PVR Partners, L. P. (PVR) 10-K 28 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2013	Jan. 15, 2014	Jan. 15, 2014
			Common Units	Class B Units
Document Information [Line Items]	'	'	'	'
Document Type	'10-K	'	'	'
Amendment Flag	'false	'	'	'
Document Period End Date	31-Dec-13	'	'	'
Document Fiscal Year Focus	'2013	'	'	'
Document Fiscal Period Focus	'FY	'	'	'
Trading Symbol	'PVR	'	'	'
Entity Registrant Name	'PVR PARTNERS, L. P.	'	'	'
Entity Central Index Key	'0001144945	'	'	'
Current Fiscal Year End Date	'--12-31	'	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'	'
Entity Current Reporting Status	'Yes	'	'	'
Entity Voluntary Filers	'No	'	'	'
Entity Filer Category	'Large Accelerated Filer	'	'	'
Entity Common Stock, Shares Outstanding	'	'	112,189,636	24,305,507
Entity Public Float	'	$2,114,352,322	'	'

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues	'	'	'
Natural gas	$374,226	$315,242	$426,690
Natural gas liquids	413,621	424,538	500,658
Gathering fees	105,115	53,831	20,409
Trunkline fees	98,847	47,002	17,454
Coal royalties	88,075	114,133	162,915
Other	37,602	53,008	31,849
Total revenues	1,117,486	1,007,754	1,159,975
Expenses	'	'	'
Cost of gas purchased	666,239	630,345	817,937
Operating	67,977	68,316	57,611
General and administrative	54,508	47,452	41,480
Merger and acquisition costs	8,138	14,049	'
Impairments	'	124,845	'
Depreciation, depletion and amortization	187,941	127,344	89,376
Total expenses	984,803	1,012,351	1,006,404
Operating income (loss)	132,683	-4,597	153,571
Other income (expense)	'	'	'
Interest expense	-106,248	-68,773	-44,287
Loss on extinguishment of debt	-13,703	'	'
Derivatives	-1,070	2,291	-13,442
Other	1,332	457	501
Net income (loss)	12,994	-70,622	96,343
Net loss attributable to noncontrolling interests, pre-PVR-PVG merger (Note 1)	'	'	664
Net income (loss) attributable to PVR Partners, L.P.	$12,994	($70,622)	$97,007
Earnings (loss) per common unit, basic and diluted	($0.83)	($1.43)	$1.45
Weighted average number of common units outstanding, basic and diluted	99,304	86,222	66,342

Consolidated_Statements_Of_Com

Consolidated Statements Of Comprehensive Income (Loss) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income (loss)	$12,994	($70,622)	$96,343
Reclassification adjustment for derivative activities	'	-743	334
Comprehensive income (loss)	$12,994	($71,365)	$96,677

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$7,298	$14,713
Accounts receivable, net of allowance for doubtful accounts	147,978	133,546
Assets held for sale	'	11,450
Other current assets	6,821	5,446
Total current assets	162,097	165,155
Property, plant and equipment	2,837,217	2,479,802
Accumulated depreciation, depletion and amortization	-647,939	-490,456
Net property, plant and equipment	2,189,278	1,989,346
Equity investments	60,782	97,553
Goodwill	70,283	70,283
Intangible assets (net of accumulated amortization of $71,972 and $41,452)	590,080	620,600
Other long-term assets	53,150	55,772
Total assets	3,125,670	2,998,709
Current liabilities	'	'
Accounts payable and accrued liabilities	142,225	197,034
Deferred income	6,214	3,788
Total current liabilities	148,439	200,822
Deferred income	12,311	15,212
Other liabilities	18,284	20,256
Senior notes	1,172,600	900,000
Revolving credit facility	562,500	590,000
Commitments and contingencies (Note 17)	'	'
Partners' capital	'	'
Partners' capital	1,211,536	1,272,419
Total liabilities and partners' capital	3,125,670	2,998,709
Common Units	'	'
Partners' capital	'	'
Partners' capital	802,644	671,386
Class B Units	'	'
Partners' capital	'	'
Partners' capital	408,892	406,553
Special Units	'	'
Partners' capital	'	'
Partners' capital	'	$194,480

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Intangible assets, accumulated amortization	$71,972	$41,452
Units outstanding	112,200,000	'
Common Units	'	'
Units outstanding	112,189,435	95,633,319
Class B Units	'	'
Units outstanding	24,305,507	22,305,788
Special Units	'	'
Units outstanding	'	10,346,257

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities	'	'	'
Net income (loss)	$12,994	($70,622)	$96,343
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Loss on extinguishment of debt	13,703	'	'
Gain on sale of assets	-14,302	-31,292	'
Depreciation, depletion and amortization	187,941	127,344	89,376
Impairments	'	124,845	'
Derivative Contracts:	'	'	'
Total derivative losses (gains)	1,070	-2,291	13,442
Cash payments to settle derivatives	-766	-10,279	-25,688
Non-cash interest expense	7,306	5,824	5,779
Non-cash unit-based compensation	4,159	4,428	3,845
Equity earnings, net of distributions received and impairment	7,642	11,308	8,460
Other	-3,460	-1,032	-985
Changes in operating assets and liabilities	'	'	'
Accounts receivable	-14,989	-28,892	-3,536
Accounts payable and accrued liabilities	2,936	10,082	6,011
Deferred income	253	5,092	-694
Other assets and liabilities	-1,041	746	-2,023
Net cash provided by operating activities	203,446	145,261	190,330
Cash flows from investing activities	'	'	'
Acquisitions	-2,334	-850,156	-146,003
Additions to property, plant and equipment	-413,451	-512,375	-230,599
Joint venture capital contributions	-15,800	-37,200	-500
Proceeds from sale of assets	70,592	62,271	'
Other	2,530	1,286	2,875
Net cash used in investing activities	-358,463	-1,336,174	-374,227
Cash flows from financing activities	'	'	'
Distributions to partners	-214,442	-176,256	-135,296
Net proceeds from equity offering	138,044	743,448	189,164
Proceeds from issuance of senior notes	400,000	600,000	'
Payments to extinguish debt	-138,070	'	'
Proceeds from borrowings	610,000	574,000	345,500
Repayments of borrowings	-637,500	-525,000	-212,500
Cash paid for debt issuance costs	-9,772	-19,206	-3,675
Other	-658	'	-6,620
Net cash provided by financing activities	147,602	1,196,986	176,573
Net increase (decrease) in cash and cash equivalents	-7,415	6,073	-7,324
Cash and cash equivalents - beginning of period	14,713	8,640	15,964
Cash and cash equivalents - end of period	7,298	14,713	8,640
Supplemental disclosure:	'	'	'
Cash paid for interest	109,386	75,650	48,780
Noncash investing activities:	'	'	'
Other assets acquired related to acquisition	'	4,827	'
Other liabilities assumed related to acquisition	'	33,499	2,434
Contribution of license agreement to joint venture	'	'	4,795
Special units issued as consideration in an acquisition	'	191,302	'
Debt issuance costs written off due to debt extinguishment	$3,033	'	'

Consolidated_Statements_Of_Par

Consolidated Statements Of Partners' Capital (USD $)		Total	Common Units		Class B Units	Special Units		Accumulated Other Comprehensive Income (loss)	Noncontrolling interest of PVR
In Thousands
Beginning Balance at Dec. 31, 2010		$434,650	$213,646	[1]	'	'		$159	$220,845	[2]
Beginning Balance (Shares) at Dec. 31, 2010	[1]	'	38,293		'	'		'	'
Unit-based compensation (in shares)	[1]	'	25		'	'		'	'
Unit-based compensation		7,750	7,750	[1]	'	'		'	'
Costs associated with merger		-11,241	-11,241	[1]	'	'		'	'
Units issued to acquire non-controlling interests (in shares)	[1]	'	32,665		'	'		'	'
Units issued to acquire non-controlling interests		'	204,537	[1]	'	'		250	-204,787	[2]
Issuance of units (in shares)	[1]	'	8,050		'	'		'	'
Issuance of units		189,164	189,164	[1]	'	'		'	'
Distributions paid		-135,296	-119,902	[1]	'	'		'	-15,394	[2]
Net income (loss)		96,343	97,007	[1]	'	'		'	-664	[2]
Other comprehensive income (loss)		334	'		'	'		334	'
Ending Balance at Dec. 31, 2011		581,704	580,961	[1]	'	'		743	'
Ending Balance (Shares) at Dec. 31, 2011	[1]	'	79,033		'	'		'	'
Unit-based compensation (in shares)	[1]	'	117		'	'		'	'
Unit-based compensation		3,694	3,694	[1]	'	'		'	'
Issuance of units (in shares)		'	16,484	[1]	21,379	10,346	[3]	'	'
Issuance of units		934,650	343,398	[1]	399,950	191,302	[3]	'	'
Distributions paid		-176,256	-176,256	[1]	'	'		'	'
Distributions paid, in shares		'	'		927	'		'	'
Other		-8	-8	[1]	'	'		'	'
Net income (loss)		-70,622	-80,403	[1]	6,603	3,178	[3]	'	'
Other comprehensive income (loss)		-743	'		'	'		-743	'
Ending Balance at Dec. 31, 2012		1,272,419	671,386	[1]	406,553	194,480	[3]	'	'
Ending Balance (Shares) at Dec. 31, 2012		'	95,633	[1]	22,306	10,346	[3]	'	'
Unit-based compensation (in shares)	[1]	'	110		'	'		'	'
Unit-based compensation		3,142	3,142	[1]	'	'		'	'
Issuance of units (in shares)	[1]	'	6,100		'	'		'	'
Issuance of units		138,044	138,044	[1]	'	'		'	'
Distributions paid		-214,442	-214,442	[1]	'	'		'	'
Distributions paid, in shares		'	'		2,000	'		'	'
Other		-621	-606	[1]	-15	'		'	'
Net income (loss)		12,994	8,477	[1]	2,354	2,163	[3]	'	'
Conversion of Special Units (in shares)		'	10,346	[1]	'	-10,346	[3]	'	'
Conversion of Special Units		'	196,643	[1]	'	-196,643	[3]	'	'
Ending Balance at Dec. 31, 2013		$1,211,536	$802,644	[1]	$408,892	'		'	'
Ending Balance (Shares) at Dec. 31, 2013		'	112,189	[1]	24,306	'		'	'
[1]	The outstanding common units have been adjusted to reflect the effect of the PVR-PVG Merger; see Note 1, Organization and Basis of Presentation. PVG unitholders received consideration of 0.98 of a PVR common unit for each PVG common unit.
[2]	Effective with the PVR-PVG Merger, see Note 1, Organization and Basis of Presentation, noncontrolling interests no longer exist and have become part of common units.
[3]	On November 7, 2013, the Special Units automatically converted into common units.

Consolidated_Statements_Of_Par1

Consolidated Statements Of Partners' Capital (Parenthetical) (Penn Virginia GP Holdings, L.P., Noncontrolling interest of PVR)	Dec. 31, 2013
Penn Virginia GP Holdings, L.P. | Noncontrolling interest of PVR	'
Received consideration, common unit, ratio	0.98	[1]
[1]	Effective with the PVR-PVG Merger, see Note 1, Organization and Basis of Presentation, noncontrolling interests no longer exist and have become part of common units.

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2013
Organization and Basis of Presentation	'
	1. Organization and Basis of Presentation
	PVR Partners, L.P. is a publicly traded Delaware master limited partnership, the common units representing limited partner interests which are listed on the New York Stock Exchange (“NYSE”) under ticker symbol “PVR.” As used in these Notes to Consolidated Financial Statements, the “Partnership,” “PVR,” “we,” “us” or “our” mean PVR Partners, L.P. and, where the context requires, includes our subsidiaries.
	We are principally engaged in the gathering and processing of natural gas and the management of coal and natural resource properties in the United States. We currently conduct operations in three business segments: (i) Eastern Midstream, (ii) Midcontinent Midstream and (iii) Coal and Natural Resource Management.
	•	Eastern Midstream — Our Eastern Midstream segment is engaged in providing natural gas gathering, transportation and other related services in Pennsylvania, Ohio and West Virginia. In addition, we own membership interests in a joint venture that transports fresh water to natural gas producers.
	•	Midcontinent Midstream — Our Midcontinent Midstream segment is engaged in providing natural gas gathering, processing and other related services. These processing and gathering systems are located primarily in Oklahoma and Texas.
	•	Coal and Natural Resource Management — Our Coal and Natural Resource Management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties.
	Merger Agreement with Regency Energy Partners L.P. On October 9, 2013, we entered into an Agreement and Plan of Merger with Regency Energy Partners LP (or “Regency”), RVP LLC, a Delaware limited liability company and Regency’s wholly owned subsidiary, and Regency’s general partner. Pursuant to the Agreement and Plan of Merger, as amended by Amendment No. 1 thereto dated as of November 7, 2013 (or the “Regency Merger Agreement”), we will merge with and into Regency (or the “Regency Merger”), and Regency will continue its existence under Delaware law as the surviving entity in the Regency Merger. Regency has filed with the Securities Exchange Commission (“SEC”) a registration statement on Form S-4 (or the “Form S-4”) relating to the merger.
	The Regency Merger Agreement provides that, at the effective time of the merger, each of our common units and each of our class B units issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time will be converted into the right to receive the merger consideration, consisting of (i) 1.020 of Regency common units and (ii) an amount of cash equal to the difference between (x) our annualized distribution less (y) Regency’s adjusted annualized distribution. Our annualized distribution is the product of four and the per unit amount of the quarterly cash distribution most recently declared by us prior to the closing of the Regency Merger. Regency’s adjusted annualized distribution is the product of four and the per unit amount of quarterly cash distribution most recently declared by Regency prior to the closing of the Regency Merger, multiplied by the exchange ratio of 1.020.
	The completion of the Regency Merger is subject to the satisfaction or waiver of certain customary closing conditions, including, among other things: (i) approval of the Regency Merger Agreement by our unitholders, (ii) approval for listing of Regency common units issuable as part of the merger consideration on the New York Stock Exchange, (iii) there being no law or injunction prohibiting the consummation of the Regency Merger, (iv) the effectiveness of the Form S-4, (v) subject to specified materiality standards, the accuracy of the representations and warranties of each party, (vi) compliance by each party in all material respects with its covenants and (vii) the receipt of certain legal opinions by us and Regency.
	If the Regency Merger Agreement is not adopted by PVR unitholders or if the Regency Merger is not completed for any other reason, PVR unitholders will not receive any form of consideration for their PVR units in connection with the merger. Instead, PVR will remain an independent publicly traded limited partnership and its common units will continue to be listed and traded on the NYSE. If the Regency Merger Agreement is terminated under specified circumstances, including if unitholder approval is not obtained, PVR will be required to pay all of the reasonably documented out-of-pocket expenses incurred by Regency and its affiliates in connection with the Regency Merger Agreement and the transactions contemplated thereby, up to a maximum amount of $20.0 million. In addition, if the Regency Merger Agreement is terminated in specified circumstances, including due to an adverse recommendation change having occurred, PVR will be required to pay Regency a termination fee of $134.5 million, less any expenses previously paid by PVR to Regency. Following payment of the termination fee, PVR will not be obligated to pay any additional expenses incurred by Regency or its affiliates.
	Costs incurred during 2013 related to the Regency Merger Agreement were $8.1 million, and include finder’s fees, advisory, legal, accounting, valuation and other professional and consulting fees.
	PVR-PVG Merger. In 2011, we consummated a transaction pursuant to a plan and agreement of merger (the “PVR Merger Agreement”) with our general partner Penn Virginia Resource GP, LLC (“PVR GP”), Penn Virginia GP Holdings, L.P. (“PVG”), PVG GP LLC (“PVG GP”) and PVR Radnor, LLC (“Merger Sub”), our wholly-owned subsidiary. Pursuant to the PVR Merger Agreement our general partner, PVG and PVG GP, were merged into Merger Sub. Subsequently, Merger Sub was merged into PVR GP, with PVR GP being the surviving entity as a subsidiary of PVR (the “PVR-PVG Merger”). In the transaction, PVG unitholders received consideration of 0.98 PVR common units for each PVG common unit, representing aggregate consideration of approximately 38.3 million PVR common units. The incentive distribution rights held by our general partner were extinguished, the 2% general partner interest in PVR held by PVR’s general partner was converted to a noneconomic management interest and approximately 19.6 million PVR common units owned by PVG were cancelled. The merger closed on March 10, 2011. After the effective date of the merger and related transactions, the separate existence of each of PVG, and PVG GP and Merger Sub ceased, and PVR GP survives as a wholly-owned subsidiary of PVR.
	Historically, PVG’s ownership of PVR’s general partner gave it control of PVR. During the periods that PVG controlled PVR (prior to March 10, 2011), PVG had no substantial assets or liabilities other than those of PVR. PVG’s consolidated financial statements included noncontrolling owners’ interest of consolidated subsidiaries, which reflected the proportion of PVR common units owned by PVR’s unitholders other than PVG. These amounts are reflected in the historical financial balances presented up to consummation of the PVR-PVG Merger.
	These financial statements were originally the financial statements of PVG prior to the effective date of the PVR-PVG Merger. The PVR-PVG Merger was accounted for in accordance with consolidation accounting standards for changes in a parent’s ownership interest in a subsidiary. Under these accounting standards, the exchange of PVG common units for PVR common units was accounted for as a PVG equity issuance and PVG was the surviving entity for accounting purposes. Although PVG was the surviving entity for accounting purposes, PVR is the surviving entity for legal and reporting purposes. The PVR-PVG Merger was accounted for as an equity transaction. Therefore, the changes in ownership interests as a result of the PVR-PVG Merger did not result in gain or loss recognition.
	Effective August 6, 2012 Penn Virginia Resource Partners, L.P. changed its name from Penn Virginia Resource Partners, L.P. to PVR Partners, L.P.
	Our Consolidated Financial Statements include the accounts of PVR and all of our wholly owned subsidiaries. Investments in non-controlled entities over which we exercise significant influence are accounted for using the equity method. Intercompany balances and transactions have been eliminated in consolidation. Our Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Consolidated Financial Statements have been included.
	Management has evaluated all activities of PVR through the date upon which our Consolidated Financial Statements were issued and concluded that other than the pending outcome of the Regency Merger, no subsequent events have occurred that would require recognition in the Consolidated Financial Statements or additional disclosure in these Notes.
	All dollar and unit amounts presented in the tables to these Notes are in thousands unless otherwise indicated.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
	2. Summary of Significant Accounting Policies
	Use of Estimates
	Preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Cash and Cash Equivalents
	We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
	Property, Plant and Equipment
	Property, plant and equipment consist of our ownership in coal fee mineral interests, our royalty interest in oil and natural gas wells, forestlands, processing facilities, gathering systems, compressor stations and related equipment. Property, plant and equipment are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which increase the productive lives of existing assets. Maintenance and repair costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property, plant and equipment using the straight-line method except for well connects, which generally are depreciated using the accelerated method. The estimated useful life of each asset is as follows:
		Useful Life
	Gathering systems	7 – 20 years
	Compressor stations	3 – 15 years
	Processing plants	15 years
	Other property and equipment	3 – 20 years
	Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, we carry out core-hole drilling activities on our coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. We deplete timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. We determine depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. When we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheet. Upon sale, we record the difference between the net book value, net of any assumed asset retirement obligation (“ARO”), and proceeds from disposition as a gain or loss.
	Intangible assets are primarily associated with assumed contracts, customer relationships and other. These intangible assets are amortized on a straight-line basis over periods of up to 26 years, the period in which benefits are derived from the contracts, customer relationships and other, and are reviewed for impairment along with their associated property, plant and equipment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
	Asset Retirement Obligations
	We recognize the fair value of a liability for an ARO in the period in which it is incurred. The determination of fair value is based upon regional market and specific facility type information. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The long-lived assets for which our AROs are recorded include compressor stations, gathering systems and coal processing plants. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed rate, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion and the depreciation are included in depreciation, depletion and amortization (“DD&A”) expense on our consolidated statements of operations.
	In connection with our natural gas midstream assets, we are obligated under federal regulations to perform limited procedures around the abandonment of pipelines. In some cases, we are unable to reasonably determine the fair value of such ARO because the settlement dates, or ranges thereof, are indeterminable. An ARO will be recorded in the period in which we can reasonably determine the settlement dates.
	Impairment of Long-Lived Assets
	The Eastern Midstream, Midcontinent Midstream and Coal and Natural Resource Management segments have completed a number of acquisitions in recent years. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, intangibles and the resulting amount of goodwill, if any. Changes in operations, decreases in commodity prices, changes in the business environment or deteriorations of market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows.
	We review long-lived assets to be held and used, including definite-lived intangible assets, whenever triggering events or circumstances indicate that the carrying value of those assets may not be recoverable. Triggering events include, but are not limited to, changes in operations; decreases in commodity prices, the amounts of which may vary depending on the asset involved; changes in the business environment; or deteriorations of market conditions. When a triggering event occurs, we estimate the future cash flows of the related assets. Our estimates of future cash flows depend on our projections of revenues and expenses for future periods. These projections are driven by our estimates or evaluation of growth rates, changes in market conditions, and changes in prices received or paid, among other factors. When the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows, we recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the present value of future net cash flows from the asset, discounted using a rate commensurate with the risk and remaining life of the asset.
	Impairment of Goodwill
	Goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually. We have the option to make a qualitative assessment of whether it is more likely than not a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. If we conclude it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, we do not need to perform the two-step impairment test. If the two-step impairment test is required, the first step of the impairment test is used to identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value of a reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is not required. If the book value of a reporting unit exceeds its fair value, the second step of impairment test compares the implied fair value of the reporting unit’s goodwill with the book value of that goodwill. If the book value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. The annual impairment testing is performed in the fourth quarter. We quantitatively tested the Eastern Midstream segment, our only reporting unit with goodwill, and determined that no impairment charge was necessary.
	Equity Investments
	We use the equity method of accounting to account for our membership interest in various joint ventures, recording the initial investment at cost. Subsequently, the carrying amounts of the investments are increased to reflect our share of income of the investees and capital contributions, and are reduced to reflect our share of losses of the investees or distributions received from the investees as the joint ventures report them. Our share of earnings or losses from these joint ventures is included in other revenues on the consolidated statements of operations. Other revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets. We record this amortization over the life of the contracts acquired, 14 years. In the event of an impairment or a gain on sale of a joint venture, the impairment charge or gain is classified in the same line of the income statement as the equity earnings or loss are recorded, “Other revenues” in the consolidated statement of operations.
	Debt Issuance Costs
	Debt issuance costs relating to long-term debt have been capitalized and are being amortized and recorded as interest expense over the term of the related debt instrument.
	Long-Term Prepaid Minimums
	We lease a portion of our reserves from third parties that require monthly or annual minimum rental payments. The prepaid minimums are recoupable from future production and are deferred and charged to coal royalties expense as the coal is subsequently produced. We evaluate the recoverability of the prepaid minimums on a periodic basis; consequently, any prepaid minimums that cannot be recouped are charged to coal royalties expense.
	Environmental Liabilities
	Other liabilities include accruals for environmental liabilities that we either assumed in connection with certain acquisitions or recorded in operating expenses when it became probable that a liability had been incurred and the amount of that liability could be reasonably estimated.
	Concentration of Credit Risk
	In 2013, 51% of our total consolidated revenues and 51% of our December 31, 2013 consolidated accounts receivable resulted from seven of our natural gas midstream customers. Within the Eastern Midstream segment for 2013, 55% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from three customers. Within the Midcontinent Midstream segment for 2013, 57% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from four customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these natural gas midstream customers. These customer concentrations increase our exposure to credit risk on our receivables, since the financial insolvency of these customers could have a significant impact on our results of operations. As of December 31, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment.
	Revenues
	Natural Gas Midstream Revenues. We recognize revenues from the sale of natural gas liquids (“NGLs”) and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and trunkline revenues based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.
	Coal Royalties Revenues and Deferred Income. We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most of our lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.
	Derivative Instruments
	From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of collars and swaps. All derivative financial instruments are recognized in our consolidated financial statements at fair value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by the board of directors of our general partner. We do not use hedge accounting for commodity derivatives; thus, the open positions are recorded at fair value with the change in value recorded to earnings.
	We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The lack of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark- to-market gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment.
	At December 31, 2013 and 2012, we had no open derivative contracts to hedge commodity prices. Therefore, no derivative assets or liabilities were reported as of December 31, 2013 and 2012.
	Historically, we have entered into interest rate swap agreements (the “Interest Rate Swaps”) to mitigate our exposure to debt interest expense. During the year ended December 31, 2012, we reclassified a total net gain of $0.7 million from accumulated other comprehensive income (“AOCI”) to earnings related the Interest Rate Swaps. At December 31, 2012, no gain or loss remained in AOCI to be recognized in the Derivatives line as the Interest Rate Swaps settled. At December 31, 2013 and 2012, we had no open derivative contracts to hedge interest rates.
	Income Taxes
	As a partnership, we are not subject to federal income tax. The taxable income and losses of the Partnership are includable in the federal and state income tax returns of our partners. Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under our partnership agreement.
	Net Income (Loss) per Limited Partner Unit
	We are required to allocate earnings or losses for a reporting period to our limited partners and the participating securities using the two-class method to compute earnings per unit. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Participating securities may participate in undistributed earnings with common units, whether that participation is conditioned upon the occurrence of a specified event or not. The form of such participation does not have to be a dividend, that is, any form of participation in undistributed earnings would constitute participation by that security, regardless of whether the payment to the security holder was referred to as a dividend. Under this method, our net income (loss) for a reporting period is reduced (or increased) by the amount that has been or will be distributed to our participating security holders. Unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of net income (loss) allocable to limited partners pursuant to the two-class method of computing earnings per unit. Class B Units and Special Units participate in the allocation of income, gains and losses with the common units; therefore, these forms of equity are participating securities. Thus, our securities consist of publicly traded common units held by limited partners and participating securities as a result of unit-based compensation and issuance of other classes of equity.
	During 2013, 2012 and 2011, service-based and performance-based phantom units were granted to employees. We have determined that our unvested service-based phantom unit awards generally contain non-forfeitable rights to distributions and, therefore, are participating securities. The performance based phantom units contain forfeitable rights to distributions and, therefore, are not participating securities.
	Basic and diluted net income (loss) per limited partner unit is computed by dividing net income (loss) allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income (loss) per limited partner unit is computed by dividing net income (loss) allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units, Class B Units and Special Units.
	Unit-Based Compensation
	Our long-term incentive plan permits the grant of awards to directors and employees of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our long-term incentive plan is administered by the compensation and benefits committee of our general partner’s board of directors. We recognize compensation expense over the vesting period of the awards.
	Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 16, “Unit-Based Payments,” for a more detailed description of our long-term incentive plan.
	New Accounting Standards
	During the first quarter of 2013, we adopted Accounting Standard Update (“ASU”) 2013-02, Comprehensive Income (Topic 220). The new ASU requires us to disclose in a single location (either on the face of the statement of operations or in the notes) the effects of reclassifications out of accumulated other comprehensive income (“AOCI”). The new disclosure requirements were effective for the first quarter 2013 and apply prospectively. All of our AOCI amounts were reclassified in 2012 and no amounts remained as of December 31, 2012. Therefore, adoption of this ASU does not have an effect on our financials.

Impairments

Impairments	12 Months Ended
	Dec. 31, 2013
Impairments	'
	3. Impairments
	During the first quarter of 2012, we recognized a $124.8 million impairment charge related to our tangible and intangible natural gas gathering assets in the Midcontinent Midstream segment located in the southern portion of the Fort Worth Basin of north Texas (the “North Texas Gathering System”). The gathering lines and customer contracts were written down to their fair value, which was determined using the income approach and discounting the estimated cash flows of the assets. This is a nonrecurring fair value measurement, see Note 6. “Fair Value Measurements,” that was triggered by continuing market declines of natural gas prices and lack of drilling in the area. The North Texas Gathering System represented a de minimis amount of our consolidated total revenues. The impairment is reported in the statement of operations in the “Impairment” line item.
	See Note 9, “Equity Investments” for a discussion of the impairment of our equity investment in Thunder Creek.

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2013
Dispositions	'
	4. Dispositions
	On August 19, 2013, we sold our 25% membership interest in Thunder Creek Gas Services LLC, a joint venture that gathers and transports coalbed methane gas in Wyoming’s Powder River Basin. This Midcontinent Midstream investment was accounted for using the equity method of accounting, and had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded in other revenues on the Consolidated Statement of Operations.
	As of December 31, 2012, we had $11.5 million of assets held for sale. This amount was separately stated in our Consolidated Balance Sheet in current assets. The assets represented a Midcontinent Midstream plant that we sold in the first quarter of 2013 for $12.0 million. A gain of $0.5 million was recorded in other revenues on the Consolidated Statement of Operations.
	On July 3, 2012, we completed the sale of our Crossroads natural gas gathering system and processing plant (the “Crossroads Sale”) for net proceeds of $62.3 million. The Crossroads system, located in the southeastern portion of Harrison County in east Texas, includes approximately eight miles of gas gathering pipeline, an 80 MMcfd cryogenic processing plant, approximately 20 miles of NGL pipeline, and a 50% ownership in an approximately 11-mile gas pipeline. A gain on sale of assets of $31.3 million was recognized in other revenues on the face of the statement of operations.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Acquisitions	'
	5. Acquisitions
	In the following paragraphs, all references to coal, crude oil and natural gas reserves and acreage acquired are unaudited. The factors we used to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risked-adjusted basis, geographic location, and condition of assets.
	Business Combinations
	Chief Acquisition
	On May 17, 2012, we completed our purchase of the membership interests of Chief Gathering LLC (“Chief Gathering”) from Chief E&D Holdings LP, for a purchase price of approximately $1.0 billion (“Chief Acquisition”), payable in a combination of $849.3 million in cash and fair value of $191.3 million in a new class of limited partner interests in us (“Special Units”). The Special Units were substantially similar to our common units, except that we did not pay or accrue any distributions on them until they automatically converted to common units, on a one-for-one basis, on the first business day after the record date for distributions with respect to the quarter ended September 30, 2013. The Special Units converted to common units on November 7, 2013 are eligible for distributions declared on January 28, 2014, with respect to the fourth quarter of 2013.
	Chief Gathering owned and operated six natural gas gathering systems serving over 300,000 dedicated acres in the Marcellus Shale, located in the north central Pennsylvania counties of Lycoming, Bradford, Susquehanna, Sullivan, Wyoming and Greene and in Preston County, West Virginia. This transaction resulted in a major expansion of our pipeline systems in our Eastern Midstream segment.
	We financed the cash portion of the purchase price for the Chief Acquisition through a combination of equity and debt. In May 2012, we received (i) $400 million in cash related to the sale of Class B Units to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P., representing a new class of limited partner interests in us, and (ii) $180 million in cash, related to the sale of common units to institutional investors in a private placement. We used the proceeds from the sale of the Class B Units and the common units to fund a portion of the cash purchase price for the Chief Acquisition. The remainder of the cash purchase price was funded by a portion of the $600 million of senior notes issued in a private placement in May 2012. See Note 13, “PVR Unit Offerings,” for a description of the conversion rights and distribution rights applicable to the Class B Units.
	The Chief Acquisition was accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price was allocated to the current assets and liabilities and the tangible, intangible and goodwill assets acquired. Fair values were developed using recognized business valuation techniques. Below is the detailed allocation of the purchase price allocation:
	Cash consideration paid for Chief	$	849,262
	Special units issued as consideration to Chief		191,302
	Total purchase price	$	1,040,564
	Accounts receivable	$	4,412
	Property, plant and equipment		376,953
	Intangible assets		622,000
	Goodwill		70,283
	Other long-term assets		415
	Accounts payable		(33,499	)
	Total purchase price	$	1,040,564
	The intangible assets identified in the acquisition represent customer contracts and relationships, all of which are fully amortizable. The amortization periods for these intangibles range from 13 to 26 years.
	The purchase price allocation includes approximately $70.3 million of goodwill. The significant factors that contributed to the recognition of goodwill included the positioning of PVR as the leading independent midstream service provider in the northeastern area of the Marcellus Shale, as the assets acquired from Chief Gathering complement our existing assets in the region. Goodwill recorded in connection with a business combination is not amortized, but is tested for impairment at least annually. Accordingly, the pro forma financial information below does not include amortization of goodwill recorded in the acquisition.
	The following pro forma financial information reflects the consolidated results of our operations as if the Chief Acquisition and related financings had occurred on January 1, 2011. The pro forma information includes adjustments primarily for revenues, operating expenses, general and administrative expenses, depreciation of the acquired property and equipment, amortization of intangibles, interest expense for acquisition debt and the change in weighted average common units resulting from the issuance of common units. The pro forma financial information is not necessarily indicative of the results of operations had these transactions been effected on the assumed date (in thousands, except per unit data):
		Years Ended December 31,
		2012			2011
	Revenues	$	1,021,297		$	1,182,381
	Net income (loss) attributable to PVR	$	(82,696	)	$	19,060
	Net income (loss) per limited partner unit, basic and diluted	$	(1.84	)	$	(0.87	)
	The acquisition costs related to the Chief Acquisition were $14.0 million and are reported on the merger and acquisition costs line in the Consolidated Statement of Operations.
	During 2013, we made other acquisitions that individually and in the aggregate are not material for disclosure purposes. The aggregate cost of all other acquisitions was $2.4 million.

Fair_Value_Measurement

Fair Value Measurement	12 Months Ended
	Dec. 31, 2013
Fair Value Measurement	'
	6. Fair Value Measurement
	We present fair value measurements and disclosures applicable to both our financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. Our financial instruments that are subject to fair value disclosures consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments and long-term debt. At December 31, 2013, the carrying values of all these financial instruments, except the long-term debt with fixed interest rates, approximated their fair value. The fair value of floating-rate debt approximates the carrying amount because the interest rates paid are based on short-term maturities. The fair value of our fixed-rate debt is estimated based on the published market prices for the same or similar issues. As of December 31, 2013, the fair value of our fixed-rate debt was $1.2 billion.
	Authoritative accounting literature requires fair value measurements to be classified and disclosed in one of the following three categories:
		•		Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.
		•		Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
		•		Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).
	Nonrecurring Fair Value Measurements
	We completed the Chief Acquisition on May 17, 2012. In connection with our accounting for this acquisition, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions discussed below. During 2013, we made other acquisitions that also required us to estimate the values of assets acquired and liabilities assumed that individually and in the aggregate are not material. The aggregate cost of all other acquisitions was a net $2.4 million. See Note 5, “Acquisitions,” for a description of these acquisitions.
	The following table summarizes the fair value estimates for financial and nonfinancial assets and liabilities measured at fair value on a nonrecurring basis by category as of the acquisition date:
						Fair Value Measurements during 2012, Using
	Description		Fair Value			Quoted Prices in		Significant Other		Significant
			Measurements at			Active Markets for		Observable Inputs		Unobservable
			Acquisition Date			Identical Assets		(Level 2)		Inputs (Level 3)
						(Level 1)
	Chief property, plant and equipment		$	376,953		$	—	$	—	$	376,953
	Chief intangible assets			622,000			—		—		622,000
	Chief goodwill			70,283			—		—		70,283
	Chief other long-term assets			415			—		—		415
	Chief working capital			(29,087	)		—		—		(29,087	)
	Total		$	1,040,564		$	—	$	—	$	1,040,564
	In conjunction with the 2012 Chief Acquisition, there are three methods of estimating the value of assets that comprise a business: (i) the income approach, (ii) the cost approach and (iii) the market approach. Our allocation of value to assets is discussed below.
	Regarding the tangible assets, the cost approach was the primary method. Due to the fact that the assets were relatively new or had been recently constructed, the indirect method of the cost approach was viewed as the most accurate method for estimating the fair value of these tangible assets. Using the indirect method of the cost approach, the current reproduction cost of the tangible asset was estimated by indexing the historical capitalized cost basis in the fixed asset records based on the asset type and historical acquisition date of each asset. These costs generally include the base cost of the tangible asset and any additional cost considerations relating to placing the asset in service. Due to the fact that these tangible assets have been in use over varying periods of time, allowances were made for physical, functional and economic factors affecting utility and value as applicable.
	The intangible assets were valued using the income approach with the application of the discounted cash flow method. The principle behind this method was that the value of an intangible asset is equal to the present value of the incremental cash flows attributable only to the subject intangible asset after deducting contributory asset charges. These incremental cash flows are then discounted to their present value.
	As part of consideration of the Chief Acquisition, we issued a new class of PVR limited partner interests to Chief E&D Holdings LP (“Special Units”) with a fair value of $191.3 million. For the purpose of estimating the fair value of the Special Units, our unit price on the acquisition date was used and adjusted for the nine quarters where we neither pay nor accrue distributions on these units. The value was further adjusted to reflect the lack of marketability. Because elements of the fair value inputs are typically not observable, we have categorized the amounts as Level 3 inputs. The Special Units automatically converted into common units on November 7, 2013.
	In connection with our review of tangible and related intangible assets, if there is an indication of impairment and the estimated undiscounted future cash flows do not exceed the carrying value of the tangible and intangible assets, then these assets are written down to their fair value. During the first quarter of 2012, the North Texas Gathering System was reviewed for impairment and found to be impaired. The factors used to determine fair value for purposes of impairment testing include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective gas gathering assets. Because these significant fair value inputs are typically not observable, we have categorized the amounts as Level 3 inputs. The assets of the North Texas Gathering System were written down to their fair value of $5.7 million which included intangible assets of zero.
	During the fourth quarter of 2012 the Thunder Creek joint venture located in Wyoming’s Powder River basin, was reviewed for impairment. As a result of the analysis, which included a review of forecasted gathering volumes, local producers’ drilling activities, natural gas pricing and other market factors, an impairment was recorded. We recognized an $8.7 million impairment charge related to our 25% membership interest in the Thunder Creek joint venture. Because these significant fair value inputs are typically not observable, we have categorized the amounts as Level 3 inputs. The intangible assets related to this joint venture were written down to zero.
	Recurring Fair Value Measurements
	As of December 31, 2013 and 2012 we had no open derivative positions; therefore there are no recurring valuations as of these dates. We did however have commodity derivatives during these years. See Note 7, “Derivative Instruments,” for the effects of these instruments on our consolidated statements of operations.
	During periods with open derivative positions, we use the following methods and assumptions to estimate their fair values:
		•		Commodity derivative instruments: We utilized collars and swap derivative contracts to hedge against the variability in the fractionation, or frac, spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. Each is a level 2 input. We used the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 7, “Derivative Instruments.”
		•		Interest rate swaps: We historically entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. We used an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each is a level 2 input. See Note 7, “Derivative Instruments.”

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments	'
	7. Derivative Instruments
	Commodity Derivatives
	We have utilized costless collars and swap derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream gas purchased. We also utilized collar derivative contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedged against the variability in our frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements.
	With respect to a costless collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the Put (or floor) price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the Call (or ceiling) price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. With respect to a swap contract for the purchase of a commodity, the counterparty is required to make a payment to us if the settlement price for any settlement period is greater than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price is less than the swap price for such contract.
	At December 31, 2013 and 2012, no open positions remained on the balance sheet and no amounts remain in AOCI related to derivatives in the natural gas midstream segments.
	Interest Rate Swaps
	During 2012, we had open positions for Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. From January 2012 to December 2012, the notional amounts of the Interest Rate Swaps totaled $100.0 million with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). The Interest Rate Swaps were with three financial institution counterparties, with no counterparty having more than 50% of the open positions.
	As of December 31, 2013 and 2012, no open positions remained on the balance sheet and no gain or loss remained in AOCI regarding the Interest Rate Swaps. During the year ended December 31, 2012, we reclassified a total net gain of $0.7 million from AOCI to earnings related the Interest Rate Swaps.
	Financial Statement Impact of Derivatives
	The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses, on our consolidated statements of operations for the periods presented:
			Location of gain (loss)
			on derivatives recognized	Year Ended December 31,
			in income	2013			2012			2011
	Derivatives not designated as hedging instruments:
	Interest rate contracts		Derivatives	$	—		$	538		$	(851	)
	Commodity contracts		Derivatives		(1,070	)		1,753			(12,591	)
	Total decrease (increase) in net income resulting from derivatives			$	(1,070	)	$	2,291		$	(13,442	)
	Realized and unrealized derivative impact:
	Cash paid for commodity and interest rate contract settlements (1)		Derivatives	$	(1,070	)	$	(10,494	)	$	(25,688	)
	Unrealized derivative gains (2)				—			12,785			12,246
	Total decrease in net income resulting from derivatives			$	(1,070	)	$	2,291		$	(13,442	)
	-1	As of December 31, 2013 and included in the settlement amounts is $0.5 million related to settled positions that were paid in January 2014. As of December 31, 2012 and included in the settlement amounts is a net $0.2 million related to settled positions that were paid in January 2013.
	-2	This activity represents unrealized gains in the natural gas midstream revenue, cost of midstream gas purchased, and interest expense. All amounts are reported in the derivatives line on our consolidated statements of operations.
	As of December 31, 2013 and 2012, we had no open derivative positions noted as derivative assets or liabilities on the consolidated balance sheets. There were two settled but not paid commodity derivative positions in accounts payable amounting to $0.5 million as of December 31, 2013 and $0.2 million as of December 31, 2012. Therefore, there is no summary presented related to the fair values and location of derivative instruments on our consolidated balance sheets.
	See Note 6, “Fair Value Measurement of Financial Instruments” for a description of how the above financial instruments are valued.
	The effects of derivative gains (losses), cash settlements of our commodity derivatives and cash settlements of the Interest Rate Swaps are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities on our consolidated statements of cash flows. We no longer utilize hedge accounting treatment for commodity or interest rate swap derivatives. These items are recorded in the “Total derivative losses (gains)” and “Cash payments to settle derivatives” lines on the consolidated statements of cash flows.
	The above hedging activity represents economic hedges of cash flows. As of December 31, 2013, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of December 31, 2013, we did not own derivative instruments containing credit risk contingencies.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment	'
	8. Property, Plant and Equipment
	The following table summarizes our property, plant and equipment for the periods presented:
		As of December 31,
		2013			2012
	Gathering systems	$	1,298,570		$	984,986
	Compressor stations		361,872			283,189
	Processing plants		130,527			116,942
	Other property, plant and equipment		24,757			17,484
	Construction in progress		194,559			252,635
	Coal properties		636,933			634,555
	Timber		88,447			88,447
	Oil and gas royalties		39,981			39,981
	Coal services equipment		35,409			35,409
	Land		26,162			26,174
	Total property, plant and equipment		2,837,217			2,479,802
	Accumulated depreciation, depletion and amortization		(647,939	)		(490,456	)
	Net property, plant and equipment	$	2,189,278		$	1,989,346
	As of December 31, 2012, we had $11.5 million of assets held for sale. This amount is separately stated in our Consolidated Balance Sheet in current assets. The assets represent capitalized expenditures on a Midcontinent Midstream plant that we sold in the first quarter of 2013.

Equity_Investments

Equity Investments	12 Months Ended
	Dec. 31, 2013
Equity Investments	'
	9. Equity Investments
	We own a 51% membership interest in Aqua – PVR Water Services LLC (“Aqua – PVR”), a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. Even though there is a presumption of a controlling financial interest in this joint venture (ownership of 51%), our partner in the joint venture has substantive participating rights that preclude us from controlling the joint venture. Therefore, it is accounted for as an equity investment. For the years ended December 31, 2013 and 2012, our contributions to this Eastern Midstream segment joint venture were $15.3 million and $35.7 million. We also recognized related party transactions for management fees with Aqua-PVR as described in Note 15, “Related Party Transactions.” Appropriate eliminations have been made regarding earnings from the joint venture for consolidation purposes.
	We own a 50% interest in Coal Handling Solutions LLC, a joint venture formed to own and operate end-user coal handling facilities in our Coal and Natural Resource Management segment.
	For a portion of the year, we also owned a 25% membership interest in Thunder Creek Gas Services LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane gas in Wyoming’s Powder River Basin. On August 19, 2013, we sold our 25% membership interest in Thunder Creek. This Midcontinent Midstream investment had a carrying value of $44.3 million. The proceeds from the sale were $58.6 million, resulting in a gain of $14.3 million recorded on the same line item as earnings from joint ventures, other revenues, on the Consolidated Statement of Operations. The earnings, excluding any gain on sale or impairment charge, and distributions related to the time period prior to August 19, 2013 are included in the amounts noted below. Earnings for years ended December 31, 2013, 2012 and 2011 were $1.0 million, $1.1 million and $2.5 million related to Thunder Creek. Distributions for the same periods were $2.4 million, $1.9 million and $8.2 million from Thunder Creek. Related to this investment and during the fourth quarter of 2012, we recognized an $8.7 million impairment charge to our membership interest in the Thunder Creek joint venture. The equity investment intangible assets, related to the excess of carrying value over our portion of the net assets of Thunder Creek, were written down to zero. This impairment was triggered by continuing market declines of natural gas prices, lack of coalbed methane drilling in the area and other market factors. The impairment is reported in the Consolidated Statement of Operations for the year ended December 31, 2012 on the same line item as earnings from joint ventures are captured, other revenues.
	For a portion of 2012, we also owned a 50% membership interest in Crosspoint Pipeline LLC, a joint venture that gathers residue gas from our Crossroads Plant and transports it to market. As mentioned in Note 4, “Dispositions,” as part of the Crossroads sale we sold our 50% ownership in Crosspoint Pipeline LLC, an approximately 11-mile gas pipeline. The earnings and distributions related to the time period prior to July 3, 2012 are included in the amounts noted below. Earnings for years ended December 31, 2012 and 2011 were $0.3 million and $0.7 million related to Crosspoint. Distributions for the same periods were $0.5 million and $0.7 million from Crosspoint. The net equity investment amount sold as of July 3, 2012 was $6.2 million.
	We account for our equity investments under the equity method of accounting. As of December 31, 2013 and 2012, our equity investment totaled $60.8 million and $97.6 million, which exceeded our portion of the underlying equity in net assets by $2.6 million and $3.3 million. The difference is being amortized to equity earnings over the estimated life of the equity investment intangible assets at the time of the acquisition. The equity investment intangible assets relate to contracts acquired, and are being amortized over 14 years.
	In accordance with the equity method of accounting, we recognized equity earnings (loss) of $14.5 million in 2013, $(2.5) million in 2012 and $5.5 million in 2011, with a corresponding increase (decrease) in the investment. These amounts include the 2013 effects of the $14.3 million gain on sale of equity investment and the 2012 impairment of equity investment for $(8.7) million. The joint ventures generally pay quarterly distributions on their cash flow. We received distributions of $7.9 million in 2013, $8.8 million in 2012 and $14.0 million in 2011. Equity earnings related to our joint venture interests are recorded in other revenues on the Consolidated Statements of Operations. The equity investments for all joint ventures are included in the equity investments caption on the Consolidated Balance Sheets.
	Financial statements from our investees are not sufficiently timely for us to apply the equity method currently. Therefore, we record our share of earnings or losses of an investee from the most recent available financial statements, a one month lag. This lag in reporting is consistent from period to period.
	Summarized financial information of unconsolidated equity investments is as follows for the periods presented:
		November 30,		November 30,
		2013		2012
	Current assets	$	22,256	$	55,351
	Noncurrent assets	$	113,378	$	273,158
	Current liabilities	$	11,909	$	38,188
	Noncurrent liabilities	$	1,682	$	3,933
		Year Ended November 30,
		2013		2012
	Revenues	$	38,900	$	59,261
	Expenses	$	35,619	$	38,463
	Net income	$	3,281	$	20,798

Intangible_Assets_Net

Intangible Assets, Net	12 Months Ended
	Dec. 31, 2013
Intangible Assets, Net	'
	10. Intangible Assets, Net
	The following table summarizes our net intangible assets for the periods presented:
		As of December 31,
		2013			2012
	Contracts and customer relationships	$	657,500		$	657,500
	Other		4,552			4,552
	Total intangible assets		662,052			662,052
	Accumulated amortization		(71,972	)		(41,452	)
	Intangible assets, net	$	590,080		$	620,600
	As disclosed in Note 3, “Impairment,” we impaired the tangible and intangible assets of the North Texas Gathering System (“North Texas”) during 2012. The related $69.2 million of North Texas intangible assets, consisting of contracts and customer relationships, were considered impaired having a fair value of zero. The accumulated amortization of the intangibles was $14.6 million at the time of the impairment. The book value of the intangible as well as the related accumulated amortization were written off and represented $54.6 million of the total $124.8 million impairment charge, noted in the “Impairments” line item in the Consolidated Statement of Operations.
	As mentioned in Note 5, “Acquisitions,” we added $622.0 million of intangible assets related to contracts and customer relationships acquired in the Chief Acquisition during 2012.
	Contracts and customer relationships are amortized on both a straight-line basis and an accelerated basis, based on the period and timing of the benefit to us, over the expected useful lives of the individual contracts and relationships, up to 26 years. Total intangible amortization expense for the years ended December 31, 2013, 2012 and 2011 was approximately $30.5 million, $17.5 million and $6.3 million. The following table sets forth our estimated aggregate amortization expense for the next five years and thereafter:
	Year	Amortization Expense
	2014	$	30,367
	2015		30,254
	2016		30,148
	2017		30,071
	2018		29,970
	Thereafter		439,270
	Total	$	590,080

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
	11. Asset Retirement Obligations
	The following table reconciles the beginning and ending aggregate carrying amount of our asset retirement obligations for the years ended December 31, 2013 and 2012, which are recorded in other liabilities on our consolidated balance sheets:
		Year Ended December 31,
		2013		2012
	Balance at beginning of period	$	2,526	$	2,343
	Liabilities incurred		—		—
	Accretion expense		196		183
	Revision of estimate		—		—
	Balance at end of period	$	2,722	$	2,526
	The accretion expense is recorded in the depreciation, depletion and amortization expense line on the consolidated statements of operations.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-Term Debt	'
	12. Long-Term Debt
	The following table summarizes our long-term debt for the periods presented:
		As of December 31,
		2013		2012
	Revolver - variable rate of 3.2% at December 31, 2013 and 2012	$	562,500	$	590,000
	Senior notes - fixed rate of 8.25%, due April 15, 2018		300,000		300,000
	Senior notes - fixed rate of 8.375%, due June 1, 2020		472,600		600,000
	Senior notes - fixed rate of 6.5%, due May 15, 2021		400,000		—
	Total debt		1,735,100		1,490,000
	Less: Current maturities		—		—
	Total long-term debt	$	1,735,100	$	1,490,000
	We capitalized interest costs amounting to $12.8 million and $14.1 million in the years ended December 31, 2013 and 2012 related to the construction of natural gas gathering systems and processing plants.
	Revolver
	On February 21, 2013, we entered into the third amendment to the amended and restated credit agreement modifying the Revolver’s Maximum Leverage Ratio covenant to allow us to maintain a ratio of Consolidated Total Indebtedness (as defined in the Revolver amendment), calculated as of the end of each fiscal quarter for the four quarters then ended, of not more than (i) 6.50 to 1.0 commencing with fiscal period ended June 30, 2012 through the fiscal period ended December 31, 2012; (ii) 5.75 to 1.0 commencing with fiscal period ended March 31, 2013 through the fiscal period ended June 30, 2013; (iii) 5.50 to 1.0 commencing with the fiscal period ended September 30, 2013 through the fiscal period ended December 31, 2013; and (iv) 5.25 to 1.0 commencing with the fiscal period ending March 31, 2014, and for each fiscal period thereafter. The maturity date of the Revolver is April 19, 2016.
	Our Revolver allows for adjustments to Consolidated EBITDA for material capital projects which exceed $10.0 million. The adjustments to Consolidated EBITDA have certain limitations and are approved by PNC Bank, as administrative agent to the Revolver.
	As of December 31, 2013, net of outstanding indebtedness of $562.5 million and letters of credit of $10.7 million, we had remaining borrowing capacity of $426.8 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the year ended December 31, 2013 was approximately 3.3%. We do not have a public rating for the Revolver. As of December 31, 2013, we were in compliance with all covenants under the Revolver, and our Maximum Leverage Ratio was 5.27 to 1.0.
	6.5% Senior Notes
	In May 2013, we sold $400.0 million of senior notes due on May 15, 2021 in a private placement with an annual interest rate of 6.5% (“6.5% Senior Notes”), which is payable semi-annually in arrears on May 15 and November 15 of each year beginning on November 15, 2013. The 6.5% Senior Notes were sold at par, equating to an effective yield to maturity of approximately 6.5%. The net proceeds from the sale of the 6.5% Senior Notes of approximately $391.0 million, after deducting fees and expenses of approximately $9.0 million, were used to repay borrowings under the Revolver. They are fully and unconditionally guaranteed by our existing and future domestic subsidiaries, subject to certain exceptions. The 6.5% Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness.
	8.375% Senior Notes
	In May 2012, we completed the issuance of $600.0 million of senior notes in a private placement. These notes were sold at par, equating to an effective yield to maturity of approximately 8.375%, due June 1, 2020 (“8.375% Senior Notes”). Interest is payable semi-annually in arrears on June 1 and December 1 of each year. The 8.375% Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness. They are fully and unconditionally guaranteed by our existing and future domestic restricted subsidiaries, subject to certain exceptions. Approximately $250 million of the proceeds from the Senior Notes offering was used in connection with the financing of the Chief Acquisition, and the remainder was used to pay down a portion of the outstanding borrowings under our Revolver.
	On December 1, 2013, using a portion of the proceeds received from the Equity Issuance, we redeemed $127.4 million of our 8.375% Senior Notes. Pursuant to the terms of the indenture, we paid the note holders 108.375% of the principal amount plus accrued and unpaid interest up to the redemption date. As a result of this redemption, we incurred a charge of $13.7 million related to the call premium and the write-off of unamortized debt issuance costs. The charge was recorded in loss on extinguishment of debt in continuing operations of the Consolidated Statement of Operations. The remaining balance of the 8.375% Senior Notes is $472.6 million at December 31, 2013.
	8.25% Senior Notes
	In April 2010, we sold $300.0 million of senior notes due on April 15, 2018 with an annual interest rate of 8.25% (“Senior Notes”), which is payable semi-annually in arrears on April 15 and October 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. The net proceeds from the sale of the Senior Notes of approximately $292.6 million, after deducting fees and expenses of approximately $7.4 million, were used to repay borrowings under the Revolver. The Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our existing and future domestic restricted subsidiaries which are also guarantors under the Revolver, subject to certain exceptions.
	The 8.25% Senior Notes are unsecured obligations of PVR Partners, L.P. and Penn Virginia Resource Finance Corporation (“Finance Corp”). The 8.375% Senior Notes and the 6.5% Senior Notes are unsecured obligations of PVR Partners, L.P. and Penn Virginia Resource Finance Corporation II (“Finance Corp II”). Finance Corp and Finance Corp II are finance subsidiaries 100% owned by PVR Partners, L.P. Finance Corp, Finance Corp II, and PVR Partners, L.P. do not have any material independent assets or operations. The 8.25% Senior Notes, 8.375% Senior Notes and 6.5% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our other existing and future domestic restricted subsidiaries, subject to certain exceptions. The guarantees are joint and several and all subsidiary guarantors are 100% owned by PVR Partners, L.P. There are no significant restrictions on the ability of PVR, Finance Corp or Finance Corp II or any guarantor of the Senior Notes to obtain funds from their subsidiaries by dividend or loan.
	Debt Maturities
	The following table sets forth the aggregate maturities of the principal amounts of long-term debt for the next five years and thereafter:
	Year	Aggregate
		Maturities
		Principal
		Amounts
	2014	$	—
	2015		—
	2016		562,500
	2017		—
	2018		300,000
	Thereafter		872,600
	Total debt, including current maturities	$	1,735,100

PVR_Unit_Offerings

PVR Unit Offerings	12 Months Ended
	Dec. 31, 2013
PVR Unit Offerings	'
	13. PVR Unit Offerings
	Common Units
	In September and October of 2013, we issued a total of 6.1 million common units, including the over allotment exercise by the underwriter, representing limited partner interest in PVR in a registered public offering. Total net proceeds of approximately $138.0 million, after deducting estimated fees and expenses and underwriting discounts and commissions totaling approximately $2.2 million, were initially used to repay a portion of the Revolver.
	In connection with the 2012 Chief Acquisition, we sold 9.0 million common units to institutional investors in a private placement in the amount of $177.7 million, net of offering costs. In November 2012, PVR issued 7.5 million common units representing limited partner interests in PVR in a registered public offering. Total net proceeds of approximately $165.7 million were used to repay a portion of the Revolver.
	During November and December of 2011, we issued a total of 8.05 million common units, including the over allotment exercise by the underwriters, representing limited partner interests in PVR in a registered public offering. Total net proceeds of $189.2 million were used to repay a portion of the Revolver.
	At The Market (“ATM”) Equity Program
	An ATM program is an alternative way of raising capital by issuing equity through existing markets over a period of time. The flexibility of timing the issuance of units helps us to match demand for capital with the supply by controlling the number of units issued. Additionally, it reduces the volatility of unit price by avoiding issuance of a large number of common units at one time. In August 2013 we issued our prospectus supplement relating to the issuance and sale from time to time of common units representing limited partner interests in PVR, or common units, having an aggregate offering price of up to $150.0 million through one or more sales agents. These sales, if any, will be made pursuant to the terms of the ATM equity offering sales agreement between us and the sales agents. The compensation of sales agents for the sales of common units shall not exceed 2.0% of the gross sales price per common unit. The net proceeds from any sales under this ATM program will be used for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of December 31, 2013, no sales have been made under the ATM program.
	Special Units
	In connection with the closing of the Chief Acquisition, on May 17, 2012, we issued 10,346,257 Special Units (the “Special Units”) to Chief E&D Holdings LP. The Special Units were a new class of PVR limited partner interests with a fair value of $191.3 million and were substantially similar to our common units, except that the Special Units neither paid nor accrued distributions for six consecutive quarters commencing after the closing of the Chief Acquisition. The Special Units automatically converted into common units on a one-for-one basis on the first business day after the record date for distributions with respect to the quarter ended September 30, 2013, which was November 7, 2013.
	Class B Units
	In connection with the closing of the Chief Acquisition, on May 17, 2012, we issued 21,378,942 Class B Units (the “Class B Units”). The Class B Units are a new class of PVR limited partner interests issued to Riverstone V PVR Holdings, L.P. and Riverstone Global Energy and Power Fund V (FT), L.P. for $400.0 million. The Class B Units will share equally with our common units with respect to the payment of distributions but, until they convert into common units, such distribution (the “Class B Distribution Amount”) will be paid in additional Class B Units unless we elect to pay the distributions on the Class B Units in cash (the “Class B Unit Distribution”).
	The number of additional Class B Units to be issued in connection with a distribution with respect to the Class B Units shall be the quotient of (A) the Class B Distribution Amount divided by (B) the volume-weighted average trading price per unit, as adjusted for splits, combinations and other similar transactions, of our common units, calculated over the consecutive 30-trading day period ending on the close of trading on the trading day immediately prior to such date, calculated as of the date the Class B Unit Distribution is declared; provided that instead of issuing any fractional Class B Units, we will round the number of Class B Units issued down to the next lower whole Class B Unit and pay cash in lieu of such fractional units, or at our option, we may round the number of Class B Units issued up to the next higher whole Class B Unit. In the event of a liquidation, unit exchange, merger, consolidation or similar event, each Class B Unit (prior to its eligibility for conversion as described below) will be entitled to receive the greater of (1) the amount of cash or property distributed in respect of each common unit and (2) an amount of cash or property having a value equal to $18.91 per unit (the “Class B Unit Price”).
	The Class B Units may be converted into Common Units on a one-for-one basis at the option of the holder in the following amounts and subject to the following conditions: (1) 50% of the outstanding Class B Units may be converted after January 1, 2014, provided that the volume-weighted average price of our common units for the 30 trading days (the “30-day VWAP”) preceding any date during the quarter ending December 31, 2013 exceeds $30 per common unit; (2) 50% of the outstanding Class B Units may be converted after April 1, 2014, provided that the 30-day VWAP exceeds $30 per common unit on any day during the quarter ending March 31, 2014; and (3) amounts of Class B Units having a minimum value of $50.0 million calculated using the 30-day VWAP preceding the date of calculation at any time on or after July 1, 2014. In addition, we may elect to convert all (but not less than all) outstanding Class B Units into common units on a one-for-one basis at any time on or after July 1, 2014. The number of Class B Units is subject to adjustment for issuances below the Class B Unit Price prior to conversion on a weighted average basis, unit splits and unit combinations.
	The Regency Merger Agreement provides that, at the effective time of the merger, each Class B unit issued and outstanding or deemed issued and outstanding as of immediately prior to the effective time will be converted into the right to receive merger consideration (the “Regency Merger Consideration”), consisting of (i) 1.020 Regency common units and (ii) an amount of cash to make up for the difference in PVR and Regency distributions.

Partners_Capital_and_Distribut

Partners' Capital and Distributions	12 Months Ended
	Dec. 31, 2013
Partners' Capital and Distributions	'
	14. Partners’ Capital and Distributions
	As of December 31, 2013, partners’ capital consisted of 112.2 million common units and 24.3 million Class B Units representing limited partner interests in PVR. As noted in the Consolidated Statement of Partners’ Capital and described in Note 1, “Organization and Basis of Presentation,” and Note 13, “PVR Unit Offerings” our outstanding number of units has changed significantly in connection with the PVR-PVG Merger and the Chief Acquisition.
	Class B Units
	On February 13, 2014, the date on which we paid distributions with respect to the quarter ended December 31, 2013, there were 24,305,507 Class B Units outstanding. We paid distributions to the holders of the Class B Units with respect to the quarter ended December 31, 2013 by issuing an aggregate of 505,576 additional Class B Units. If we were to pay distributions to the holders of the Class B Units in cash, rather than in additional Class B Units, at the same per unit quarterly cash distributions to which the holders of our common units are entitled with respect to the quarter ended December 31, 2013, the amount of cash distributions that would have been attributable to the Class B Units was $13.4 million.
	Net Income (Loss) per Common Unit
	The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit data):
			Year Ended December 31,
			2013			2012			2011
	Net income (loss)		$	12,994		$	(70,622	)	$	96,343
	Noncontrolling interest net loss			—			—			664
	Net income (loss) attributable to PVR Partners, L.P.		$	12,994		$	(70,622	)	$	97,007
	Less:
	Distributions to participating securities			(51,961	)		(29,716	)		(410	)
	Recognition of beneficial conversion feature (1)			(70,009	)		(45,967	)		—
	Participating securities’ allocable share of undistributed net loss (income)			26,619			23,102			(300	)
	Net income (loss) allocable to common units, basic and diluted		$	(82,357	)	$	(123,203	)	$	96,297
	Weighted average number of common units outstanding, basic and diluted			99,304			86,222			66,342
	Net income (loss) per common unit, basic and diluted		$	(0.83	)	$	(1.43	)	$	1.45
	-1	Special Units and Class B Units were issued at prices below the market price of the common units into which they are convertible. The aggregate discount of $139.2 million represents a beneficial conversion feature which is considered a non-cash distribution that will be distributed ratably using the effective yield method over the period the Special Units and Class B Units are outstanding. The impact of the beneficial conversion feature is included as distributed income to Class B Units and Special Units with a corresponding reduction in net income allocable to common units in the calculation of net income (loss) per common unit for the years ended December 31, 2013 and 2012.
	Basic net income (loss) per common unit is computed by dividing net income (loss) allocable to common units by the weighted average number of common units outstanding and vested deferred common units outstanding during the period.
	Diluted net income (loss) per common unit is computed by dividing net income (loss) allocable to common units by the weighted average number of common units outstanding and vested deferred common units outstanding during the period and, when dilutive, Class B Units, Special Units, and phantom units. The following table presents the weighted average number of each class of participating securities that were excluded from the diluted net income (loss) per common unit calculation because the inclusion of these units would have had an antidilutive effect:
			2013			2012			2011
	Special units			8,787			6,473			—
	Class B units			23,372			13,630			—
	Phantom units			78			63			37
				32,237			20,166			37
	Cash Distributions
	We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to common unitholders of record. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or any other agreements and (iii) provide funds for distributions to unitholders for any one or more of the next four quarters. During the years ended December 31, 2013, 2012 and 2011 we paid cash distributions of $214.4 million, $176.3 million and $135.3 million.
	On February 13, 2014, we paid a $0.55 per unit quarterly distribution to common unitholders of record on February 7, 2014.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions	'
	15. Related Party Transactions
	We own a 51% membership interest in a joint venture, Aqua — PVR Water Services LLC (“Aqua — PVR”), where we construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. Related to the Aqua-PVR joint venture we have executed agreements where PVR charges the joint venture a fee for construction management services and provides accounting management services. The construction management services fee is 10% of the construction costs of a project managed by PVR. PVR has also purchased water from the joint venture to test our natural gas pipelines before they were placed into service. These fees and purchases began in 2012 and are not presumed to be carried out on an arm’s-length basis. The construction fees are invoiced once the project is complete, and the other services or purchases are invoiced once incurred or quarterly. The table below discloses the related party transactions for the period presented. The statements of operations amounts are net of eliminations.
		Year Ended December 31,
		2013		2012
	Consolidated Statements of Operations:
	Other income	$	648	$	3,150
	General and administrative	$	43	$	26
		December 31,		December 31,
		2013		2012
	Consolidated Balance Sheets:
	Accounts receivable	$	5,281	$	6,442
	Accounts payable	$	—	$	172

UnitBased_Payments

Unit-Based Payments	12 Months Ended
	Dec. 31, 2013
Unit-Based Payments	'
	16. Unit-Based Payments
	Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. These standards require us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award.
	The PVR GP, LLC Sixth Amended and Restated Long-Term Incentive Plan (“LTIP”) permits the grant of common units, deferred common units, unit options, restricted units and phantom units to employees and directors of our general partner and its affiliates. Common units and deferred common units granted under the LTIP are immediately vested, and we recognize compensation expenses related to those grants on the grant date. Restricted units and time-based and performance-based phantom units granted under the LTIP generally vest over a three-year period, and we recognize compensation expense related to those grants on a straight-line basis over the vesting period. Compensation expense related to these grants is recorded in the general and administrative expenses caption on our Consolidated Statements of Operations. As of December 31, 2013, the LTIP permitted the grant of awards covering an aggregate of 3,000,000 common units to employees and directors of our general partner and employees of its affiliates who perform services for us. Common units delivered under the LTIP may consist of newly issued common units or common units acquired in the open market.
	In connection with the normal three-year vesting of phantom and restricted units, as well as common unit and deferred common unit awards, we recognized the following expenses during the periods presented:
		2013			2012			2011
	Phantom units	$	3,533		$	3,848		$	3,025
	Director deferred and common units		626			579			820
		$	4,159		$	4,427		$	3,845
	Common Units. At the election of a non-employee director, a portion of the director’s cash compensation may be paid in common units. Our general partner granted 21,811 common units at a weighted average grant-date fair value of $25.24 per unit to non-employee directors in 2013. Our general partner granted 16,020 common units at a weighted average grant-date fair value of $24.35 per unit to non-employee directors in 2012. Our general partner granted 2,176 common units at a weighted average grant-date fair value of $25.23 per unit to non-employee directors in 2011. The fair value of the common units is calculated based on the grant-date unit price.
	Deferred Common Units. At the election of non-employee directors, a portion of the compensation to non-employee directors is paid in deferred common units. Each deferred common unit represents one common unit, which vests immediately upon issuance and is available to the holder upon termination or retirement from the board of directors.
	The following is a summary of deferred common unit activity for the periods presented:
		Number of			Weighted Average
		Deferred			Grant-Date Fair
		Common Units			Value
	Balance at January 1, 2011		126,582		$	21.62
	Granted and vested		113,400		$	26.99
	Converted to common units		(2,839	)	$	18.16
	Balance at December 31, 2011		237,143		$	24.23
	Granted and vested		28,167		$	24.21
	Converted to common units		(41,007	)	$	23.26
	Balance at December 31, 2012		224,303		$	24.4
	Granted and vested		23,401		$	24.88
	Converted to common units		(2,000	)	$	17.53
	Balance at December 31, 2013		245,704		$	24.5
	In 2013, 2,000 deferred common units converted to common units. The aggregate intrinsic value of deferred common units converted to common units in 2013 was less than $0.1 million. In 2012, 41,007 deferred common units converted to common units. The aggregate intrinsic value of deferred common units converted to common units in 2012 was $1.0 million. In 2011, 2,839 deferred common units converted to common units. The aggregate intrinsic value of deferred common units converted to common units in 2011 was $0.1 million. The aggregate intrinsic value of vested deferred common units at December 31, 2013, was $6.0 million. The fair value of the deferred common units is calculated based on the grant-date unit price.
	Restricted Units. Restricted units vest upon terms established by the Compensation and Benefits Committee (the “Committee”). In addition, all restricted units will vest upon a change of control of our general partner. If a grantee’s employment with, or membership on the board of directors of, our general partner terminates for any reason, the grantee’s unvested restricted units will be automatically forfeited unless, and to the extent that, the Committee provides otherwise. Distributions payable with respect to restricted units may, in the Committee’s discretion, be paid directly to the grantee or held by our general partner and made subject to a risk of forfeiture during the applicable restriction period. Restricted units generally vest over a three-year period, with one-third vesting in each year. The fair value of the restricted units is calculated based on the grant-date unit price. There were no restricted unit grants made in 2013, 2012 or 2011.
	Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Committee, the cash equivalent of the value of a common unit. The Committee determines the time period over which phantom units granted to employees and directors will vest. In addition, all phantom units will vest upon a change of control of our general partner. If a director’s membership on the board of directors of our general partner terminates for any reason, or an employee’s employment with our general partner and its affiliates terminates for any reason other than retirement after reaching age 62, the grantee’s phantom units will be automatically forfeited unless, and to the extent, the Committee provides otherwise.
	Generally, we pay or accrue distributions for all of our unvested phantom units. Payments of distributions associated with phantom units that are expected to vest are recorded as capital distributions; however, payments associated with phantom units that are not expected to vest are recorded as compensation expense. During 2013, we granted 288 thousand phantom units at a weighted average grant-date fair value of $23.19, consisting of 186 thousand time-based phantom units and 102 thousand performance-based phantom units. During 2012, we granted 238 thousand phantom units at a weighted average grant-date fair value of $18.21, consisting of 125 thousand time-based phantom units and 113 thousand performance-based phantom units. During 2011, we granted 261 thousand phantom units at a weighted average grant-date fair value of $21.32, including 155 thousand time-based phantom units and 106 thousand performance-based phantom units.
	Time-based phantom units generally vest over a three-year period, with one-third vesting in each year. Time-based phantom units are generally entitled to non-forfeitable distribution rights which are paid quarterly along with common unit distributions. A portion of the vested units were withheld for payroll taxes with the recipient receiving the net vested units. The fair value of time-based phantom units is calculated based on the grant-date unit price.
	Performance-based phantom units cliff-vest at the end of a three year period. The number of units that could vest ranges from 0% to 200% of the number of performance-based phantom units initially granted and depends on the outcome of unit market performance compared to peers and, for certain grants, key results of operations metrics. Performance-based phantom units are entitled to forfeitable distribution equivalent rights which accumulate over the term of the units and will be paid in cash to the grantees at the date of vesting. The fair value of each performance-based phantom unit granted in 2013 was $17.60. The fair value of each performance-based phantom unit granted in 2012 was $5.85, and the fair value of each performance-based phantom unit granted in 2011 was $6.29. These fair values were estimated on the date of grant using a Monte Carlo simulation approach that uses the assumptions noted in the following table. Expected volatilities are based on historical changes in the market value of our common units. We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the phantom units, continuously compounded.
		2013			2012			2011
	Expected volatility		28.2	%		34.03	%		54.53	%
	Expected life		2.7 years			2.9 years			2.6 years
	Risk-free interest rate		0.31	%		0.4	%		0.83	%
	The performance-based phantom units granted in 2012 may vest in 2015 depending on the achievement of specified performance goals measured over a performance period ending December 31, 2014. Because our estimate of the achievement of the specified performance goals differed at December 31, 2013, as compared to the estimate at December 31, 2012, the fair value of each performance-based phantom unit granted in 2012 decreased to $5.85 at December 31, 2013 from $10.92 at December 31, 2012.
	On December 10, 2013, the Compensation and Benefits Committee of the Board of Directors of our general partner approved a modification to all performance-based phantom units that were granted in 2011 and were outstanding at December 10, 2013. The modification allows for the vesting and payout of the 2011 performance-based phantom units at target level of performance, subject to the closing of the Regency Merger. All other terms and conditions of the 2011 performance-based phantom units remain the same. Approximately 88 thousand performance-based phantom units granted to 14 employees were affected by the modification. Because the performance condition in the original award was improbable as of the date of modification, the fair value of each performance-based phantom unit granted in 2011 decreased to $6.29 at December 31, 2013 from $11.66 at December 31, 2012. The grant-date fair value of the modified award is $24.67 and is based on the grant-date unit price. Additional compensation expense will be recognized in 2014 for the modified award if the Regency Merger closes.
	The following table summarizes the status of our nonvested phantom units as of December 31, 2013 and changes during the year then ended:
		Nonvested			Weighted
		Phantom			Average
		Units			Grant-Date
					Fair Value
	Nonvested at January 1, 2013		414,390		$	16.27
	Granted		287,703		$	23.19
	Vested		(114,134	)	$	25.76
	Forfeited		(40,724	)	$	18.2
	Cancellation		(88,476	)	$	6.29
	Reissuance		88,476		$	24.67
	Nonvested at December 31, 2013		547,235		$	20.75
	At December 31, 2013, we had $5.6 million of total unrecognized compensation cost related to nonvested phantom units. We expect that cost to be recognized over a weighted-average period of 2.4 years. The total grant-date fair value of phantom units that vested in 2013, 2012 and 2011 was $2.9 million, $2.9 million and $0.9 million. The aggregate intrinsic value at December 31, 2013, of phantom units expected to vest was $9.2 million.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies	'
	17. Commitments and Contingencies
	Rental Commitments
	Operating lease rental expense in the years ended December 31, 2013, 2012 and 2011 was $12.9 million, $13.0 million and $10.8 million. The following table sets forth our minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2013:
		Minimum Rental
	Year	Commitments
	2014	$	6,385
	2015		5,143
	2016		3,852
	2017		2,973
	2018		1,159
	Thereafter		4,788
	Total minimum payments	$	24,300
	Our rental commitments primarily relate to equipment and building leases and leases of coal reserve-based properties which we sublease, or intend to sublease, to third parties. The obligation with respect to leased properties which we sublease expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. We believe that the future rental commitments with regard to this subleased property cannot be estimated with certainty.
	Firm Transportation Commitments
	As of December 31, 2013, we had contracts for firm transportation capacity rights for specified volumes per day on a pipeline system with terms that ranged from one to five years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion. The following table sets forth our obligation for firm transportation commitments in effect at December 31, 2013 for the next five years and thereafter:
	Year	Firm
		Transportation
		Commitments
	2014	$	10,332
	2015		1,759
	2016		—
	2017		—
	2018		—
	Thereafter		—
	Total firm transportation commitments	$	12,091
	Legal
	We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position or results of operations.
	Environmental Compliance
	Our operations and those of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations.
	As of December 31, 2013 and 2012, our environmental liabilities were $0.9 million respectively for each year, which represent our best estimate of the liabilities as of those dates related to our Eastern Midstream, Midcontinent Midstream and Coal and Natural Resource Management businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.
	Mine Health and Safety Laws
	There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Information	'
	18. Segment Information
	Our operating segments represent components of our business about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our coal and natural resource management operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows:
	•		Eastern Midstream — Our Eastern Midstream segment is engaged in providing natural gas gathering, transportation and other related services in Pennsylvania, Ohio and West Virginia. In addition, we own membership interests in a joint venture that transports fresh water to natural gas producers.
	•		Midcontinent Midstream — Our Midcontinent Midstream segment is engaged in providing natural gas gathering, processing and other related services. These processing and gathering systems are located primarily in Oklahoma and Texas.
	•		Coal and Natural Resource Management — Our Coal and Natural Resource Management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting oil and gas royalties.
	The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2013, 2012 and 2011:
			Eastern		Midcontinent			Coal and		Consolidated
			Midstream (1)		Midstream (2)			Natural
								Resource
								Management (3)
	Year Ended December 31, 2013
	Revenues		$	200,217	$	807,165		$	110,104	$	1,117,486
	Cost of midstream gas purchased			—		666,239			—		666,239
	Operating costs and expenses			30,990		64,241			27,254		122,485
	Merger and acquisition costs			2,713		2,713			2,712		8,138
	Depreciation, depletion & amortization			97,973		61,809			28,159		187,941
	Operating income		$	68,541	$	12,163		$	51,979	$	132,683
	Interest expense										(106,248	)
	Loss on extinguishment of debt										(13,703	)
	Derivatives										(1,070	)
	Other										1,332
	Net income									$	12,994
	Additions to property and equipment		$	338,296	$	74,991		$	2,498	$	415,785
	Year Ended December 31, 2012
	Revenues		$	99,350	$	771,723		$	136,681	$	1,007,754
	Cost of midstream gas purchased			—		630,345			—		630,345
	Operating costs and expenses			17,186		66,618			31,964		115,768
	Merger and acquisition costs			14,049		—			—		14,049
	Impairments			—		124,845			—		124,845
	Depreciation, depletion & amortization			42,713		51,829			32,802		127,344
	Operating income (loss)		$	25,402	$	(101,914	)	$	71,915	$	(4,597	)
	Interest expense										(68,773	)
	Derivatives										2,291
	Other										457
	Net income (loss)									$	(70,622	)
	Additions to property and equipment		$	1,224,722	$	136,775		$	1,034	$	1,362,531
	Year Ended December 31, 2011
	Revenues		$	26,170	$	944,852		$	188,953	$	1,159,975
	Cost of midstream gas purchased			—		817,937			—		817,937
	Operating costs and expenses			2,737		60,505			35,849		99,091
	Depreciation, depletion & amortization			4,243		47,956			37,177		89,376
	Operating income		$	19,190	$	18,454		$	115,927	$	153,571
	Interest expense										(44,287	)
	Derivatives										(13,442	)
	Other										501
	Net income									$	96,343
	Additions to property and equipment		$	120,310	$	121,789		$	134,503	$	376,602
			Total assets at December 31,
			2013		2012			2011
	Eastern Midstream (4)		$	1,893,483	$	1,677,846		$	174,444
	Midcontinent Midstream (5)			594,999		640,437			736,351
	Coal and Natural Resource Management (6)			637,188		680,426			683,197
	Totals		$	3,125,670	$	2,998,709		$	1,593,992
	-1	Our Eastern Midstream segment’s revenues for the years ended December 31, 2013 and 2012 include $(2.2) million and $2.0 million of equity earnings (loss) related to our 51% interest in the Aqua-PVR joint venture. See Note 9, “Equity Investments” for a further description.
	-2	Our Midcontinent Midstream segment’s revenues for the years ended December 31, 2013, 2012 and 2011 include $15.2 million, $(7.6) million and $2.5 million of equity earnings (loss) related to our 25% membership interest in Thunder Creek. The 2013 revenue includes the gain on sale of the Thunder Creek equity investment. The loss in 2012 relates to an impairment charge of $8.7 million. See Note 9, “Equity Investments” for a further description of this segment’s equity investment.
	-3	Our Coal and Natural Resource Management segment’s revenues for the years ended December 31, 2013, 2012 and 2011 include $1.4 million, $2.8 million and $2.3 million of equity earnings related to our 50% interest in Coal Handling Solutions LLC. See Note 9, “Equity Investments” for a further description.
	-4	Total assets at December 31, 2013, 2012 and 2011 for the Eastern Midstream segment included equity contributions of $15.3 million, $35.7 million and $5.3 million related to our 51% interest in the Aqua-PVR joint venture. The equity investment at December 31, 2013, 2012 and 2011 for the Aqua-PVR joint venture was $47.2 million, $36.8 million and $5.3 million. See Note 9, “Equity Investments” for a further description.
	-5	The equity investment in our 25% membership interest in Thunder Creek was sold in August 2013 and had a carrying value of $44.3 million. Total assets at December 31, 2012 and 2011 for the Midcontinent Midstream segment included equity investment of $45.2 million and $53.1 million related to Thunder Creek. See Note 9, “Equity Investments” for a further description.
	-6	Total assets at December 31, 2013, 2012 and 2011 for the Coal and Natural Resource Management segment included equity investment of $13.6 million, $15.6 million and $16.3 million related to our 50% interest in Coal Handling Solutions LLC. See Note 9, “Equity Investments” for a further description.
	Operating income is equal to total revenues less cost of midstream gas purchased, operating costs and expenses and DD&A expense. Operating income does not include interest expense, certain other income items and derivatives. Identifiable assets are those assets used in our operations in each segment.
	In 2013, 51% of our total consolidated revenues and 51% of our December 31, 2013 consolidated accounts receivable resulted from seven of our natural gas midstream customers. Within the Eastern Midstream segment for 2013, 55% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from three customers. Within the Midcontinent Midstream segment for 2013, 57% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from four customers. These customer concentrations may impact our results of operations, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We are not aware of any financial difficulties experienced by these customers.
	In 2012, 37% of our total consolidated revenues and 34% of our December 31, 2012 consolidated accounts receivable resulted from four of our natural gas midstream customers. Within the Eastern Midstream segment for 2012, 47% of the segment’s revenues and 33% of the December 31, 2012 accounts receivable for the segment resulted from one customer. Within the Midcontinent Midstream segment for 2012, 42% of the segment’s revenues and 39% of the December 31, 2012 accounts receivable for the segment resulted from three customers.
	For the year ended December 31, 2011, four of our Midcontinent Midstream segment customers accounted for 40% of our total consolidated revenues.

Supplemental_Quarterly_Financi

Supplemental Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Supplemental Quarterly Financial Information (Unaudited)	'
	Supplemental Quarterly Financial Information (Unaudited, in thousands except per unit data)
			First			Second			Third			Fourth
			Quarter			Quarter			Quarter			Quarter
	2013
	Revenues (1)		$	263,411		$	273,465		$	288,964		$	291,646
	Operating income (1)		$	31,262		$	29,956		$	47,099		$	24,366
	Net income (loss)		$	7,237		$	5,508		$	17,888		$	(17,639	)
	Basic net income (loss) per limited partner unit (2)		$	(0.17	)	$	(0.21	)	$	(0.09	)	$	(0.35	)
	Diluted net income (loss) per limited partner unit (2)		$	(0.17	)	$	(0.21	)	$	(0.09	)	$	(0.37	)
	Weighted average number of units outstanding, basic			95,906			95,947			96,983			108,268
	Weighted average number of units outstanding, diluted			95,906			95,947			96,983			112,429
	2012
	Revenues (3)		$	246,417		$	222,912		$	268,847		$	269,578
	Operating income (loss) (3)		$	(95,692	)	$	14,535		$	60,491		$	16,069
	Net income (loss)		$	(110,344	)	$	7,809		$	38,783		$	(6,870	)
	Basic and diluted net income (loss) per limited partner unit (2)		$	(1.39	)	$	(0.07	)	$	0.16		$	(0.30	)
	Weighted average number of units outstanding, basic			79,301			83,786			88,366			93,333
	Weighted average number of units outstanding, diluted			79,340			83,786			88,366			93,333
	-1	Revenues and operating income in the third quarter of 2013 includes the $14.3 million gain on sale of our 25% equity investment in Thunder Creek.
	-2	Certain participating securities with beneficial conversion features were issued in conjunction with the Chief Acquisition. These participating securities and the effects of the beneficial conversion features have impacted the earnings (loss) per unit calculation. The sum of the quarters may not equal the total of the respective year’s net income (loss) per limited partner unit due to applying the two-class method of calculating net income (loss) per limited partner unit.
	-3	Operating income (loss) in the first quarter of 2012 includes the $124.8 million impairment of the North Texas Gathering System. Revenues and operating income for the fourth quarter of 2012 includes the $8.7 million impairment of our 25% equity investment in Thunder Creek.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Use of Estimates	'
	Use of Estimates
	Preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment consist of our ownership in coal fee mineral interests, our royalty interest in oil and natural gas wells, forestlands, processing facilities, gathering systems, compressor stations and related equipment. Property, plant and equipment are carried at cost and include expenditures for additions and improvements, such as roads and land improvements, which increase the productive lives of existing assets. Maintenance and repair costs are charged to expense as incurred. Renewals and betterments, which extend the useful life of the properties, are capitalized. We compute depreciation and amortization of property, plant and equipment using the straight-line method except for well connects, which generally are depreciated using the accelerated method. The estimated useful life of each asset is as follows:
		Useful Life
	Gathering systems	7 – 20 years
	Compressor stations	3 – 15 years
	Processing plants	15 years
	Other property and equipment	3 – 20 years
	Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, we carry out core-hole drilling activities on our coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. We deplete timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. We determine depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. When we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our consolidated balance sheet. Upon sale, we record the difference between the net book value, net of any assumed asset retirement obligation (“ARO”), and proceeds from disposition as a gain or loss.
	Intangible assets are primarily associated with assumed contracts, customer relationships and other. These intangible assets are amortized on a straight-line basis over periods of up to 26 years, the period in which benefits are derived from the contracts, customer relationships and other, and are reviewed for impairment along with their associated property, plant and equipment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	We recognize the fair value of a liability for an ARO in the period in which it is incurred. The determination of fair value is based upon regional market and specific facility type information. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. The long-lived assets for which our AROs are recorded include compressor stations, gathering systems and coal processing plants. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed rate, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion and the depreciation are included in depreciation, depletion and amortization (“DD&A”) expense on our consolidated statements of operations.
	In connection with our natural gas midstream assets, we are obligated under federal regulations to perform limited procedures around the abandonment of pipelines. In some cases, we are unable to reasonably determine the fair value of such ARO because the settlement dates, or ranges thereof, are indeterminable. An ARO will be recorded in the period in which we can reasonably determine the settlement dates.
Impairment of Long-Lived Assets	'
	Impairment of Long-Lived Assets
	The Eastern Midstream, Midcontinent Midstream and Coal and Natural Resource Management segments have completed a number of acquisitions in recent years. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, intangibles and the resulting amount of goodwill, if any. Changes in operations, decreases in commodity prices, changes in the business environment or deteriorations of market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows.
	We review long-lived assets to be held and used, including definite-lived intangible assets, whenever triggering events or circumstances indicate that the carrying value of those assets may not be recoverable. Triggering events include, but are not limited to, changes in operations; decreases in commodity prices, the amounts of which may vary depending on the asset involved; changes in the business environment; or deteriorations of market conditions. When a triggering event occurs, we estimate the future cash flows of the related assets. Our estimates of future cash flows depend on our projections of revenues and expenses for future periods. These projections are driven by our estimates or evaluation of growth rates, changes in market conditions, and changes in prices received or paid, among other factors. When the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows, we recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset. Fair value is estimated to be the present value of future net cash flows from the asset, discounted using a rate commensurate with the risk and remaining life of the asset.
Impairment of Goodwill	'
	Impairment of Goodwill
	Goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually. We have the option to make a qualitative assessment of whether it is more likely than not a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. If we conclude it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, we do not need to perform the two-step impairment test. If the two-step impairment test is required, the first step of the impairment test is used to identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value of a reporting unit exceeds its book value, goodwill of the reporting unit is not considered impaired, and the second step of the impairment test is not required. If the book value of a reporting unit exceeds its fair value, the second step of impairment test compares the implied fair value of the reporting unit’s goodwill with the book value of that goodwill. If the book value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination. The annual impairment testing is performed in the fourth quarter. We quantitatively tested the Eastern Midstream segment, our only reporting unit with goodwill, and determined that no impairment charge was necessary.
Equity Investments	'
	Equity Investments
	We use the equity method of accounting to account for our membership interest in various joint ventures, recording the initial investment at cost. Subsequently, the carrying amounts of the investments are increased to reflect our share of income of the investees and capital contributions, and are reduced to reflect our share of losses of the investees or distributions received from the investees as the joint ventures report them. Our share of earnings or losses from these joint ventures is included in other revenues on the consolidated statements of operations. Other revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets. We record this amortization over the life of the contracts acquired, 14 years. In the event of an impairment or a gain on sale of a joint venture, the impairment charge or gain is classified in the same line of the income statement as the equity earnings or loss are recorded, “Other revenues” in the consolidated statement of operations.
Debt Issuance Costs	'
	Debt Issuance Costs
	Debt issuance costs relating to long-term debt have been capitalized and are being amortized and recorded as interest expense over the term of the related debt instrument.
Long-Term Prepaid Minimums	'
	Long-Term Prepaid Minimums
	We lease a portion of our reserves from third parties that require monthly or annual minimum rental payments. The prepaid minimums are recoupable from future production and are deferred and charged to coal royalties expense as the coal is subsequently produced. We evaluate the recoverability of the prepaid minimums on a periodic basis; consequently, any prepaid minimums that cannot be recouped are charged to coal royalties expense.
Environmental Liabilities	'
	Environmental Liabilities
	Other liabilities include accruals for environmental liabilities that we either assumed in connection with certain acquisitions or recorded in operating expenses when it became probable that a liability had been incurred and the amount of that liability could be reasonably estimated.
Concentration of Credit Risk	'
	Concentration of Credit Risk
	In 2013, 51% of our total consolidated revenues and 51% of our December 31, 2013 consolidated accounts receivable resulted from seven of our natural gas midstream customers. Within the Eastern Midstream segment for 2013, 55% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from three customers. Within the Midcontinent Midstream segment for 2013, 57% of the segment’s revenues and 54% of the December 31, 2013 accounts receivable for the segment resulted from four customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these natural gas midstream customers. These customer concentrations increase our exposure to credit risk on our receivables, since the financial insolvency of these customers could have a significant impact on our results of operations. As of December 31, 2013, we had recorded a $0.3 million allowance for doubtful accounts in the Midcontinent Midstream segment.
Revenues	'
	Revenues
	Natural Gas Midstream Revenues. We recognize revenues from the sale of natural gas liquids (“NGLs”) and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and trunkline revenues based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.
	Coal Royalties Revenues and Deferred Income. We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most of our lessees must make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.
Derivative Instruments	'
	Derivative Instruments
	From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of collars and swaps. All derivative financial instruments are recognized in our consolidated financial statements at fair value. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by the board of directors of our general partner. We do not use hedge accounting for commodity derivatives; thus, the open positions are recorded at fair value with the change in value recorded to earnings.
	We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The lack of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark- to-market gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment.
	At December 31, 2013 and 2012, we had no open derivative contracts to hedge commodity prices. Therefore, no derivative assets or liabilities were reported as of December 31, 2013 and 2012.
	Historically, we have entered into interest rate swap agreements (the “Interest Rate Swaps”) to mitigate our exposure to debt interest expense. During the year ended December 31, 2012, we reclassified a total net gain of $0.7 million from accumulated other comprehensive income (“AOCI”) to earnings related the Interest Rate Swaps. At December 31, 2012, no gain or loss remained in AOCI to be recognized in the Derivatives line as the Interest Rate Swaps settled. At December 31, 2013 and 2012, we had no open derivative contracts to hedge interest rates.
Income Taxes	'
	Income Taxes
	As a partnership, we are not subject to federal income tax. The taxable income and losses of the Partnership are includable in the federal and state income tax returns of our partners. Net income for financial statement purposes may differ significantly from taxable income reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under our partnership agreement.
Net Income (Loss) per Limited Partner Unit	'
	Net Income (Loss) per Limited Partner Unit
	We are required to allocate earnings or losses for a reporting period to our limited partners and the participating securities using the two-class method to compute earnings per unit. The two-class method is an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available to common unitholders. Participating securities may participate in undistributed earnings with common units, whether that participation is conditioned upon the occurrence of a specified event or not. The form of such participation does not have to be a dividend, that is, any form of participation in undistributed earnings would constitute participation by that security, regardless of whether the payment to the security holder was referred to as a dividend. Under this method, our net income (loss) for a reporting period is reduced (or increased) by the amount that has been or will be distributed to our participating security holders. Unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of net income (loss) allocable to limited partners pursuant to the two-class method of computing earnings per unit. Class B Units and Special Units participate in the allocation of income, gains and losses with the common units; therefore, these forms of equity are participating securities. Thus, our securities consist of publicly traded common units held by limited partners and participating securities as a result of unit-based compensation and issuance of other classes of equity.
	During 2013, 2012 and 2011, service-based and performance-based phantom units were granted to employees. We have determined that our unvested service-based phantom unit awards generally contain non-forfeitable rights to distributions and, therefore, are participating securities. The performance based phantom units contain forfeitable rights to distributions and, therefore, are not participating securities.
	Basic and diluted net income (loss) per limited partner unit is computed by dividing net income (loss) allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income (loss) per limited partner unit is computed by dividing net income (loss) allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units, Class B Units and Special Units.
Unit-Based Compensation	'
	Unit-Based Compensation
	Our long-term incentive plan permits the grant of awards to directors and employees of our general partner and employees of its affiliates who perform services for us. Awards under our long-term incentive plan can be in the form of common units, restricted units, unit options, phantom units and deferred common units. Our long-term incentive plan is administered by the compensation and benefits committee of our general partner’s board of directors. We recognize compensation expense over the vesting period of the awards.
	Authoritative accounting literature establishes standards for transactions in which an entity exchanges its equity instruments for goods and services. This standard requires us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. See Note 16, “Unit-Based Payments,” for a more detailed description of our long-term incentive plan.
New Accounting Standards	'
	New Accounting Standards
	During the first quarter of 2013, we adopted Accounting Standard Update (“ASU”) 2013-02, Comprehensive Income (Topic 220). The new ASU requires us to disclose in a single location (either on the face of the statement of operations or in the notes) the effects of reclassifications out of accumulated other comprehensive income (“AOCI”). The new disclosure requirements were effective for the first quarter 2013 and apply prospectively. All of our AOCI amounts were reclassified in 2012 and no amounts remained as of December 31, 2012. Therefore, adoption of this ASU does not have an effect on our financials.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Estimated Useful Life Of Property, Plant And Equipment	'
	We compute depreciation and amortization of property, plant and equipment using the straight-line method except for well connects, which generally are depreciated using the accelerated method. The estimated useful life of each asset is as follows:
		Useful Life
	Gathering systems	7 – 20 years
	Compressor stations	3 – 15 years
	Processing plants	15 years
	Other property and equipment	3 – 20 years

Acquisitions_Tables

Acquisitions (Tables) (Chief Gathering LLC)	12 Months Ended
	Dec. 31, 2013
Chief Gathering LLC	'
Allocation of Purchase Price Allocation	'
	Below is the detailed allocation of the purchase price allocation:
	Cash consideration paid for Chief	$	849,262
	Special units issued as consideration to Chief		191,302
	Total purchase price	$	1,040,564
	Accounts receivable	$	4,412
	Property, plant and equipment		376,953
	Intangible assets		622,000
	Goodwill		70,283
	Other long-term assets		415
	Accounts payable		(33,499	)
	Total purchase price	$	1,040,564
Pro Forma Financial Information	'
	The pro forma financial information is not necessarily indicative of the results of operations had these transactions been effected on the assumed date (in thousands, except per unit data):
		Years Ended December 31,
		2012			2011
	Revenues	$	1,021,297		$	1,182,381
	Net income (loss) attributable to PVR	$	(82,696	)	$	19,060
	Net income (loss) per limited partner unit, basic and diluted	$	(1.84	)	$	(0.87	)

Fair_Value_Measurement_Tables

Fair Value Measurement (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Estimates for Non Financial Assets and Liabilities Measured at Fair Value on Nonrecurring Basis	'
	The following table summarizes the fair value estimates for financial and nonfinancial assets and liabilities measured at fair value on a nonrecurring basis by category as of the acquisition date:
					Fair Value Measurements during 2012, Using
	Description	Fair Value			Quoted Prices in		Significant Other		Significant
		Measurements at			Active Markets for		Observable Inputs		Unobservable
		Acquisition Date			Identical Assets		(Level 2)		Inputs (Level 3)
					(Level 1)
	Chief property, plant and equipment	$	376,953		$	—	$	—	$	376,953
	Chief intangible assets		622,000			—		—		622,000
	Chief goodwill		70,283			—		—		70,283
	Chief other long-term assets		415			—		—		415
	Chief working capital		(29,087	)		—		—		(29,087	)
	Total	$	1,040,564		$	—	$	—	$	1,040,564

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Effects of Derivative Activities and Location of Gains and Losses on Statement of Income	'
	The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses, on our consolidated statements of operations for the periods presented:
			Location of gain (loss)
			on derivatives recognized	Year Ended December 31,
			in income	2013			2012			2011
	Derivatives not designated as hedging instruments:
	Interest rate contracts		Derivatives	$	—		$	538		$	(851	)
	Commodity contracts		Derivatives		(1,070	)		1,753			(12,591	)
	Total decrease (increase) in net income resulting from derivatives			$	(1,070	)	$	2,291		$	(13,442	)
	Realized and unrealized derivative impact:
	Cash paid for commodity and interest rate contract settlements (1)		Derivatives	$	(1,070	)	$	(10,494	)	$	(25,688	)
	Unrealized derivative gains (2)				—			12,785			12,246
	Total decrease in net income resulting from derivatives			$	(1,070	)	$	2,291		$	(13,442	)
	-1	As of December 31, 2013 and included in the settlement amounts is $0.5 million related to settled positions that were paid in January 2014. As of December 31, 2012 and included in the settlement amounts is a net $0.2 million related to settled positions that were paid in January 2013.
	-2	This activity represents unrealized gains in the natural gas midstream revenue, cost of midstream gas purchased, and interest expense. All amounts are reported in the derivatives line on our consolidated statements of operations.

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Property and Equipment	'
	The following table summarizes our property, plant and equipment for the periods presented:
		As of December 31,
		2013			2012
	Gathering systems	$	1,298,570		$	984,986
	Compressor stations		361,872			283,189
	Processing plants		130,527			116,942
	Other property, plant and equipment		24,757			17,484
	Construction in progress		194,559			252,635
	Coal properties		636,933			634,555
	Timber		88,447			88,447
	Oil and gas royalties		39,981			39,981
	Coal services equipment		35,409			35,409
	Land		26,162			26,174
	Total property, plant and equipment		2,837,217			2,479,802
	Accumulated depreciation, depletion and amortization		(647,939	)		(490,456	)
	Net property, plant and equipment	$	2,189,278		$	1,989,346

Equity_Investments_Tables

Equity Investments (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Financial Information of Unconsolidated Equity Investments	'
	Summarized financial information of unconsolidated equity investments is as follows for the periods presented:
		November 30,		November 30,
		2013		2012
	Current assets	$	22,256	$	55,351
	Noncurrent assets	$	113,378	$	273,158
	Current liabilities	$	11,909	$	38,188
	Noncurrent liabilities	$	1,682	$	3,933
		Year Ended November 30,
		2013		2012
	Revenues	$	38,900	$	59,261
	Expenses	$	35,619	$	38,463
	Net income	$	3,281	$	20,798

Intangible_Assets_Net_Tables

Intangible Assets, Net (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Net Intangible Assets	'
	The following table summarizes our net intangible assets for the periods presented:
		As of December 31,
		2013			2012
	Contracts and customer relationships	$	657,500		$	657,500
	Other		4,552			4,552
	Total intangible assets		662,052			662,052
	Accumulated amortization		(71,972	)		(41,452	)
	Intangible assets, net	$	590,080		$	620,600
Summary of Estimated Aggregate Amortization Expenses for Futures Years	'
	The following table sets forth our estimated aggregate amortization expense for the next five years and thereafter:
	Year	Amortization Expense
	2014	$	30,367
	2015		30,254
	2016		30,148
	2017		30,071
	2018		29,970
	Thereafter		439,270
	Total	$	590,080

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Aggregate Carrying Amount of Asset Retirement Obligations	'
	The following table reconciles the beginning and ending aggregate carrying amount of our asset retirement obligations for the years ended December 31, 2013 and 2012, which are recorded in other liabilities on our consolidated balance sheets:
		Year Ended December 31,
		2013		2012
	Balance at beginning of period	$	2,526	$	2,343
	Liabilities incurred		—		—
	Accretion expense		196		183
	Revision of estimate		—		—
	Balance at end of period	$	2,722	$	2,526

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Long Term Debt	'
	The following table summarizes our long-term debt for the periods presented:
		As of December 31,
		2013		2012
	Revolver - variable rate of 3.2% at December 31, 2013 and 2012	$	562,500	$	590,000
	Senior notes - fixed rate of 8.25%, due April 15, 2018		300,000		300,000
	Senior notes - fixed rate of 8.375%, due June 1, 2020		472,600		600,000
	Senior notes - fixed rate of 6.5%, due May 15, 2021		400,000		—
	Total debt		1,735,100		1,490,000
	Less: Current maturities		—		—
	Total long-term debt	$	1,735,100	$	1,490,000
Future Maturities of Long-Term Debt	'
	The following table sets forth the aggregate maturities of the principal amounts of long-term debt for the next five years and thereafter:
	Year	Aggregate
		Maturities
		Principal
		Amounts
	2014	$	—
	2015		—
	2016		562,500
	2017		—
	2018		300,000
	Thereafter		872,600
	Total debt, including current maturities	$	1,735,100

Partners_Capital_and_Distribut1

Partners' Capital and Distributions (Tables)	12 Months Ended
	Dec. 31, 2013
Reconciliation of Net Income (Loss) and Weighted Average Units Used in Computing Basic and Diluted Net Income (Loss) Per Limited Partner Unit	'
	The following table reconciles net income (loss) and weighted average units used in computing basic and diluted net income (loss) per common unit (in thousands, except per unit data):
			Year Ended December 31,
			2013			2012			2011
	Net income (loss)		$	12,994		$	(70,622	)	$	96,343
	Noncontrolling interest net loss			—			—			664
	Net income (loss) attributable to PVR Partners, L.P.		$	12,994		$	(70,622	)	$	97,007
	Less:
	Distributions to participating securities			(51,961	)		(29,716	)		(410	)
	Recognition of beneficial conversion feature (1)			(70,009	)		(45,967	)		—
	Participating securities’ allocable share of undistributed net loss (income)			26,619			23,102			(300	)
	Net income (loss) allocable to common units, basic and diluted		$	(82,357	)	$	(123,203	)	$	96,297
	Weighted average number of common units outstanding, basic and diluted			99,304			86,222			66,342
	Net income (loss) per common unit, basic and diluted		$	(0.83	)	$	(1.43	)	$	1.45
	-1	Special Units and Class B Units were issued at prices below the market price of the common units into which they are convertible. The aggregate discount of $139.2 million represents a beneficial conversion feature which is considered a non-cash distribution that will be distributed ratably using the effective yield method over the period the Special Units and Class B Units are outstanding. The impact of the beneficial conversion feature is included as distributed income to Class B Units and Special Units with a corresponding reduction in net income allocable to common units in the calculation of net income (loss) per common unit for the years ended December 31, 2013 and 2012.
Weighted Average Number of Each Class of Participating Securities Excluded from Diluted Net Income (Loss) Per Common Unit	'
	The following table presents the weighted average number of each class of participating securities that were excluded from the diluted net income (loss) per common unit calculation because the inclusion of these units would have had an antidilutive effect:
			2013			2012			2011
	Special units			8,787			6,473			—
	Class B units			23,372			13,630			—
	Phantom units			78			63			37
				32,237			20,166			37

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions - Statement of Operations	'
		Year Ended December 31,
		2013			2012
	Consolidated Statements of Operations:
	Other income	$	648		$	3,150
	General and administrative	$	43		$	26
Related Party Transactions - Balance Sheets	'
	December 31,			December 31,
	2013			2012
	Consolidated Balance Sheets:
	Accounts receivable	$	5,281		$	6,442
	Accounts payable	$	—		$	172

UnitBased_Payments_Tables

Unit-Based Payments (Tables)	12 Months Ended
	Dec. 31, 2013
Components of Recognized Expenses	'
	In connection with the normal three-year vesting of phantom and restricted units, as well as common unit and deferred common unit awards, we recognized the following expenses during the periods presented:
		2013			2012			2011
	Phantom units	$	3,533		$	3,848		$	3,025
	Director deferred and common units		626			579			820
		$	4,159		$	4,427		$	3,845
Summary of Deferred Common Unit Activity	'
	The following is a summary of deferred common unit activity for the periods presented:
		Number of			Weighted Average
		Deferred			Grant-Date Fair
		Common Units			Value
	Balance at January 1, 2011		126,582		$	21.62
	Granted and vested		113,400		$	26.99
	Converted to common units		(2,839	)	$	18.16
	Balance at December 31, 2011		237,143		$	24.23
	Granted and vested		28,167		$	24.21
	Converted to common units		(41,007	)	$	23.26
	Balance at December 31, 2012		224,303		$	24.4
	Granted and vested		23,401		$	24.88
	Converted to common units		(2,000	)	$	17.53
	Balance at December 31, 2013		245,704		$	24.5
Schedule of Expected Life of Phantom Units	'
	We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the phantom units, continuously compounded.
		2013			2012			2011
	Expected volatility		28.2	%		34.03	%		54.53	%
	Expected life		2.7 years			2.9 years			2.6 years
	Risk-free interest rate		0.31	%		0.4	%		0.83	%
Summary of Nonvested Time-Based Phantom Units	'
	The following table summarizes the status of our nonvested phantom units as of December 31, 2013 and changes during the year then ended:
		Nonvested			Weighted
		Phantom			Average
		Units			Grant-Date
					Fair Value
	Nonvested at January 1, 2013		414,390		$	16.27
	Granted		287,703		$	23.19
	Vested		(114,134	)	$	25.76
	Forfeited		(40,724	)	$	18.2
	Cancellation		(88,476	)	$	6.29
	Reissuance		88,476		$	24.67
	Nonvested at December 31, 2013		547,235		$	20.75

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Minimum Rental Commitments Under Operating Leases	'
	The following table sets forth our minimum rental commitments for the next five years under all non-cancelable operating leases in effect at December 31, 2013:
		Minimum Rental
	Year	Commitments
	2014	$	6,385
	2015		5,143
	2016		3,852
	2017		2,973
	2018		1,159
	Thereafter		4,788
	Total minimum payments	$	24,300
Disclosure of Obligation for Firm Transportation Commitments	'
	The following table sets forth our obligation for firm transportation commitments in effect at December 31, 2013 for the next five years and thereafter:
	Year	Firm
		Transportation
		Commitments
	2014	$	10,332
	2015		1,759
	2016		—
	2017		—
	2018		—
	Thereafter		—
	Total firm transportation commitments	$	12,091

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Segments Financial Information	'
	The following table presents a summary of certain financial information relating to our segments as of and for the years ended December 31, 2013, 2012 and 2011:
			Eastern		Midcontinent			Coal and		Consolidated
			Midstream (1)		Midstream (2)			Natural
								Resource
								Management (3)
	Year Ended December 31, 2013
	Revenues		$	200,217	$	807,165		$	110,104	$	1,117,486
	Cost of midstream gas purchased			—		666,239			—		666,239
	Operating costs and expenses			30,990		64,241			27,254		122,485
	Merger and acquisition costs			2,713		2,713			2,712		8,138
	Depreciation, depletion & amortization			97,973		61,809			28,159		187,941
	Operating income		$	68,541	$	12,163		$	51,979	$	132,683
	Interest expense										(106,248	)
	Loss on extinguishment of debt										(13,703	)
	Derivatives										(1,070	)
	Other										1,332
	Net income									$	12,994
	Additions to property and equipment		$	338,296	$	74,991		$	2,498	$	415,785
	Year Ended December 31, 2012
	Revenues		$	99,350	$	771,723		$	136,681	$	1,007,754
	Cost of midstream gas purchased			—		630,345			—		630,345
	Operating costs and expenses			17,186		66,618			31,964		115,768
	Merger and acquisition costs			14,049		—			—		14,049
	Impairments			—		124,845			—		124,845
	Depreciation, depletion & amortization			42,713		51,829			32,802		127,344
	Operating income (loss)		$	25,402	$	(101,914	)	$	71,915	$	(4,597	)
	Interest expense										(68,773	)
	Derivatives										2,291
	Other										457
	Net income (loss)									$	(70,622	)
	Additions to property and equipment		$	1,224,722	$	136,775		$	1,034	$	1,362,531
	Year Ended December 31, 2011
	Revenues		$	26,170	$	944,852		$	188,953	$	1,159,975
	Cost of midstream gas purchased			—		817,937			—		817,937
	Operating costs and expenses			2,737		60,505			35,849		99,091
	Depreciation, depletion & amortization			4,243		47,956			37,177		89,376
	Operating income		$	19,190	$	18,454		$	115,927	$	153,571
	Interest expense										(44,287	)
	Derivatives										(13,442	)
	Other										501
	Net income									$	96,343
	Additions to property and equipment		$	120,310	$	121,789		$	134,503	$	376,602
			Total assets at December 31,
			2013		2012			2011
	Eastern Midstream (4)		$	1,893,483	$	1,677,846		$	174,444
	Midcontinent Midstream (5)			594,999		640,437			736,351
	Coal and Natural Resource Management (6)			637,188		680,426			683,197
	Totals		$	3,125,670	$	2,998,709		$	1,593,992
	-1	Our Eastern Midstream segment’s revenues for the years ended December 31, 2013 and 2012 include $(2.2) million and $2.0 million of equity earnings (loss) related to our 51% interest in the Aqua-PVR joint venture. See Note 9, “Equity Investments” for a further description.
	-2	Our Midcontinent Midstream segment’s revenues for the years ended December 31, 2013, 2012 and 2011 include $15.2 million, $(7.6) million and $2.5 million of equity earnings (loss) related to our 25% membership interest in Thunder Creek. The 2013 revenue includes the gain on sale of the Thunder Creek equity investment. The loss in 2012 relates to an impairment charge of $8.7 million. See Note 9, “Equity Investments” for a further description of this segment’s equity investment.
	-3	Our Coal and Natural Resource Management segment’s revenues for the years ended December 31, 2013, 2012 and 2011 include $1.4 million, $2.8 million and $2.3 million of equity earnings related to our 50% interest in Coal Handling Solutions LLC. See Note 9, “Equity Investments” for a further description.
	-4	Total assets at December 31, 2013, 2012 and 2011 for the Eastern Midstream segment included equity contributions of $15.3 million, $35.7 million and $5.3 million related to our 51% interest in the Aqua-PVR joint venture. The equity investment at December 31, 2013, 2012 and 2011 for the Aqua-PVR joint venture was $47.2 million, $36.8 million and $5.3 million. See Note 9, “Equity Investments” for a further description.
	-5	The equity investment in our 25% membership interest in Thunder Creek was sold in August 2013 and had a carrying value of $44.3 million. Total assets at December 31, 2012 and 2011 for the Midcontinent Midstream segment included equity investment of $45.2 million and $53.1 million related to Thunder Creek. See Note 9, “Equity Investments” for a further description.
	-6	Total assets at December 31, 2013, 2012 and 2011 for the Coal and Natural Resource Management segment included equity investment of $13.6 million, $15.6 million and $16.3 million related to our 50% interest in Coal Handling Solutions LLC. See Note 9, “Equity Investments” for a further description.

Supplemental_Quarterly_Financi1

Supplemental Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Quarterly Financial Information (Unaudited)	'
	Supplemental Quarterly Financial Information (Unaudited, in thousands except per unit data)
			First			Second			Third			Fourth
			Quarter			Quarter			Quarter			Quarter
	2013
	Revenues (1)		$	263,411		$	273,465		$	288,964		$	291,646
	Operating income (1)		$	31,262		$	29,956		$	47,099		$	24,366
	Net income (loss)		$	7,237		$	5,508		$	17,888		$	(17,639	)
	Basic net income (loss) per limited partner unit (2)		$	(0.17	)	$	(0.21	)	$	(0.09	)	$	(0.35	)
	Diluted net income (loss) per limited partner unit (2)		$	(0.17	)	$	(0.21	)	$	(0.09	)	$	(0.37	)
	Weighted average number of units outstanding, basic			95,906			95,947			96,983			108,268
	Weighted average number of units outstanding, diluted			95,906			95,947			96,983			112,429
	2012
	Revenues (3)		$	246,417		$	222,912		$	268,847		$	269,578
	Operating income (loss) (3)		$	(95,692	)	$	14,535		$	60,491		$	16,069
	Net income (loss)		$	(110,344	)	$	7,809		$	38,783		$	(6,870	)
	Basic and diluted net income (loss) per limited partner unit (2)		$	(1.39	)	$	(0.07	)	$	0.16		$	(0.30	)
	Weighted average number of units outstanding, basic			79,301			83,786			88,366			93,333
	Weighted average number of units outstanding, diluted			79,340			83,786			88,366			93,333
	-1	Revenues and operating income in the third quarter of 2013 includes the $14.3 million gain on sale of our 25% equity investment in Thunder Creek.
	-2	Certain participating securities with beneficial conversion features were issued in conjunction with the Chief Acquisition. These participating securities and the effects of the beneficial conversion features have impacted the earnings (loss) per unit calculation. The sum of the quarters may not equal the total of the respective year’s net income (loss) per limited partner unit due to applying the two-class method of calculating net income (loss) per limited partner unit.
	-3	Operating income (loss) in the first quarter of 2012 includes the $124.8 million impairment of the North Texas Gathering System. Revenues and operating income for the fourth quarter of 2012 includes the $8.7 million impairment of our 25% equity investment in Thunder Creek.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2011
	Segment
Organization and Nature of Operations [Line Items]	'	'
Number of operating business segments	3	'
Portion of unit received by PVG's unitholders for each common unit owned	'	0.98
Aggregate common units received by PVG's unitholders for all outstanding common units owned	'	38,300,000
General partner interest	'	2.00%
Common units cancelled	'	19,600,000
Regency Energy Partners LP	'	'
Organization and Nature of Operations [Line Items]	'	'
Merher agreement termination fees	134.5	'
Merger related cost	8.1	'
Regency Energy Partners LP | Maximum	'	'
Organization and Nature of Operations [Line Items]	'	'
Merger related cost	20	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2011
Summary Of Significant Accounting Policies [Line Items]	'	'
Original maturity threshold for cash equivalent consideration	'three months	'
Amortization over the life of contracts	'26 years	'
Contracts acquired useful life	'14 years	'
Number of days to collect midstream revenues	30	'
Approximate number of days before receipt of coal production information	30	'
Total reclassification from accumulated other comprehensive income to earnings related to IRS	0.7	'
Total Seven Customers For Natural Gas Midstream Segments | Consolidated revenues	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Concentration risk percentage	51.00%	'
Total Seven Customers For Natural Gas Midstream Segments | Consolidated accounts receivable	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Concentration risk percentage	51.00%	'
Total Three Customer For Natural Gas Eastern Midstream Segment | Consolidated revenues	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Concentration risk percentage	55.00%	'
Total Three Customer For Natural Gas Eastern Midstream Segment | Consolidated accounts receivable	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Concentration risk percentage	54.00%	'
Total Four Customers For Natural Gas Midcontinent Midstream Segment | Consolidated revenues	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Concentration risk percentage	57.00%	40.00%
Total Four Customers For Natural Gas Midcontinent Midstream Segment | Consolidated accounts receivable	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Concentration risk percentage	54.00%	'
Midcontinent Midstream Segment	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'
Allowance for doubtful accounts	0.3	'

Estimated_Useful_Life_of_Prope

Estimated Useful Life of Property, Plant and Equipment (Detail)	12 Months Ended
	Dec. 31, 2013
Gathering systems | Minimum	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'7 years
Gathering systems | Maximum	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'20 years
Compressor stations | Minimum	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'3 years
Compressor stations | Maximum	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'15 years
Processing plants	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'15 years
Other property and equipment | Minimum	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'3 years
Other property and equipment | Maximum	'
Summary Of Significant Accounting Policies [Line Items]	'
Estimated useful life of asset	'20 years

Impairment_Additional_Informat

Impairment - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2012
Asset Impairment And Closure Costs [Line Items]	'	'
Impairment charge related to tangible and intangible natural gas gathering assets	$124,800	$124,845

Disposition_Additional_Informa

Disposition - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended		0 Months Ended	3 Months Ended		1 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Aug. 19, 2013	Sep. 30, 2013	Dec. 31, 2012	Jul. 03, 2012	Jul. 03, 2012
				Thunder Creek Gas Services LLC	Thunder Creek Gas Services LLC	Thunder Creek Gas Services LLC	Crossroads Natural Gas Gathering System	Crossroads Natural Gas Gathering System
							mi	Natural Gas Liquids
							MMcf	mi
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'
Membership interest ownership percentage	'	'	'	25.00%	'	25.00%	'	'
Amount of equity investment sold, net	'	'	'	$44,300,000	'	'	'	'
Proceeds from sale of equity investment	'	'	'	58,600,000	'	'	'	'
Gain from sale of equity investment	'	14,300,000	'	14,300,000	14,300,000	'	'	'
Assets held for sale	'	'	11,450,000	'	'	'	'	'
Progress payments on a Midcontinent Midstream plant sold	12,000,000	70,592,000	62,271,000	'	'	'	'	'
Gain on sales of project	500,000	'	'	'	'	'	'	'
Sale of Crossroads natural gas	'	'	'	'	'	'	62,300,000	'
Gas pipeline	'	'	'	'	'	'	8	20
Cryogenic processing plant capacity	'	'	'	'	'	'	80	'
Ownership in an approximately 11-mile gas pipeline	'	'	'	'	'	'	50.00%	'
Length of gas pipeline	'	'	'	'	'	'	11	'
Gain on sale of property plant and equipment	'	'	'	'	'	'	$31,300,000	'

Acquisition_Additional_Informa

Acquisition - Additional Information (Detail) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

31-May-13

Dec. 31, 2013

Dec. 31, 2012

31-May-12

17-May-12

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

31-May-12

31-May-12

17-May-12

17-May-12

Senior notes 8.375%

Chief Gathering LLC

Chief Gathering LLC

Chief Gathering LLC

Chief Gathering LLC

Chief Gathering LLC

Chief Gathering LLC

Chief Gathering LLC

Chief Gathering LLC

Customer Contracts And Relationships

Customer Contracts And Relationships

Class B Units

Common Units

Natural gas gathering systems

Natural gas gathering systems

Minimum

Maximum

Property

Minimum

acre

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Business acquisition purchase price

'

$2,400,000

'

'

$1,040,564,000

'

'

'

'

'

'

'

Cash consideration paid for Chief Gathering

'

'

'

'

849,262,000

'

'

'

'

'

'

'

Special units issued as consideration to Chief E&D Holdings LP

'

'

'

'

191,302,000

'

'

'

'

'

'

'

Natural gas gathering systems acquired

'

'

'

'

'

'

'

'

'

'

6

'

Number of acres within which gas gathering system operates

'

'

'

'

'

'

'

'

'

'

'

300,000

Cash received from sale of partnership units

'

'

'

'

'

'

'

'

400,000,000

180,000,000

'

'

Cash received from issuance of senior notes in a private placement

391,000,000

400,000,000

600,000,000

600,000,000

'

'

'

'

'

'

'

'

Estimated weighted-average amortization period

'

'14 years

'

'

'

'

'13 years

'26 years

'

'

'

'

Business combination, purchase price allocation, goodwill

'

70,283,000

70,283,000

'

70,283,000

'

'

'

'

'

'

'

Merger and acquisition related costs

'

$8,138,000

$14,049,000

'

'

$14,000,000

'

'

'

'

'

'

Allocation_of_Purchase_Price_A

Allocation of Purchase Price Allocation of Chief Acquisition (Detail) (USD $)	12 Months Ended		0 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	17-May-12	Dec. 31, 2013
			Chief Gathering LLC	Chief Gathering LLC
Business Acquisition [Line Items]	'	'	'	'
Cash consideration paid for Chief	'	'	$849,262	'
Special units issued as consideration to Chief	'	'	191,302	'
Total purchase price	2,400	'	1,040,564	'
Accounts receivable	'	'	4,412	'
Property, plant and equipment	'	'	376,953	'
Intangible assets	'	'	622,000	622,000
Goodwill	70,283	70,283	70,283	'
Other long-term assets	'	'	415	'
Accounts payable	'	'	-33,499	'
Total purchase price	'	'	$1,040,564	'

Pro_Forma_Financial_Informatio

Pro Forma Financial Information of Chief Acquisition (Detail) (Chief Gathering LLC, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Chief Gathering LLC	'	'
Business Acquisition [Line Items]	'	'
Revenues	$1,021,297	$1,182,381
Net income (loss) attributable to PVR	($82,696)	$19,060
Net income (loss) per limited partner unit, basic and diluted	($1.84)	($0.87)

Fair_Value_Measurement_Additio

Fair Value Measurement - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended		3 Months Ended		0 Months Ended
	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Aug. 19, 2013	17-May-12
				Thunder Creek Gas Services LLC	Thunder Creek Gas Services LLC	Chief Gathering LLC
Fair Value Measurements [Line Items]	'	'	'	'	'	'
Fair value of fixed-rate debt	'	$1,200,000,000	'	'	'	'
Business acquisition purchase price	'	2,400,000	'	'	'	1,040,564,000
Special units issued as consideration to Chief E&D Holdings LP	'	'	'	'	'	191,302,000
Assets fair value	5,700,000	'	'	'	'	'
Intangible assets fair value	0	'	'	0	'	'
Impairment charges	$124,800,000	'	$124,845,000	$8,700,000	'	'
Member interest ownership percentage	'	'	'	25.00%	25.00%	'

Fair_Value_Estimates_for_Non_F

Fair Value Estimates for Non Financial Assets and Liabilities Measured at Fair Value on Nonrecurring Basis (Detail) (Fair Value, Measurements, Nonrecurring, Chief Gathering LLC, USD $)	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	$1,040,564
Property, plant and equipment	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	376,953
Intangible Assets	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	622,000
Goodwill	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	70,283
Other long-term assets	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	415
Working Capital	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	-29,087
Fair Value, Inputs, Level 3	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	1,040,564
Fair Value, Inputs, Level 3 | Property, plant and equipment	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	376,953
Fair Value, Inputs, Level 3 | Intangible Assets	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	622,000
Fair Value, Inputs, Level 3 | Goodwill	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	70,283
Fair Value, Inputs, Level 3 | Other long-term assets	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	415
Fair Value, Inputs, Level 3 | Working Capital	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair value of assets and liabilities	($29,087)

Derivative_Instruments_Additio

Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
		Commodity Contract	Commodity Contract
Derivative [Line Items]	'	'	'
Notional amounts of interest rate swaps	$100	'	'
Payment of weighted average fixed rate on notional amount	2.09%	'	'
Swap interest rates, receive	'LIBOR	'	'
Percentage of open positions	50.00%	'	'
Amount reclassified out of AOCI relating to actual hedge settlements	0.7	'	'
Derivative liabilities	'	$0.50	$0.20

Effects_of_Derivative_Activiti

Effects of Derivative Activities and Location of Gains and Losses on Statement of Operations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative [Line Items]	'		'		'
Gain (loss) on derivatives recognized in income	($1,070)		$2,291		($13,442)
Not Designated as Hedging Instrument	'		'		'
Derivative [Line Items]	'		'		'
Gain (loss) on derivatives recognized in income	-1,070		2,291		-13,442
Unrealized derivative gain (losses)	'		12,785	[1]	12,246	[1]
Not Designated as Hedging Instrument | Derivatives	'		'		'
Derivative [Line Items]	'		'		'
Cash paid for commodity and interest rate contract settlements	-1,070	[2]	-10,494	[2]	-25,688	[2]
Not Designated as Hedging Instrument | Interest Rate Contract | Derivatives	'		'		'
Derivative [Line Items]	'		'		'
Gain (loss) on derivatives recognized in income	'		538		-851
Not Designated as Hedging Instrument | Commodity Contract | Derivatives	'		'		'
Derivative [Line Items]	'		'		'
Gain (loss) on derivatives recognized in income	($1,070)		$1,753		($12,591)
[1]	This activity represents unrealized gains in the natural gas midstream revenue, cost of midstream gas purchased, and interest expense. All amounts are reported in the derivatives line on our consolidated statements of operations.
[2]	As of December 31, 2013 and included in the settlement amounts is $0.5 million related to settled positions that were paid in January 2014. As of December 31, 2012 and included in the settlement amounts is a net $0.2 million related to settled positions that were paid in January 2013.

Effects_of_Derivative_Activiti1

Effects of Derivative Activities and Location of Gains and Losses on Statement of Operations (Parenthetical) (Detail) (USD $)	1 Months Ended
In Millions, unless otherwise specified	Jan. 31, 2013	Jan. 31, 2014
		Subsequent Event
Derivative [Line Items]	'	'
Net cash payments to settle derivatives	($0.20)	($0.50)

Summary_of_Property_Plant_and_

Summary of Property, Plant and Equipment (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	$2,837,217	$2,479,802
Accumulated depreciation, depletion and amortization	-647,939	-490,456
Net property, plant and equipment	2,189,278	1,989,346
Gathering systems	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	1,298,570	984,986
Compressor stations	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	361,872	283,189
Processing plants	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	130,527	116,942
Other property and equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	24,757	17,484
Construction in Progress	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	194,559	252,635
Coal Properties	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	636,933	634,555
Timber Properties	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	88,447	88,447
Oil And Gas Royalties	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	39,981	39,981
Coal Services Equipment	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	35,409	35,409
Land	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	$26,162	$26,174

Property_Plant_and_Equipment_A

Property Plant and Equipment - Additional Information (Detail) (USD $)	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]	'
Assets held for sale	$11,450

Equity_Investments_Additional_

Equity Investments - Additional Information (Detail) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jul. 03, 2012

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Aug. 19, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Contracts And Customer Relationships

Crossroads Natural Gas Gathering System

Crossroads Natural Gas Gathering System

Crossroads Natural Gas Gathering System

Coal Handling Solutions LLC

Aqua PVR Water Services LLC

Aqua PVR Water Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

mi

Schedule of Equity Method Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Member interest ownership percentage

'

'

'

'

'

'

'

'

50.00%

51.00%

'

25.00%

'

25.00%

'

25.00%

'

Contribution to the joint venture

'

$15,800,000

$37,200,000

$500,000

'

'

'

'

'

$15,300,000

$35,700,000

'

'

'

'

'

'

Amount of equity investment sold, net

'

'

'

'

'

6,200,000

'

'

'

'

'

44,300,000

'

'

'

'

'

Proceeds from sale of equity investment

'

'

'

'

'

'

'

'

'

'

'

58,600,000

'

'

'

'

'

Gain from sale of equity investment

'

14,300,000

'

'

'

'

'

'

'

'

'

14,300,000

14,300,000

'

'

'

'

Equity earnings

'

14,500,000

-2,500,000

5,500,000

'

'

300,000

700,000

'

'

'

'

'

'

1,000,000

1,100,000

2,500,000

Distributions

'

7,900,000

8,800,000

14,000,000

'

'

500,000

700,000

'

'

'

'

'

'

2,400,000

1,900,000

8,200,000

Impairment charges

124,800,000

'

124,845,000

'

'

'

'

'

'

'

'

'

'

8,700,000

'

'

'

Intangible assets fair value

0

'

'

'

'

'

'

'

'

'

'

'

'

0

'

0

'

Ownership in an approximately 11-mile gas pipeline

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

Length of gas pipeline

'

'

'

'

'

11

'

'

'

'

'

'

'

'

'

'

'

Equity investments

'

60,782,000

97,553,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Excess portion of underlying equity in net assets over equity investment

'

2,600,000

3,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contracts and customer relationships intangible asset estimated life,(in years)

'

'26 years

'

'

'14 years

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of equity investment

'

'

($8,700,000)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Summary_of_Financial_Informati

Summary of Financial Information of Unconsolidated Equity Investments (Detail) (USD $)	1 Months Ended
In Thousands, unless otherwise specified	Nov. 30, 2013	Nov. 30, 2012
Schedule of Equity Method Investments [Line Items]	'	'
Current assets	$22,256	$55,351
Noncurrent assets	113,378	273,158
Current liabilities	11,909	38,188
Noncurrent liabilities	1,682	3,933
Revenues	38,900	59,261
Expenses	35,619	38,463
Net income	$3,281	$20,798

Summary_of_Net_Intangible_Asse

Summary of Net Intangible Assets (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]	'	'
Total intangible assets	$662,052	$662,052
Accumulated amortization	-71,972	-41,452
Intangible assets, net	590,080	620,600
Contracts And Customer Relationships	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Total intangible assets	657,500	657,500
Other	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Total intangible assets	$4,552	$4,552

Intangible_Assets_Net_Addition

Intangible Assets, Net - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended					3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	17-May-12	Mar. 31, 2012	Dec. 31, 2013
					Chief Gathering LLC	Chief Gathering LLC	North Texas Gathering System	North Texas Gathering System
Finite-Lived Intangible Assets [Line Items]	'	'	'	'	'	'	'	'
Impaired Intangible Assets	'	'	'	'	'	'	'	$69,200,000
Intangible assets fair value	0	'	'	'	'	'	'	0
Net value of intangibles at time of the impairment	'	590,080,000	'	'	'	'	'	54,600,000
Accumulated amortization of intangible assets	'	71,972,000	41,452,000	'	'	'	'	14,600,000
Impairment charges	124,800,000	'	124,845,000	'	'	'	124,800,000	124,800,000
Intangible assets	'	'	'	'	622,000,000	622,000,000	'	'
Expected useful lives	'	'26 years	'	'	'	'	'	'
Total intangible amortization expense	'	$30,500,000	$17,500,000	$6,300,000	'	'	'	'

Summary_of_Estimated_Aggregate

Summary of Estimated Aggregate Amortization Expenses For Futures Years (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]	'
2014	$30,367
2015	30,254
2016	30,148
2017	30,071
2018	29,970
Thereafter	439,270
Total	$590,080

Aggregate_Carrying_amount_of_A

Aggregate Carrying amount of Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Changes in Asset Retirement Obligations [Line Items]	'	'
Balance at beginning of period	$2,526	$2,343
Liabilities incurred	'	'
Accretion expense	196	183
Revision of estimate	'	'
Balance at end of period	$2,722	$2,526

Summary_of_Long_Term_Debt_Deta

Summary of Long Term Debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Senior notes	$1,172,600	$900,000
Total debt	1,735,100	1,490,000
Less: Current maturities	'	'
Total long-term debt	1,735,100	1,490,000
Line of Credit	'	'
Debt Instrument [Line Items]	'	'
Revolver - variable rate of 3.2% at December 31, 2013 and 2012	562,500	590,000
Senior Notes 8.25% Due April 15 2018	'	'
Debt Instrument [Line Items]	'	'
Senior notes	300,000	300,000
Senior Notes 8.375% Due June 1 2020	'	'
Debt Instrument [Line Items]	'	'
Senior notes	472,600	600,000
Senior Notes 6.5% Due May 15 2021	'	'
Debt Instrument [Line Items]	'	'
Senior notes	$400,000	'

Summary_of_Long_Term_Debt_Pare

Summary of Long Term Debt (Parenthetical) (Detail)	1 Months Ended			12 Months Ended
	31-May-13	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
		Line of Credit	Line of Credit	Senior Notes 8.25% Due April 15 2018	Senior Notes 8.375% Due June 1 2020	Senior Notes 6.5% Due May 15 2021
Debt Instrument [Line Items]	'	'	'	'	'	'
Variable rate	'	3.20%	3.20%	'	'	'
Debt interest rate	6.50%	'	'	8.25%	8.38%	6.50%
Debt maturity date	15-May-21	'	'	15-Apr-18	1-Jun-20	15-May-21

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

31-May-13

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Dec. 31, 2013

Feb. 28, 2014

Dec. 31, 2013

31-May-12

31-May-12

Apr. 30, 2010

Revolver

Maximum

Maximum

Maximum

Maximum

Subsequent Event

Senior notes 8.375%

Senior notes 8.375%

Senior notes 8.375%

Senior notes 8.250%

Fiscal period ended June 30, 2012 through the fiscal period ended December 31, 2012

Fiscal period ended March 31, 2013 through the fiscal period ended June 30, 2013

Fiscal period ending September 30, 2013 through the fiscal period ending December 31, 2013

Maximum

Chief Gathering LLC

Fiscal period ending March 31, 2014, and for each fiscal period thereafter

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capitalized interest costs

'

$12,800,000

$14,100,000

'

'

'

'

'

'

'

'

'

'

'

Leverage Ratio

'

'

'

'

'

5.27%

6.50%

5.75%

5.50%

5.25%

'

'

'

'

Debt maturity date

15-May-21

'

'

'

19-Apr-16

'

'

'

'

'

'

1-Jun-20

'

15-Apr-18

Minimum adjusted EBITDA allowed for material capital projects

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Indebtedness outstanding

'

562,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Letters of credit

'

10,700,000

'

'

'

'

'

'

'

'

'

'

'

'

Remaining borrowing capacity

'

426,800,000

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average interest rate on borrowings

'

3.30%

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes, face amount

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt interest rate

6.50%

'

'

'

'

'

'

'

'

'

'

8.38%

'

8.25%

Issuance of senior notes

391,000,000

400,000,000

600,000,000

'

'

'

'

'

'

'

'

600,000,000

'

'

Debt issuance costs

9,000,000

9,772,000

19,206,000

3,675,000

'

'

'

'

'

'

'

'

'

7,400,000

Repayments of borrowings

'

637,500,000

525,000,000

212,500,000

'

'

'

'

'

'

'

'

250,000,000

'

Debt redemption, amount

'

'

'

'

'

'

'

'

'

'

127,400,000

'

'

'

Principal amount of debt redeemed, percentage

'

'

'

'

'

'

'

'

'

'

108.38%

'

'

'

Debt redemption, charge

'

138,070,000

'

'

'

'

'

'

'

'

13,700,000

'

'

'

Senior notes

'

1,172,600,000

900,000,000

'

'

'

'

'

'

'

472,600,000

'

'

300,000,000

Senior notes yield to maturity percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

8.25%

Proceeds from sale of senior notes, net

'

'

'

'

'

'

'

'

'

'

'

'

'

$292,600,000

Percentage of finance subsidiaries owned

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of subsidiary guarantors owned

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

Future_Maturities_of_LongTerm_

Future Maturities of Long-Term Debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
2014	'	'
2015	'	'
2016	562,500	'
2017	'	'
2018	300,000	'
Thereafter	872,600	'
Total debt, including current maturities	$1,735,100	$1,490,000

PVR_Unit_Offerings_Additional_

PVR Unit Offerings - Additional Information (Detail) (USD $)

0 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

Oct. 31, 2013

Sep. 30, 2013

Aug. 31, 2013

Nov. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Aug. 31, 2013

Nov. 30, 2012

Dec. 31, 2011

Nov. 30, 2011

17-May-12

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

17-May-12

Regency Energy Partners LP

Maximum

Limited Partner

Limited Partner

Limited Partner

Class B Units

Class B Units

Class B Units

Class B Units

Class B Units

Class B Units

Class B Units

Class B Units

Special Units

Scenario 1

Scenario 1

Scenario 2

Scenario 2

Scenario 3

Scenario 3

Minimum

Minimum

Minimum

Limited partner's interest

6,100,000

6,100,000

'

'

'

'

'

'

'

7,500,000

8,050,000

8,050,000

'

'

'

'

'

'

'

'

'

Net proceeds from issuance of partner's capital

'

'

'

$165,700,000

$138,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost associated with issuance of partner's capital

'

'

'

'

2,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited partner interest units sold in private placement

'

'

'

'

9,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Limited partner interest sold in private placement

'

'

'

'

177,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net proceeds from issuance of partners' capital

'

'

'

'

138,044,000

743,448,000

189,164,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common units offering price

'

'

150,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Sales of common units shall not exceed gross sales price per common unit, percentage

'

'

'

'

'

'

'

'

2.00%

'

'

'

'

'

'

'

'

'

'

'

'

Business acquisition equity issuance value

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

'

'

191,300,000

Business acquisition equity issuance units

'

'

'

'

'

'

'

'

'

'

'

'

21,378,942

24,300,000

'

'

'

'

'

'

10,346,257

Distributed per common unit

'

'

'

'

'

'

'

'

'

'

'

'

$18.91

'

'

'

'

'

'

'

'

Class B unit outstanding percentage that may be converted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

50.00%

'

'

'

'

Volume-weighted average price trading days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'30 days

'

'30 days

'

'30 days

'

'

Class B unit conversion date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1-Jan-14

'

1-Apr-14

'

1-Jul-14

'

Weighted average price of common units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$30

'

$30

'

'

'

Amounts of Class B Units to be converted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$50,000,000

'

Number of common units received for each class B units issued and outstanding

'

'

'

'

'

'

'

1.02

'

'

'

'

'

'

'

'

'

'

'

'

'

Partners_Capital_and_Distribut2

Partners' Capital and Distributions - Additional Information (Detail) (USD $)	12 Months Ended				0 Months Ended	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	17-May-12	Dec. 31, 2013	Dec. 31, 2013
				Scenario, Forecast	Class B Units	Class B Units	Class B Units
				Unit Distribution			Scenario, Forecast
Units outstanding	112,200,000	'	'	'	'	'	24,305,507
Business acquisition equity issuance shares	'	'	'	'	21,378,942	24,300,000	'
Unit issued	'	'	'	'	'	'	505,576
Quarterly distribution to common unit holders, distribution date	'	'	'	13-Feb-14	'	'	28-Feb-14
Amount that would have been paid if Class B units entitled and accrue cash distribution	'	'	'	'	'	$13,400,000	'
Percentage of distributed of available cash	100.00%	'	'	'	'	'	'
Maximum period of cash distribution to limited partners	'45 days	'	'	'	'	'	'
Cash distributions during the period	$214,442,000	$176,256,000	$135,296,000	'	'	'	'
Quarterly payment of distribution per unit	'	'	'	$0.55	'	'	'
Quarterly distribution to common unitholders, record date	'	'	'	7-Feb-14	'	'	'

Reconciliation_of_Net_Income_L

Reconciliation of Net Income (Loss) and Weighted Average Units Used in Computing Basic and Diluted Net Income (Loss) Per Limited Partner Unit (Detail) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Net income (loss)

($17,639)

$17,888

$5,508

$7,237

($6,870)

$38,783

$7,809

($110,344)

$12,994

($70,622)

$96,343

Noncontrolling interest net loss

'

'

'

'

'

'

'

'

'

'

664

Net income (loss) attributable to PVR Partners, L.P.

'

'

'

'

'

'

'

'

12,994

-70,622

97,007

Distributions to participating securities

'

'

'

'

'

'

'

'

-51,961

-29,716

-410

Recognition of beneficial conversion feature

'

'

'

'

'

'

'

'

-70,009

[1]

-45,967

[1]

'

Participating securities' allocable share of undistributed net loss (income)

'

'

'

'

'

'

'

'

26,619

23,102

-300

Net income (loss) allocable to common units, basic and diluted

'

'

'

'

'

'

'

'

($82,357)

($123,203)

$96,297

Weighted average number of common units outstanding, basic and diluted

'

'

'

'

'

'

'

'

99,304

86,222

66,342

Net income (loss) per common unit, basic and diluted

'

'

'

'

'

'

'

'

($0.83)

($1.43)

$1.45

[1]

Special Units and Class B Units were issued at prices below the market price of the common units into which they are convertible. The aggregate discount of $139.2 million represents a beneficial conversion feature which is considered a non-cash distribution that will be distributed ratably using the effective yield method over the period the Special Units and Class B Units are outstanding. The impact of the beneficial conversion feature is included as distributed income to Class B Units and Special Units with a corresponding reduction in net income allocable to common units in the calculation of net income (loss) per common unit for the years ended December 31, 2013 and 2012.

Reconciliation_of_Net_Income_L1

Reconciliation of Net Income (Loss) and Weighted Average Units Used in Computing Basic and Diluted Net Income (Loss) Per Limited Partner Unit (Parenthetical) (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Non-cash distribution	$139.20

Weighted_Average_Number_of_Eac

Weighted Average Number of Each Class of Participating Securities Excluded from Diluted Net Income (Loss) Per Common Unit (Detail)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Weighted average units excluded from diluted net income per common unit calculation	32,237	20,166	37
Special Units	'	'	'
Weighted average units excluded from diluted net income per common unit calculation	8,787	6,473	'
Class B Units	'	'	'
Weighted average units excluded from diluted net income per common unit calculation	23,372	13,630	'
Phantom Units	'	'	'
Weighted average units excluded from diluted net income per common unit calculation	78	63	37

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (Aqua PVR Water Services LLC)	Dec. 31, 2013
Aqua PVR Water Services LLC	'
Related Party Transaction [Line Items]	'
Construction management services fee as percentage of construction costs of project	10.00%
Percentage of membership interest owned	51.00%

Related_Party_Transactions_Det

Related Party Transactions (Detail) (Aqua PVR Water Services LLC, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Aqua PVR Water Services LLC	'	'
Related Party Transaction [Line Items]	'	'
Other income	$648	$3,150
General and administrative	43	26
Accounts receivable	5,281	6,442
Accounts payable	'	$172

UnitBased_Payments_Additional_

Unit-Based Payments - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	Dec. 10, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Stock units vesting period	'	'3 years	'	'
Common units granted to employees, directors of general partner and employees of affiliated	'	3,000,000	'	'
Common units granted at a weighted average grant-date fair value	'	21,811	16,020	2,176
Amount of common units granted at a weighted average grant-date fair value	'	$25.24	$24.35	$25.23
Total unrecognized compensation cost related to nonvested phantom units	'	$5,600,000	'	'
Aggregate intrinsic value expected to vest	'	9,200,000	'	'
Weighted-average period of expected cost recognized	'	'2 years 4 months 24 days	'	'
Deferred Common Unit	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Number Of Deferred Common Units, Converted to common units	'	2,000	41,007	2,839
Aggregate intrinsic value of deferred common units converted to common units	'	'	$1,000,000	$100,000
Aggregate intrinsic value of vested deferred common units	'	6,000,000	'	'
Deferred Common Unit | Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Aggregate intrinsic value of deferred common units converted to common units	'	$100,000	'	'
Restricted Units	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Stock units vesting period	'	'3 years	'	'
Phantom Units	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Common units granted at a weighted average grant-date fair value	'	287,703	238,000	261,000
Amount of common units granted at a weighted average grant-date fair value	'	$23.19	$18.21	$21.32
Grant-date fair value of restricted units that vested	'	2,900,000	2,900,000	900,000
Phantom Units | Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Number of units vested	'	0.00%	'	'
Phantom Units | Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Number of units vested	'	200.00%	'	'
Time Based Phantom Units	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Common units granted at a weighted average grant-date fair value	'	186,000	125,000	155,000
Performance Based Phantom Units	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Common units granted at a weighted average grant-date fair value	88,000	102,000	113,000	106,000
Amount of common units granted at a weighted average grant-date fair value	'	$17.60	$5.85	$6.29
Employees affected by modification	14	'	'	'
Grant date fair value of modified award	'	$24.67	'	'
Performance Based Phantom Units | Change in Accounting Estimate	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Amount of common units granted at a weighted average grant-date fair value	'	$5.85	$10.92	'
Performance Based Phantom Units | Minimum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Amount of common units granted at a weighted average grant-date fair value	'	$6.29	'	'
Performance Based Phantom Units | Maximum	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Amount of common units granted at a weighted average grant-date fair value	'	$11.66	'	'

Components_of_Recognized_Expen

Components of Recognized Expenses (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Compensation Expense	$4,159	$4,427	$3,845
Phantom Units	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Compensation Expense	3,533	3,848	3,025
Director deferred and common units	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Compensation Expense	$626	$579	$820

Summary_of_Deferred_Common_Uni

Summary of Deferred Common Unit Activity (Detail) (Deferred Common Unit, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred Common Unit	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of Deferred Common Units, Beginning	224,303	237,143	126,582
Number of Deferred Common Units, Granted and vested	23,401	28,167	113,400
Number Of Deferred Common Units, Converted to common units	-2,000	-41,007	-2,839
Number of Deferred Common Units, Ending	245,704	224,303	237,143
Weighted Average Grant-Date Fair Value, Beginning	$24.40	$24.23	$21.62
Weighted Average Grant-Date Fair Value, Granted and vested	$24.88	$24.21	$26.99
Weighted Average Grant-Date Fair Value, Converted to common units	$17.53	$23.26	$18.16
Weighted Average Grant-Date Fair Value, Ending	$24.50	$24.40	$24.23

Schedule_of_Expected_Life_of_P

Schedule of Expected Life of Phantom Units (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Expected volatility	28.20%	34.03%	54.53%
Expected life	'2 years 8 months 12 days	'2 years 10 months 24 days	'2 years 7 months 6 days
Risk-free interest rate	0.31%	0.40%	0.83%

Summary_Of_Nonvested_Phantom_U

Summary Of Nonvested Phantom Units (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Nonvested Phantom Units, Granted	21,811	16,020	2,176
Weighted Average Grant-Date Fair Value, Granted	$25.24	$24.35	$25.23
Phantom Units	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Nonvested Phantom Units, Beginning	414,390	'	'
Nonvested Phantom Units, Granted	287,703	238,000	261,000
Nonvested Phantom Units, Vested	-114,134	'	'
Nonvested Phantom Units, Forfeited	-40,724	'	'
Nonvested Phantom Units, Cancellation	-88,476	'	'
Nonvested Phantom Units, Reissuance	88,476	'	'
Nonvested Phantom Units, Ending	547,235	414,390	'
Weighted Average Grant-Date Fair Value, Beginning	$16.27	'	'
Weighted Average Grant-Date Fair Value, Granted	$23.19	$18.21	$21.32
Weighted Average Grant-Date Fair Value, Vested	$25.76	'	'
Weighted Average Grant-Date Fair Value, Forfeited	$18.20	'	'
Weighted Average Grant-Date Fair Value, Cancellation	$6.29	'	'
Weighted Average Grant-Date Fair Value, Reissuance	$24.67	'	'
Weighted Average Grant-Date Fair Value, Ending	$20.75	$16.27	'

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Product Liability Contingency [Line Items]	'	'	'
Operating lease rental expense	$12.90	$13	$10.80
Environmental liabilities	$0.90	$0.90	'
Firm Transportation | Minimum	'	'	'
Product Liability Contingency [Line Items]	'	'	'
Term of contract for firm transportation capacity	'1 year	'	'
Firm Transportation | Maximum	'	'	'
Product Liability Contingency [Line Items]	'	'	'
Term of contract for firm transportation capacity	'5 years	'	'

Disclosure_of_Minimum_Rental_C

Disclosure of Minimum Rental Commitments Under Operating Leases (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitment And Contingencies [Line Items]	'
2014	$6,385
2015	5,143
2016	3,852
2017	2,973
2018	1,159
Thereafter	4,788
Total minimum payments	$24,300

Disclosure_of_Obligation_for_F

Disclosure of Obligation for Firm Transportation Commitments (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitment And Contingencies [Line Items]	'
2014	$10,332
2015	1,759
2016	'
2017	'
2018	'
Thereafter	'
Total firm transportation commitments	$12,091

Schedule_of_Segments_Financial

Schedule of Segments Financial Information (Detail) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

$291,646,000

[1]

$288,964,000

[1]

$273,465,000

[1]

$263,411,000

[1]

$269,578,000

[2]

$268,847,000

[2]

$222,912,000

[2]

$246,417,000

[2]

$1,117,486,000

$1,007,754,000

$1,159,975,000

Cost of midstream gas purchased

'

'

'

'

'

'

'

'

666,239,000

630,345,000

817,937,000

Operating costs and expenses

'

'

'

'

'

'

'

'

122,485,000

115,768,000

99,091,000

Merger and acquisition costs

'

'

'

'

'

'

'

'

8,138,000

14,049,000

'

Depreciation, depletion & amortization

'

'

'

'

'

'

'

'

187,941,000

127,344,000

89,376,000

Operating income (loss)

24,366,000

[1]

47,099,000

[1]

29,956,000

[1]

31,262,000

[1]

16,069,000

[2]

60,491,000

[2]

14,535,000

[2]

-95,692,000

[2]

132,683,000

-4,597,000

153,571,000

Interest expense

'

'

'

'

'

'

'

'

-106,248,000

-68,773,000

-44,287,000

Loss on extinguishment of debt

'

'

'

'

'

'

'

'

-13,703,000

'

'

Derivatives

'

'

'

'

'

'

'

'

-1,070,000

2,291,000

-13,442,000

Other

'

'

'

'

'

'

'

'

1,332,000

457,000

501,000

Net income (loss)

-17,639,000

17,888,000

5,508,000

7,237,000

-6,870,000

38,783,000

7,809,000

-110,344,000

12,994,000

-70,622,000

96,343,000

Additions to property and equipment

'

'

'

'

'

'

'

'

415,785,000

1,362,531,000

376,602,000

Impairments

'

'

'

'

'

'

'

124,800,000

'

124,845,000

'

Total assets

3,125,670,000

'

'

'

2,998,709,000

'

'

'

3,125,670,000

2,998,709,000

1,593,992,000

Aqua PVR Water Services LLC

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Equity assets

47,200,000

'

'

'

36,800,000

'

'

'

47,200,000

36,800,000

5,300,000

Eastern Midstream Segment | Aqua PVR Water Services LLC

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Equity assets

15,300,000

'

'

'

35,700,000

'

'

'

15,300,000

35,700,000

5,300,000

Operating Segments | Eastern Midstream Segment

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

200,217,000

[3]

99,350,000

[3]

26,170,000

[3]

Operating costs and expenses

'

'

'

'

'

'

'

'

30,990,000

[3]

17,186,000

[3]

2,737,000

[3]

Merger and acquisition costs

'

'

'

'

'

'

'

'

2,713,000

[3]

14,049,000

[3]

'

Depreciation, depletion & amortization

'

'

'

'

'

'

'

'

97,973,000

[3]

42,713,000

[3]

4,243,000

[3]

Operating income (loss)

'

'

'

'

'

'

'

'

68,541,000

[3]

25,402,000

[3]

19,190,000

[3]

Additions to property and equipment

'

'

'

'

'

'

'

'

338,296,000

[3]

1,224,722,000

[3]

120,310,000

[3]

Total assets

1,893,483,000

[4]

'

'

'

1,677,846,000

[4]

'

'

'

1,893,483,000

[4]

1,677,846,000

[4]

174,444,000

[4]

Operating Segments | Midcontinent Midstream Segment

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

807,165,000

[5]

771,723,000

[5]

944,852,000

[5]

Cost of midstream gas purchased

'

'

'

'

'

'

'

'

666,239,000

[5]

630,345,000

[5]

817,937,000

[5]

Operating costs and expenses

'

'

'

'

'

'

'

'

64,241,000

[5]

66,618,000

[5]

60,505,000

[5]

Merger and acquisition costs

'

'

'

'

'

'

'

'

2,713,000

[5]

'

'

Depreciation, depletion & amortization

'

'

'

'

'

'

'

'

61,809,000

[5]

51,829,000

[5]

47,956,000

[5]

Operating income (loss)

'

'

'

'

'

'

'

'

12,163,000

[5]

-101,914,000

[5]

18,454,000

[5]

Additions to property and equipment

'

'

'

'

'

'

'

'

74,991,000

[5]

136,775,000

[5]

121,789,000

[5]

Impairments

'

'

'

'

'

'

'

'

'

124,845,000

[5]

'

Total assets

594,999,000

[6]

'

'

'

640,437,000

[6]

'

'

'

594,999,000

[6]

640,437,000

[6]

736,351,000

[6]

Operating Segments | Coal And Natural Resource Management Segment

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

'

'

'

'

'

'

'

'

110,104,000

[7]

136,681,000

[7]

188,953,000

[7]

Operating costs and expenses

'

'

'

'

'

'

'

'

27,254,000

[7]

31,964,000

[7]

35,849,000

[7]

Merger and acquisition costs

'

'

'

'

'

'

'

'

2,712,000

[7]

'

'

Depreciation, depletion & amortization

'

'

'

'

'

'

'

'

28,159,000

[7]

32,802,000

[7]

37,177,000

[7]

Operating income (loss)

'

'

'

'

'

'

'

'

51,979,000

[7]

71,915,000

[7]

115,927,000

[7]

Additions to property and equipment

'

'

'

'

'

'

'

'

2,498,000

[7]

1,034,000

[7]

134,503,000

[7]

Total assets

$637,188,000

[8]

'

'

'

$680,426,000

[8]

'

'

'

$637,188,000

[8]

$680,426,000

[8]

$683,197,000

[8]

[1]

Revenues and operating income in the third quarter of 2013 includes the $14.3 million gain on sale of our 25% equity investment in Thunder Creek.

[2]

Operating income (loss) in the first quarter of 2012 includes the $124.8 million impairment of the North Texas Gathering System. Revenues and operating income for the fourth quarter of 2012 includes the $8.7 million impairment of our 25% equity investment in Thunder Creek.

[3]

Our Eastern Midstream segment's revenues for the years ended December 31, 2013 and 2012 include $(2.2) million and $2.0 million of equity earnings (loss) related to our 51% interest in the Aqua-PVR joint venture. See Note 9, "Equity Investments" for a further description.

[4]

Total assets at December 31, 2013, 2012 and 2011 for the Eastern Midstream segment included equity contributions of $15.3 million, $35.7 million and $5.3 million related to our 51% interest in the Aqua-PVR joint venture. The equity investment at December 31, 2013, 2012 and 2011 for the Aqua-PVR joint venture was $47.2 million, $36.8 million and $5.3 million. See Note 9, "Equity Investments" for a further description.

[5]

Our Midcontinent Midstream segment's revenues for the years ended December 31, 2013, 2012 and 2011 include $15.2 million, $(7.6) million and $2.5 million of equity earnings (loss) related to our 25% membership interest in Thunder Creek. The 2013 revenue includes the gain on sale of the Thunder Creek equity investment. The loss in 2012 relates to an impairment charge of $8.7 million. See Note 9, "Equity Investments" for a further description of this segment's equity investment.

[6]

The equity investment in our 25% membership interest in Thunder Creek was sold in August 2013 and had a carrying value of $44.3 million. Total assets at December 31, 2012 and 2011 for the Midcontinent Midstream segment included equity investment of $45.2 million and $53.1 million related to Thunder Creek. See Note 9, "Equity Investments" for a further description.

[7]

Our Coal and Natural Resource Management segment's revenues for the years ended December 31, 2013, 2012 and 2011 include $1.4 million, $2.8 million and $2.3 million of equity earnings related to our 50% interest in Coal Handling Solutions LLC. See Note 9, "Equity Investments" for a further description.

[8]

Total assets at December 31, 2013, 2012 and 2011 for the Coal and Natural Resource Management segment included equity investment of $13.6 million, $15.6 million and $16.3 million related to our 50% interest in Coal Handling Solutions LLC. See Note 9, "Equity Investments" for a further description.

Schedule_of_Segments_Financial1

Schedule of Segments Financial Information (Parenthetical) (Detail) (USD $)

3 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Aug. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Aqua PVR Water Services LLC

Aqua PVR Water Services LLC

Aqua PVR Water Services LLC

Aqua PVR Water Services LLC

Aqua PVR Water Services LLC

Aqua PVR Water Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Thunder Creek Gas Services LLC

Coal Handling Solutions LLC

Coal Handling Solutions LLC

Coal Handling Solutions LLC

Eastern Midstream Segment

Eastern Midstream Segment

Eastern Midstream Segment

Midcontinent Midstream Segment

Midcontinent Midstream Segment

Midcontinent Midstream Segment

Midcontinent Midstream Segment

Coal And Natural Resource Management Segment

Coal And Natural Resource Management Segment

Coal And Natural Resource Management Segment

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity earnings

'

$14,500,000

($2,500,000)

$5,500,000

'

'

'

($2,200,000)

$2,000,000

'

'

$1,000,000

$1,100,000

$2,500,000

'

$15,200,000

($7,600,000)

$2,500,000

'

$1,400,000

$2,800,000

$2,300,000

Equity ownership percentage

'

'

'

'

'

'

'

51.00%

51.00%

51.00%

25.00%

'

25.00%

'

25.00%

25.00%

25.00%

25.00%

'

50.00%

50.00%

50.00%

Impairment charges

124,800,000

'

124,845,000

'

'

'

'

'

'

'

8,700,000

'

'

'

'

'

8,700,000

'

'

'

'

'

Equity assets

'

'

'

'

$47,200,000

$36,800,000

$5,300,000

$15,300,000

$35,700,000

$5,300,000

'

'

'

'

'

'

$45,200,000

$53,100,000

$44,300,000

$13,600,000

$15,600,000

$16,300,000

Segment_Information_Additional

Segment Information - Additional Information (Detail)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Total Four Customers For Natural Gas Midstream Segment

Total Four Customers For Natural Gas Midstream Segment

Total One Customer For Natural Gas Easter Midstream Segment

Total One Customer For Natural Gas Easter Midstream Segment

Total Three Customers For Natural Gas Mid continent Midstream Segment

Total Three Customers For Natural Gas Mid continent Midstream Segment

Total Seven Customers For Natural Gas Midstream Segments

Total Seven Customers For Natural Gas Midstream Segments

Total Three Customer For Natural Gas Eastern Midstream Segment

Total Three Customer For Natural Gas Eastern Midstream Segment

Total Four Customers For Natural Gas Midcontinent Midstream Segment

Total Four Customers For Natural Gas Midcontinent Midstream Segment

Total Four Customers For Natural Gas Midcontinent Midstream Segment

Consolidated revenues

Consolidated accounts receivable

Consolidated revenues

Consolidated accounts receivable

Consolidated revenues

Consolidated accounts receivable

Consolidated revenues

Consolidated accounts receivable

Consolidated revenues

Consolidated accounts receivable

Consolidated revenues

Consolidated revenues

Consolidated accounts receivable

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Concentration risk percentage

37.00%

34.00%

47.00%

33.00%

42.00%

39.00%

51.00%

51.00%

55.00%

54.00%

57.00%

40.00%

54.00%

Supplemental_Quarterly_Financi2

Supplemental Quarterly Financial Information (Unaudited) (Detail) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Quarterly Financial Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenues

$291,646

[1]

$288,964

[1]

$273,465

[1]

$263,411

[1]

$269,578

[2]

$268,847

[2]

$222,912

[2]

$246,417

[2]

$1,117,486

$1,007,754

$1,159,975

Operating income (loss)

24,366

[1]

47,099

[1]

29,956

[1]

31,262

[1]

16,069

[2]

60,491

[2]

14,535

[2]

-95,692

[2]

132,683

-4,597

153,571

Net income (loss)

($17,639)

$17,888

$5,508

$7,237

($6,870)

$38,783

$7,809

($110,344)

$12,994

($70,622)

$96,343

Basic net income (loss) per limited partner unit

($0.35)

[3]

($0.09)

[3]

($0.21)

[3]

($0.17)

[3]

'

'

'

'

'

'

'

Basic and diluted net income per limited partner unit

'

'

'

'

($0.30)

[3]

$0.16

[3]

($0.07)

[3]

($1.39)

[3]

'

'

'

Diluted net income (loss) per limited partner unit

($0.37)

[3]

($0.09)

[3]

($0.21)

[3]

($0.17)

[3]

'

'

'

'

'

'

'

Weighted average number of units outstanding, basic

108,268

96,983

95,947

95,906

93,333

88,366

83,786

79,301

'

'

'

Weighted average number of units outstanding, diluted

112,429

96,983

95,947

95,906

93,333

88,366

83,786

79,340

'

'

'

[1]

Revenues and operating income in the third quarter of 2013 includes the $14.3 million gain on sale of our 25% equity investment in Thunder Creek.

[2]

Operating income (loss) in the first quarter of 2012 includes the $124.8 million impairment of the North Texas Gathering System. Revenues and operating income for the fourth quarter of 2012 includes the $8.7 million impairment of our 25% equity investment in Thunder Creek.

[3]

Certain participating securities with beneficial conversion features were issued in conjunction with the Chief Acquisition. These participating securities and the effects of the beneficial conversion features have impacted the earnings (loss) per unit calculation. The sum of the quarters may not equal the total of the respective year's net income (loss) per limited partner unit due to applying the two-class method of calculating net income (loss) per limited partner unit.

Supplemental_Quarterly_Financi3

Supplemental Quarterly Financial Information (Unaudited) (Parenthetical) (Detail) (USD $)	3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended	0 Months Ended	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2013	Aug. 19, 2013	Sep. 30, 2013	Dec. 31, 2012
				North Texas Gathering System	North Texas Gathering System	Thunder Creek Gas Services LLC	Thunder Creek Gas Services LLC	Thunder Creek Gas Services LLC
Quarterly Financial Information [Line Items]	'	'	'	'	'	'	'	'
Gain from sale of equity investment	'	$14,300,000	'	'	'	$14,300,000	$14,300,000	'
Impairment charges	$124,800,000	'	$124,845,000	$124,800,000	$124,800,000	'	'	$8,700,000
Equity ownership percentage	'	'	'	'	'	'	25.00%	25.00%