operating Segments | Corporate and Other	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Total assets	$64,601	'	$61,564

Subsequent_Events_Cash_Distrib

Subsequent Events (Cash Distribution) (Details) (USD $)	1 Months Ended		3 Months Ended				1 Months Ended		0 Months Ended	1 Months Ended
In Millions, except Per Share data, unless otherwise specified	Feb. 28, 2014	Jan. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Apr. 23, 2014	Apr. 23, 2014	7-May-14	Apr. 23, 2014	Apr. 23, 2014
							Subsequent Event	Subsequent Event	Subsequent Event	Subsequent Event	Subsequent Event
							Cash Distribution Declared	Cash Distribution Paid	Merit	General Partners’ Interest	Preferred Partner
										Cash Distribution Paid	Cash Distribution Paid
Subsequent Event [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Distribution Made to Limited Partner, Declaration Date	'	'	'	'	'	'	23-Apr-14	'	'	'	'
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$0.19	$0.19	$0.58	$0.56	$0.54	$0.51	$0.19	'	'	'	'
Distribution Made to Limited Partner, Cash Distributions Paid	'	'	'	'	'	'	'	$15.30	'	$1.10	$1.50
Distribution Made to Member or Limited Partner, Distribution Date	'	'	'	'	'	'	'	15-May-14	'	'	'
Distribution Made to Member or Limited Partner, Date of Record	'	'	'	'	'	'	'	7-May-14	'	'	'
Business Acquisition, Cost of Acquired Entity, Cash Paid	'	'	'	'	'	'	'	'	$420	'	'
Business Acquisition Closing Date Of Acquisition	'	'	'	'	'	'	'	'	1-Apr-14	'	'